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, 1994
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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, 1995 the aggregate market value of the voting stock held by
nonaffiliates of the Registrant was $785,684,211.
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, 1995, 37,669,963.
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 18,
1995.
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 17
Item 3 Legal Proceedings 19
Item 4 Submission of Matters to a Vote of
Security Holders 19
Item 4-A Executive Officers of the Registrant 19
Part II
Item 5 Market for the Registrant's Common Equity
and Related Stockholder Matters 21
Item 6 Selected Financial Data 22
Item 7 Management's Discussion and Analysis of
Financial Condition and Results of Operations 25
Item 8 Financial Statements and Supplementary Data 49
Item 9 Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure 86
Part III
Item 10 Directors and Executive Officers of the
Registrant 87
Item 11 Executive Compensation 87
Item 12 Security Ownership of Certain Beneficial Owners
and Management 87
Item 13 Certain Relationships and Related Transactions 87
Part IV
Item 14 Exhibits, Financial Statement Schedules and
Reports on Form 8-K 88
Signatures 93
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 6
Electric Operations 7
Gas Operations 9
Fuel Supply
Nuclear 10
Coal 12
Oil 12
Environmental Quality Control 13
Research and Development 14
Operating Statistics 15
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,
1994 the Company had 2,075 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,
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, 1994.
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.
2
In each of the communities in which it renders service, the
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:
1994 1993 1992
----- ----- -----
Electric 67.4% 69.1% 70.8%
Gas 32.6% 30.9% 29.2%
----- ----- -----
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, 1994 was 5.28.
3
(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, 1994 the amount of additional First Mortgage
Bonds which could be issued on that basis was approximately
$356,674,000. 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,
1994, the Company could issue $194,334,000 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, 1994, the coverage ratio under
(b) above (the more restrictive provision) was 2.13.
At December 31, 1994 the Company had $51.6 million of short-term
debt outstanding consisting of $32.0 million of unsecured short-term
debt and $19.6 million of secured short-term debt.
The Company's Charter provides that unsecured debt may not exceed
15% of the Company's total capitalization (excluding unsecured debt).
At December 31, 1994, including the $32 million of unsecured debt
already outstanding, the Company was able to issue $69.5 million of
unsecured debt under this provision. The Company has unsecured
short-term credit facilities totaling $72 million.
The Company has a $90 million revolving credit agreement which
expires December 31,1997. 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, 1994, this provision
would not restrict borrowings under the revolving credit agreement.
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, 1995, are secured
by a lien on the Company's accounts receivable.
4
The Company has a $30 million credit agreement with a domestic
bank until May 31, 1995 to provide funds for the Company's transition
cost liability pursuant to Federal Energy Regulatory Commission Order
No. 636. Borrowings under this agreement, which are secured by the
Company's accounts receivable, totaled $18.7 million (recorded as a
deferred credit on the Balance Sheet) at December 31, 1994.
The Company's Charter does not contain any financial tests for
the issuance of preference or common stock.
The Company's securities ratings at December 31, 1994 were:
First
Mortgage Preferred
Bonds Stock
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Standard & Poor's Corporation BBB+ BBB
Moody's Investors Service Baa1 baa2
Duff & Phelps BBB+ BBB
The securities ratings set forth in the table are subject to revision
and/or withdrawal at any time by the respective rating organizations
and should not be considered a recommendation to buy, sell or hold
securities of the Company.
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.
5
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.
On December 19, 1994, the PSC instituted a proceeding to review
the Company's practices regarding acquisition of pipeline capacity,
the costs of capacity and the Company's recovery of those costs.
Pending conclusion of the proceeding, the PSC directed the Company to
recover FERC Order No. 636 transition costs over a five-year period
and all other unrecovered gas costs over 18 months. This proceeding
follows an announcement made by the Company last fall that it expected
purchased gas expense to be higher during the 1994-95 heating season.
See the Notes to Financial Statements, Note 10 under the heading "Gas
Cost Recovery" and Note 1 under the heading "Rates and Revenue" for
further information related to this proceeding and for information
related to the discontinuing of the weather normalization adjustment
from January-May 1995 and its estimated impact on 1995 earnings.
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,
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.
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
6
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.
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 resolved the Company's rate case proceedings initiated
in July 1992 and determines the Company's rates from July 1, 1993
through June 30, 1996. The 1993 Rate Agreement includes certain
incentive arrangements providing for both rewards and penalties. See
Item 7 - Management's Discussion and Analysis of Financial Condition
and Results of Operations under the heading "Regulatory Matters" for a
summary of recent PSC rate decisions, a summary of the 1993 Rate
Agreement and a discussion of the incentive arrangements including a
discussion of the risks and rewards available to the Company under the
1993 Rate Agreement.
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 approved by the
PSC in March 1994. This tariff allows 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 will
absorb 30 percent of any net revenues lost as a result of such
discounts through June 1996, while the remainder may be recovered from
other customers. The portion recoverable after June 1996 is expected
to be determined in a future Company rate proceeding. The Company has
negotiated long-term electric supply contracts with three of it's
large industrial and commercial electric customers at discounted
rates. It intends to pursue negotiations with other large customers
as the need and opportunity arise. The Company has not experienced
any customer loss due to competitive alternative arrangements.
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. The passage of the National Energy Policy Act of 1992
(Energy Act) has accelerated these competitive challenges by promoting
competition in the electric power industry at the wholesale level, and
ensuring that a new class of independent power producers established
under the Energy Act, as well as qualified facilities and other
electric utilities, can achieve access to utility-owned transmission
facilities upon payment of appropriate prices. Competition in the
Company's gas business was accelerated with the passage in April 1992
of the FERC's Order No. 636. In essence, FERC Order 636 requires
interstate natural gas companies to offer customers "unbundled", or
separately-priced sale and transportation services. The PSC has been
conducting proceedings to investigate various issues regarding the
emerging competitive environment
7
in the electric and gas business in New York State. See Item 7 -
Managements Discussion and Analysis of Financial Condition and
Results of Operations under the heading "Competition" for information
on the competitive challenges the Company faces in it's electric and
gas business and how it proposes to respond to those challenges.
ELECTRIC OPERATIONS
The total net generating capacity of the Company's electric
system is 1,225,000 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, 50,000 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-Quebec purchased through the Power Authority.
The Company's net peak load of 1,374,000 Kw occurred on July 21, 1994.
The percentages of electricity actually generated and purchased
for the years 1990-1994 are as follows:
1994 1993 1992 1991 1990
Sources of Generated Energy: ------ ------ ------ ------ ------
Nuclear 55.3% 57.6% 52.1% 53.8% 48.5%
Fossil-Coal 16.9 18.2 24.4 23.0 23.8
-Oil 1.2 1.3 2.9 3.3 6.4
Hydro and Other 2.7 2.6 3.5 2.1 3.2
----- ----- ----- ----- -----
Total Generated Net 76.1 79.7 82.9 82.2 81.9
Purchased 23.9 20.3 17.1 17.8 18.1
----- ----- ----- ----- -----
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 23%, 24% and 24%, for the years 1995,
1996 and 1997, 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. In terms of capacity these
comprise 38%, 12%, 21%, 7% and 16%, respectively, of the Company's
current electric generating system.
Nine Mile Two, a nuclear generating unit in Oswego County, New
York
8
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 Company has four licensed hydroelectric generating stations
with an aggregate capability of 47 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 is
currently participating in negotiations with the New York State
Department of Environmental Conservation (NYSDEC) and other parties to
receive favorable Water Quality Certifications from the NYSDEC. The
outcome of the process, as well as decisions on what environmental
conditions FERC will impose in new licenses for the stations, will
determine the content of state water quality certifications issued by
the NYSDEC. The United States Supreme Court earlier this year decided
a case brought by the State of Washington (Tacoma Case) which held
that the various States had broad authority to impose non-water
quality conditions in their certifications. The NYSDEC holds the view
that this is the governing law in the State of New York, and has
drafted new provisions accordingly. If the negotiations are
unsuccessful, the Company will resume it's litigation in a NYSDEC
administrative proceeding initially brought by the Company to
challenge the 1992 certifications. This is anticipated to happen in
the first quarter of 1995. 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
the stations 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.
9
Preparation for replacement of the two steam generators at the
Ginna Nuclear Plant began in 1993 and will continue until the
replacement in 1996. Steam generator fabrication is well underway.
All major components for the steam generators have been ordered and
most have been delivered. Major sub-assemblies are now being
fabricated. Engineering for the installation is underway and will be
completed well before the scheduled installation. Cost of the
replacement is estimated to be $115 million, about $40 million for the
steam generators, about $50 million for the installation and the
remainder for Company engineering, radiation protection, plant support
and other services. In 1994 the Company spent approximately $16
million for the replacement project. The installation contractor,
Bechtel Power Corporation, has established a presence at the Ginna
site and 1995 activities will include a number of in-containment
modifications during the normal refueling outage in preparation for
the 1996 replacement. Following the 1995 outage, support facilities
will be constructed in preparation for the spring 1996 replacement.
The gross and net book cost of the Ginna Plant as of December 31,
1994 are $484 million and $258 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 $30.0 million in 1995
and $48.5 million in 1996 for steam generator replacement as discussed
above) are estimated to be $47.8 million, $61.3 million and $6.5
million for the years 1995, 1996 and 1997, 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 5,625,000 Therms (one Therm is equivalent to 1,000,000
British Thermal Units). On January 19, 1994, the Company experienced
its maximum daily throughput of approximately 4,735,690 Therms.
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
10
conditions. The Company anticipates no problem with obtaining
reliable, 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 Supply and Costs -
Gas" for a discussion of that topic and "Capital Requirements and Gas
Operations" for a discussion of Empire.
The Company continues to provide new and additional gas service.
Of 235,313 residential gas spaceheating customers at December 31,
1994, 3,376 were added during 1994, and 30% of those were conversions
from other fuels.
Approximately 26% of the gas delivered to customers by the
Company during 1994 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 hexafluoride, (3) the
enrichment of the uranium hexafluoride, (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 1999/(3)/ 2000/(2)/
Conversion 1997/(4)/ 2000/(2)/
Enrichment (5) (5)
Fabrication 2001 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) A contract is in place with flexibility to supply from 20 to 80
percent of the annual Ginna uranium requirements. A second
contract is in place to supply about 20% of the annual
requirements for 1995. The remaining requirements are
uncommitted.
(4) Seventy percent of the conversion requirements have been procured
through 1997.
(5) Thirty years from 1984 or life of reactor, whichever is less.
See
11
the following discussion.
The Company has a contract with United States Enrichment
Corporation (USEC) formerly with the federal Department of Energy
(DOE) 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. For further information concerning this
contract see Item 8, Note 10 under the heading "Nuclear Fuel
Enrichment Services".
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:
1994 1993 1992 1991 1990
----- ----- ----- ----- -----
Ginna $.403 $.400 $.359 $.442 $.485
Nine Mile Two $.481 $.515 $.558 $.714 $.990
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 has completed a
conceptual study of alternatives to increase the capacity for the
interim storage of spent nuclear fuel at the Ginna Plant. The
preferred alternative, based on cost and safety criteria, is to
install high-capacity spent fuel racks in the existing area of the
spent fuel pool. The additional storage capacity, scheduled to be
implemented prior to September 2000, would allow interim storage of
all spent fuel discharged from the Ginna Plant through the end of it's
Operating License in the year 2009.
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 to be
$70.9 million at December 31, 1994. The Company is allowed by the
12
PSC to recover these costs in rates. The estimated fees are
classified as a long term liability and interest is accrued at
the three-month Treasury bill rate, adjusted quarterly. The Act also
requires the DOE to provide for the disposal of nuclear fuel
irradiated after April 6, 1983, for a charge of one mill ($.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
$163.0 million, and those for the Company's 14% share of Nine Mile Two
are estimated to be approximately $37.1 million (January 1994
dollars). Through December 31, 1994, the Company has accrued and
recovered in rates $70.1 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 Note 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
560,000 tons. In 1994 approximately 95% of its requirements were
purchased under contract and the balance on the open market. The
Company is meeting its requirements during early 1995 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 1.0 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:
1994 1993 1992 1991 1990
------ ------ ------ ------ ------
Per Ton $36.31 $37.27 $39.28 $41.95 $42.27
Per Million BTU $1.38 $1.42 $1.48 $1.61 $1.60
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
13
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 $2.9 million on a variety of projects and facility
additions during 1994.
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. The Company can
provide no assurance as to what disposal arrangements, if any, New
York will have in place. The State has not passed legislation that
would designate a site for the disposal of low level radioactive
waste. In 1990, then 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 extended it's interim storage capacity at the Ginna
Plant from December 31, 1995 through mid-1999. Efforts will be
pursued to extend storage capacity beyond 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
14
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
Ginna, Beebee, and Russell Stations, which were renewed in July, 1992,
February, 1994, and June 1994, respectively. These permits are each
effective for a period of five years. Consistent with these permits,
no significant changes to the wastewater discharge treatment systems
are currently required, nor anticipated.
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 $2.2 million for
the year 1995, $2.8 million for the year 1996 and $22.6 million for
the year 1997. 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 1994, 1993 and 1992 were $7.3 million, $8.3 million,
and $7.4 million 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.
15
Electric Department Statistics
Year Ended December 31 1994 1993 1992 1991 1990 1989
---- ---- ---- ---- ---- ----
Electric Revenue (000's)
Residential $ 243,593 $ 235,286 $ 220,866 $ 212,327 $ 197,612 $ 191,732
Commercial 206,910 196,456 184,815 181,561 165,445 155,076
Industrial 150,690 147,396 142,392 141,001 130,012 124,634
Other (Includes Unbilled Revenue) 56,955 59,817 60,194 54,041 58,861 71,654
---------- ---------- ---------- ---------- ---------- ----------
Electric revenue from our customers 658,148 638,955 608,267 588,930 551,930 543,096
Other electric utilities 16,605 16,361 25,541 28,612 42,465 38,028
---------- ---------- ---------- ---------- ---------- ----------
Total electric revenue 674,753 655,316 633,808 617,542 594,395 581,124
---------- ---------- ---------- ---------- ---------- ----------
Electric Expense (000's)
Fuel used in electric generation 44,961 45,871 48,376 65,105 76,420 75,873
Purchased electricity 37,002 31,563 29,706 27,683 34,264 39,645
Other operation 187,594 188,684 183,118 168,610 155,289 137,458
Maintenance 47,295 52,464 53,714 57,032 53,880 55,915
Depreciation and Amortization 75,211 72,326 73,213 72,746 67,302 65,287
Taxes - local, state and other 97,919 96,043 94,841 86,925 77,323 71,361
---------- ---------- ---------- ---------- ---------- ----------
Total electric expense 489,982 486,951 482,968 478,101 464,478 445,539
---------- ---------- ---------- ---------- ---------- ----------
Operating Income before
Federal Income Tax 184,771 168,365 150,840 139,441 129,917 135,585
Federal income tax 52,842 43,845 38,046 31,390 30,670 29,887
---------- ---------- ---------- ---------- ---------- ----------
Operating Income from
Electric Operations (000's) $ 131,929 $ 124,520 $ 112,794 $ 108,051 $ 99,247 $ 105,698
---------- ---------- ---------- ---------- ---------- ----------
Electric Operating Ratio % 47.0 48.6 49.7 51.6 53.8 53.2
Electric Sales - KWH (000's)
Residential 2,111,468 2,124,763 2,084,466 2,085,429 2,075,072 2,072,047
Commercial 2,032,811 1,987,490 1,937,950 1,928,730 1,897,583 1,832,521
Industrial 1,867,972 1,894,026 1,929,498 1,917,796 1,931,633 1,906,429
Other 516,775 505,341 503,330 507,765 490,077 491,905
---------- ---------- ---------- ---------- ---------- ----------
Total billed 6,529,026 6,511,620 6,455,244 6,439,720 6,394,365 6,302,902
Unbilled sales (8,739) (4,556) 742 7,657 (25,421) 33,406
---------- ---------- ---------- ---------- ---------- ----------
Total customer sales 6,520,287 6,507,064 6,455,986 6,447,377 6,368,944 6,336,308
Other electric utilities 1,021,733 743,588 1,062,738 1,034,370 1,316,379 1,255,282
---------- ---------- ---------- ---------- ---------- ----------
Total electric sales 7,542,020 7,250,652 7,518,724 7,481,747 7,685,323 7,591,590
---------- ---------- ---------- ---------- ---------- ----------
Electric Customers at December 31
Residential 304,494 302,219 300,344 298,440 296,110 293,418
Commercial 29,984 29,635 29,339 28,856 28,804 28,386
Industrial 1,361 1,382 1,386 1,388 1,428 1,422
Other 2,670 2,638 2,605 2,558 2,553 2,512
---------- ---------- ---------- ---------- ---------- ----------
Total electric customers 338,509 335,874 333,674 331,242 328,895 325,738
---------- ---------- ---------- ---------- ---------- ----------
Electricity Generated and
Purchased - KWH (000's)
Fossil 1,478,120 1,520,936 2,197,757 2,146,664 2,505,110 2,578,006
Nuclear 4,527,178 4,495,457 4,191,035 4,391,480 4,016,721 3,659,185
Hydro 218,129 199,239 278,318 174,239 244,539 175,085
Pumped storage 247,550 233,477 226,391 240,206 269,966 290,582
Less energy for pumping (371,383) (355,725) (344,245) (364,520) (405,966) (429,895)
Other 1,245 2,559 811 1,269 20,408 54,893
---------- ---------- ---------- ---------- ---------- ----------
Total generated - Net 6,100,839 6,095,943 6,550,067 6,589,338 6,650,778 6,327,856
Purchased 1,998,882 1,646,244 1,389,875 1,451,208 1,498,089 1,757,413
---------- ---------- ---------- ---------- ---------- ----------
Total electric energy 8,099,721 7,742,187 7,939,942 8,040,546 8,148,867 8,085,269
---------- ---------- ---------- ---------- ---------- ----------
System Net Capability -
KW at December 31
Fossil 532,000 541,000 541,000 541,000 541,000 541,000
Nuclear 617,000 620,000 617,000 622,000 621,000 621,000
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 375,000 347,000 348,000 354,000 356,000 369,000
---------- ---------- ---------- ---------- ---------- ----------
Total system net capability 1,600,000 1,584,000 1,582,000 1,593,000 1,594,000 1,607,000
---------- ---------- ---------- ---------- ---------- ----------
Net Peak Load - KW 1,374,000 1,333,000 1,252,000 1,297,000 1,208,000 1,249,000
Annual Load Factor - Net % 58.8 59.1 62.5 61.7 64.6 62.4
16
Gas Department Statistics
Year Ended December 31 1994 1993 1992 1991 1990 1989
---- ---- ---- ---- ---- ----
Gas Revenue (000's)
Residential $ 5,935 $ 5,526 $ 6,456 $ 6,354 $ 6,508 $ 6,770
Residential spaceheating 221,927 196,411 183,405 157,458 159,501 165,832
Commercial 50,318 45,620 44,274 40,196 43,534 46,897
Industrial 7,254 6,346 6,418 6,761 9,674 9,371
Municipal and other
(Includes Unbilled Revenue) 40,627 39,805 21,171 24,959 17,279 35,703
--------- --------- --------- --------- --------- ---------
Total gas revenue 326,061 293,708 261,724 235,728 236,496 264,573
--------- --------- --------- --------- --------- ---------
Gas Expense (000's)
Gas purchased for resale 194,390 166,884 141,291 129,779 132,512 152,623
Other operation 48,302 46,697 43,506 39,830 39,307 36,306
Maintenance 7,774 9,229 9,006 8,383 8,510 8,401
Depreciation 12,250 11,851 11,815 11,435 10,465 9,776
Taxes - local, state and other 31,859 30,849 29,411 26,724 23,711 23,980
--------- --------- --------- --------- --------- ---------
Total gas expense 294,575 265,510 235,029 216,151 214,505 231,086
--------- --------- --------- --------- --------- ---------
Operating Income before
Federal Income Tax 31,486 28,198 26,695 19,577 21,991 33,487
Federal income tax 8,403 5,485 5,545 2,869 3,820 7,952
--------- --------- --------- --------- --------- ---------
Operating Income from
Gas Operations (000's) $ 23,083 $ 22,713 $ 21,150 $ 16,708 $ 18,171 $ 25,535
--------- --------- --------- --------- --------- ---------
Gas Operating Ratio % 76.8 75.9 74.1 75.5 76.3 74.6
Gas Sales - Therms (000's)
Residential 6,533 6,735 8,780 9,068 9,644 10,321
Residential spaceheating 290,241 289,252 287,614 253,655 262,458 277,267
Commerical 74,647 77,326 78,993 71,509 77,617 84,152
Industrial 11,823 11,792 12,437 13,000 18,536 17,873
Municipal 10,500 11,947 11,410 10,580 13,350 12,319
--------- --------- --------- --------- --------- ---------
Total billed 393,744 397,052 399,234 357,812 381,605 401,932
Unbilled sales (10,110) 8,017 13 3,291 (22,840) 20,320
--------- --------- --------- --------- ---------- ---------
Total gas sales 383,634 405,069 399,247 361,103 358,765 422,252
Transportation of customer-owned gas 136,372 124,436 126,140 109,835 101,985 105,303
--------- --------- --------- --------- --------- ---------
Total gas sold and transported 520,006 529,505 525,387 470,938 460,750 527,555
--------- --------- --------- --------- --------- ---------
Gas Customers at December 31
Residential 17,836 18,389 19,114 21,448 22,410 23,321
Residential spaceheating 235,313 231,937 228,096 222,918 219,242 215,120
Commercial 18,742 18,636 18,378 18,151 17,920 17,677
Industrial 905 924 932 921 960 1,095
Municipal 988 1,001 1,010 983 984 1,067
Transportation 558 466 424 423 401 367
--------- --------- --------- --------- --------- ---------
Total gas customers 274,342 271,353 267,954 264,844 261,917 258,647
--------- --------- --------- --------- --------- ---------
Gas - Therms (000's)
Purchased for resale 262,267 347,778 360,493 384,643 366,684 426,941
Gas from storage 134,802 76,378 53,757 16,755 - -
Other 2,959 1,039 1,061 1,617 2,525 1,764
--------- --------- --------- --------- --------- ---------
Total gas available 400,028 425,195 415,311 403,015 369,209 428,705
--------- --------- --------- --------- --------- ---------
Cost of gas per therm (cents) 50.00c 36.79c 35.35c 32.96c 36.03c 35.74c
Total Daily Capacity -
Therms at December 31* 5,625,000 5,625,000 4,485,000 4,485,000 4,485,000 4,485,000
--------- --------- --------- --------- --------- ---------
Maximum daily throughput - Therms 4,735,690 3,864,850 3,768,470 3,539,260 3,539,820 3,719,050
Degree Days (Calendar Month)
For the period 6,699 7,044 6,981 6,146 5,924 7,109
Percent colder (warmer) than normal (0.6) 4.4 3.4 (8.4) (11.8) 5.9
* Method for determining daily capacity, based on current network analysis,
reflects the maximum demand which the transmission systems can accept
without a deficiency.
17
ITEM 2. PROPERTIES
ELECTRIC PROPERTIES
The net capability of the Company's electric generating
plants in operation as of December 31, 1994, the net generation of
each plant for the year ended December 31, 1994, 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 80 442,254
Beebee Station
(Gas Turbine) Oil 1969 14 404
Russell Station
(Steam) Coal 1949-1957 257 938,919
Ginna Station
(Steam) Nuclear 1970 470 3,361,488
Oswego Unit 6/(1)/
(Steam) Oil 1980 195 96,947
Nine Mile Point
Unit No. 2/(2)/
(Steam) Nuclear 1988 147 1,165,690
Station No. 9
(Gas Turbine) Gas 1969 15 841
Station 5
(Hydro) Water 1917 39 166,525
5 Other Stations
(Hydro) Water 1906-1960 8 51,604
---------
6,224,672
Pumped Storage/(3)/ 247,550
Less energy for
pumping (371,383)
----- ---------
1,225 6,100,839
===== =========
(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 147 distribution substations having an
aggregate rated transformer capacity of approximately 2,091,104 Kva,
of which 138, having an aggregate rated capacity of 1,911,938 Kva,
were located on lands owned in fee, and 9 of
18
which, having an aggregate rated capacity of 179,166 Kva, were located
on land under easements, leases or license agreements. The Company
also has 75,486 line transformers with a capacity of 2,973,933 Kva.
The Company also owns 24 transmission substations having an aggregate
rated capacity of approximately 3,052,017 Kva of which 23, having an
aggregate rated capacity of approximately 2,977,350 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 707 wire miles of overhead lines and 399
wire miles of underground lines. The distribution system consists of
approximately 16,181 wire miles of overhead lines, approximately 3,580
wire miles of underground lines and 345,988 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 4,172 miles of gas
mains and 284,006 installed meters. (See Item 1 - Business, "Gas
Operations".)
OTHER PROPERTIES
The Company owns a ten-story office building centrally
located in Rochester and other structures and property. The Company
also leases a 153,000 square foot Customer Service Center in
Rochester.
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.
19
ITEM 3. LEGAL PROCEEDINGS
See Item 8, Note 10 - Commitments and Other Matters and Item
7, under the heading entitled "Projected Capital and other
Requirements".
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, 1994.
ITEM 4-A. EXECUTIVE OFFICERS OF THE REGISTRANT
AGE POSITIONS, OFFICES AND BUSINESS
NAME 12/31/94 EXPERIENCE 1990 TO DATE
---- -------- -----------------------------------
Roger W. Kober 61 Chairman of the Board, President
and Chief Executive Officer - 1993
to date
President and Chief Executive
Officer - 1991
President and Chief Operating
Officer - 1990
David K. Laniak 59 Executive Vice President and Chief
Operating Officer - August, 1994
to Date
Senior Vice President, Gas,
Electric Distribution and Customer
Services - 1990 to August, 1994
Thomas S. Richards 51 Senior Vice President, Corporate
Services and General Counsel -
August, 1994 to Date
Senior Vice President, Finance and
General Counsel - October, 1993 to
August, 1994
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 57 Senior Vice President, Customer
Operations - August, 1994 to Date
Senior Vice President, Production
and Engineering - 1990 to
August, 1994
20
David C. Heiligman 54 Vice President, Finance and
Corporate Secretary - August 1994
to Date
Vice President, Secretary and
Treasurer 1990 to August, 1994
Robert C. Mecredy 49 Vice President, Nuclear
Operations - August, 1994 to Date
Vice President, Ginna Nuclear
Production - 1990 to August, 1994
Division Manager, Nuclear
Production - 1990
Wilfred J. Schrouder, Jr 53 Vice President, Customer
Development - August, 1994 to Date
Vice President, Employee Relations,
Public Affairs and Materials
Management - 1990 to August, 1994
Daniel J. Baier 48 Controller - August, 1994 to Date
Assistant Controller - 1990 to
August, 1994
Mark Keogh 49 Treasurer - August, 1994 to Date
Manager, Treasury Department - 1992
to August, 1994
Manager, Corporate Administration -
1990 to 1992
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.
21
PART II
ITEM 5 MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS
COMMON STOCK AND DIVIDENDS
- ----------------------------------------------- ---------------------------------------------
EARNINGS/DIVIDENDS 1994 1993 1992 SHARES/SHAREHOLDERS 1994 1993 1992
- ----------------------------------------------- ---------------------------------------------
Earnings per weighted Number of shares (000's)
average share $1.79 $2.00 $1.86 Weighted average 37,327 35,599 33,258
Dividends paid Actual number at
per share $1.76 $1.72 $1.68 December 31 37,670 36,911 34,797
- ----------------------------------------------- Number of shareholders
at December 31 37,212 38,102 39,017
--------------------------------------------
TAX STATUS OF CASH DIVIDENDS
Cash dividends paid in 1994, 1993 and 1992 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 Company believes that
future dividend payments will need to be evaluated in the context of maintaining
the financial strength necessary to operate in a more competitive and uncertain
business environment. This will require consideration, among other things, of a
dividend payout ratio that is lower over time, reevaluating assets and managing
greater fluctuation in revenues. While the Company does not presently expect
the impact of these factors to affect the Company's ability to pay the current
dividend, future dividends may be affected. 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 1995, the Company paid a cash
dividend of $.45 per share on its Common Stock, up $.01 from the prior quarterly
dividend payment of $.44. The January 1995 dividend payment is equivalent to
$1.80 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".
- --------------------------------------------------------------------------------------------------------
1994 1993 1992
- --------------------------------------------------------------------------------------------------------
Common Stock--Price Range
High
1st quarter 26 3/8 28 3/8 23 1/4
2nd quarter 25 1/8 28 24
3rd quarter 23 3/4 29 3/4 24 3/4
4th quarter 21 3/8 29 1/4 25 1/4
Low
1st quarter 23 3/8 24 1/8 20 7/8
2nd quarter 20 1/2 25 1/2 21 1/4
3rd quarter 19 3/4 27 3/8 22 3/4
4th quarter 20 1/8 24 3/4 23 1/8
At December 31 20 7/8 26 1/4 24 1/2
- --------------------------------------------------------------------------------------------------------
22
Item 6. Selected Financial Data
Consolidated Summary of Operations Year Ended December 31
(Thousands of Dollars) 1994 1993 1992 1991 1990 1989
- --------------------------------------------------------------------------------------------------------------------------------
Operating Revenues
Electric $ 658,148 $ 638,955 $ 608,267 $ 588,930 $ 551,930 $ 543,096
Gas 326,061 293,708 261,724 235,728 236,496 264,573
-------------------------------------------------------------------------------------------------------------------------------
984,209 932,663 869,991 824,658 788,426 807,669
Electric sales to other utilities 16,605 16,361 25,541 28,612 42,465 38,028
-------------------------------------------------------------------------------------------------------------------------------
Total Operating Revenues 1,000,814 949,024 895,532 853,270 830,891 845,697
-------------------------------------------------------------------------------------------------------------------------------
Operating Expenses
Fuel Expenses
Electric fuels 44,961 45,871 48,376 65,105 76,420 75,873
Purchased electricity 37,002 31,563 29,706 27,683 34,264 39,645
Gas purchased for resale 194,390 166,884 141,291 129,779 132,512 152,623
-------------------------------------------------------------------------------------------------------------------------------
Total Fuel Expenses 276,353 244,318 219,373 222,567 243,196 268,141
-------------------------------------------------------------------------------------------------------------------------------
Operating Revenues Less Fuel Expenses 724,461 704,706 676,159 630,703 587,695 577,556
Other Operating Expenses
Operations excluding fuel expenses 235,896 235,381 226,624 208,440 194,594 173,764
Maintenance 55,069 61,693 62,720 65,415 62,391 64,316
Depreciation and Amortization 87,461 84,177 85,028 84,181 77,767 75,063
Taxes - local, state and other 129,778 126,892 124,252 113,649 101,035 95,341
Federal income tax - current 35,658 33,453 36,101 28,766 20,661 20,509
- deferred 25,587 15,877 7,490 5,493 13,829 17,330
-------------------------------------------------------------------------------------------------------------------------------
Total Other Operating Expenses 569,449 557,473 542,215 505,944 470,277 446,323
-------------------------------------------------------------------------------------------------------------------------------
Operating Income 155,012 147,233 133,944 124,759 117,418 131,233
-------------------------------------------------------------------------------------------------------------------------------
Other Income and Deductions
Allowance for other funds used during
construction 396 153 164 675 2,689 2,261
Federal income tax 16,259 9,827 4,195 4,580 2,459 1,439
Pension plan curtailment (33,679) (8,179) - - - -
Regulatory disallowances (600) (1,953) (8,215) (10,000) - (2,100)
Other, net (4,853) (7,074) 6,155 6,078 4,062 8,328
-------------------------------------------------------------------------------------------------------------------------------
Total Other Income and (Deductions) (22,477) (7,226) 2,299 1,333 9,210 9,928
-------------------------------------------------------------------------------------------------------------------------------
Income before Interest Charges 132,535 140,007 136,243 126,092 126,628 141,161
-------------------------------------------------------------------------------------------------------------------------------
Interest Charges
Long term debt 53,606 56,451 60,810 63,918 64,873 68,628
Short term debt 1,808 1,487 1,950 2,623 1,070 -
Other, net 4,758 5,220 5,228 4,459 3,523 3,115
Allowance for borrowed funds used during
construction (2,012) (1,714) (2,184) (2,905) (2,719) (2,026)
-------------------------------------------------------------------------------------------------------------------------------
Total Interest Charges 58,160 61,444 65,804 68,095 66,747 69,717
-------------------------------------------------------------------------------------------------------------------------------
Net Income 74,375 78,563 70,439 57,997 59,881 71,444
Dividends on Preferred Stock 7,369 7,300 8,290 6,963 6,025 6,025
-------------------------------------------------------------------------------------------------------------------------------
Earnings Applicable to Common Stock $ 67,006 $ 71,263 $ 62,149 $ 51,034 $ 53,856 $ 65,419
-------------------------------------------------------------------------------------------------------------------------------
Weighted average number of shares
for period (000's) 37,327 35,599 33,258 31,794 31,293 31,090
Earnings per Common Share $ 1.79 $ 2.00 $ 1.86 $ 1.60 $ 1.72 $ 2.10
-------------------------------------------------------------------------------------------------------------------------------
Cash Dividends Paid per Common Share $ 1.76 $ 1.72 $ 1.68 $ 1.62 $ 1.56 $ 1.50
-------------------------------------------------------------------------------------------------------------------------------
23
Condensed Consolidated Balance Sheet ----------------------------------------------------------------------------------
(Thousands of Dollars) At December 31 1994 1993 1992 1991 1990 1989
- -------------------------------------------------------------------------------------------------------------------------------
Assets
Utility Plant $2,981,151 $2,890,799 $2,798,581 $2,706,554 $2,310,294 $2,208,158
Less: Accumulated depreciation and
amortization 1,423,098 1,335,083 1,253,117 1,178,649 812,994 730,621
------------ ------------ ------------ ------------ ------------ ------------
1,558,053 1,555,716 1,545,464 1,527,905 1,497,300 1,477,537
Construction work in progress 128,860 112,750 83,834 76,848 82,663 68,784
------------ ----------- ------------ ------------ ------------ ------------
Net utility plant 1,686,913 1,668,466 1,629,298 1,604,753 1,579,963 1,546,321
Current Assets 236,519 248,589 209,621 189,009 176,045 190,321
Investment in Empire 38,560 38,560 9,846 - - -
Deferred Debits and Regulatory Assets 504,204 507,769 200,676 160,034 108,451 102,729
------------ ------------ ------------ ------------ ------------ ------------
Total Assets $2,466,196 $2,463,384 $2,049,441 $1,953,796 $1,864,459 $1,839,371
- --------------------------------------- ============ ============ ============ ============ ============ ============
CAPITALIZATION AND LIABILITIES
Capitalization
Long term debt $ 735,178 $ 747,631 $ 658,880 $ 672,322 $ 721,612 $ 764,627
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 55,000 42,000 54,000 60,000 30,000 30,000
Common shareholders' equity
Common stock 670,569 652,172 591,532 529,339 516,388 513,560
Retained earnings 74,566 75,126 66,968 61,515 62,542 57,983
------------ ------------ ------------ ------------ ------------ ------------
Total common shareholders' equity 745,135 727,298 658,500 590,854 578,930 571,543
------------ ------------ ------------ ------------ ------------ ------------
Total Capitalization 1,602,313 1,583,929 1,438,380 1,390,176 1,397,542 1,433,170
------------ ------------ ------------ ------------ ------------ ------------
Long Term Liabilities (Department
of Energy) 87,826 89,804 94,602 63,626 59,989 55,502
Current Liabilities 181,327 234,530 267,276 267,601 183,720 137,899
Deferred Credits and Other Liabilities 594,730 555,121 249,183 232,393 223,208 212,800
------------ ------------ ------------ ------------ ------------ ------------
Total Capitalization and Liabilities $2,466,196 $2,463,384 $2,049,441 $1,953,796 $1,864,459 $1,839,371
- --------------------------------------- ============ ============ ============ ============ ============ ============
24
Financial Data
At December 31 1994 1993 1992 1991 1990 1989
---- ---- ---- ---- ---- ----
Capitalization Ratios(a)(percent)
Long term debt 48.2 49.4 48.2 50.6 53.6 55.1
Preferred stock 7.3 6.6 8.0 8.7 6.7 6.5
Common shareholders' equity 44.5 44.0 43.8 40.7 39.7 38.4
------ ------ ------ ------ ------ ------
Total 100.0 100.0 100.0 100.0 100.0 100.0
------ ------ ------ ------ ------ ------
Book Value per Common Share--Year End $19.78 $19.70 $18.92 $18.41 $18.42 $18.28
Rate of Return on Average Common Equity
(percent) 11.73(b) 10.25(b) 9.98 8.60 9.29 11.56(c)
Embedded Cost of Senior Capital (percent)
Long term debt 7.40 7.36 7.91 8.32 8.59 8.74
Preferred stock 6.26 6.69 6.98 6.97 6.72 6.72
Effective Federal Income Tax Rate (percent) 37.7 33.5 35.9 33.9 34.8 33.8
Depreciation Rate (percent) - Electric 2.69 2.62 2.69 3.05 3.33 3.25
- Gas 2.62 2.60 2.78 2.94 2.94 2.96
Interest Coverages (c)(d)
Before federal income taxes (incld. AFUDC) 3.55 3.03 2.74 2.38 2.32 2.53
(excld. AFUDC) 3.51 3.00 2.70 2.33 2.25 2.47
After federal income taxes (incld. AFUDC) 2.61 2.35 2.12 1.91 1.86 2.02
(excld. AFUDC) 2.57 2.32 2.08 1.86 1.78 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) Rate of return on average common equity excludes the effects of retirement
enhancement programs recognized by the Company in 1994 and 1993.
(c) Excludes disallowed Nine Mile Two plant costs written off in 1989.
(d) 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 1994 and 1993 exclude the
effects of retirement enhancement programs recognized by
the Company during each year and certain gas purchase undercharges written
off in 1994 and 1993.
25
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.
EARNINGS SUMMARY
Operating earnings have improved due to modest rate relief and lower
interest expense, coupled with cost control efforts by the Company and savings
resulting from work force reduction programs in 1993 and 1994.
Presented below is a table which summarizes the Company's Common Stock
earnings on a per-share basis. Non-recurring items and their effect on earnings
per share have been identified. Earnings per share as reported in 1994 fell
below 1993 levels, reflecting one-time charges for work force reduction programs
completed during the past year. A total of 572 persons, or about 22 percent of
the work force elected to participate in one of three programs offered in 1993
and 1994. Of that total, 399 were participants in the most recent program
completed on October 1, 1994. The overall after-tax savings of the program are
estimated to be about $61 million through 1998. The latest program resulted in a
one-time charge in September 1994 of $33.7 million, or $.59 per share, net of
tax. The 1993 writeoffs totaled $8.2 million or $.15 per share for the earlier
programs.
In addition to the cost of the work force reduction programs, earnings as
reported include a charge of $.01 per share in 1994 and $.04 per share in 1993
for unrecoverable gas costs.
Excluding the impact of non-recurring items, earnings per share for 1994
and 1993 were up despite the effect of the issuance of additional Common Stock
in each year. Future earnings will be affected, in part, by the Company's
success in controlling operating and capital costs within the levels targeted
under the terms of the 1993 Rate Agreement (see Regulatory Matters), as well as
achieving certain incentive goals established in that Agreement. Furthermore, a
decision in early 1995 by the Company to discontinue operation of a weather
normalization clause under certain circumstances through May 1995 is expected to
have an impact on 1995 earnings as discussed under Operating Revenues and Sales.
The impact of developing competition in the energy marketplace may also affect
future earnings.
26
EARNINGS PER SHARE - SUMMARY
- --------------------------------------------------------------------------------
(Dollars per Share) 1994 1993 1992
- --------------------------------------------------------------------------------
Earnings per Share Before Non-recurring Items $2.39 $2.19 $1.91
Non-recurring Items
Gas Under-recovery Writeoff (.01) (.04)
Retirement Enhancement Programs (.59) (.15)
Nine Mile Two Litigation Proceeds .10
Ice Storm Disallowance (.15)
----- ----- -----
Total Non-recurring Items $(.60) $(.19) $(.05)
----- ----- -----
Reported Earnings per Share $1.79 $2.00 $1.86
===== ===== =====
DIVIDEND POLICY
In December 1993 the Company announced a quarterly dividend increase from
$.43 to $.44 per share of Common Stock payable in January 1994. Subsequently,
in December 1994 the Company announced a new quarterly dividend rate of $.45 per
share payable in January 1995. The Company's Certificate of Incorporation
(Charter) provides for the payment of dividends on Common Stock out of the
surplus net profits (retained earnings) of the Company. The Company believes
that future dividend payments will need to be evaluated in the context of
maintaining the financial strength necessary to operate in a more competitive
and uncertain business environment. This will require consideration, among
other things, of a dividend payout ratio that is lower over time, reevaluating
assets and managing greater fluctuation in revenues. While the Company does not
presently expect the impact of these factors to affect the Company's ability to
pay the current dividend, future dividends may be affected.
COMPETITION
OVERVIEW. The Company is operating in a rapidly developing competitive
marketplace for electric and gas service. In its electric business, this
competitive environment includes a Federal trend toward deregulation and a state
trend toward incentive regulation. The passage of the National Energy Policy
Act of 1992 (Energy Act) has accelerated these competitive challenges by
promoting competition in the electric power industry at the wholesale level, and
ensuring that a new class of independent power producers established under the
Energy Act, as well as qualified facilities and other electric utilities, can
achieve access to utility-owned transmission facilities upon payment of
appropriate prices. Competition in the Company's gas
27
business was accelerated with the passage of the Federal Energy Regulatory
Commission's (FERC) Order No. 636. In essence, FERC Order 636 requires
interstate natural gas pipeline companies to offer customers "unbundled", or
separately-priced, sale and transportation services.
ELECTRIC UTILITY COMPETITION. Cost pressures on major customers, excess
electric capacity in the region, and new technology 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 customer access to the transmission system in order to purchase
electricity from suppliers other than the Company.
In New York State, the Public Service Commission (PSC) has encouraged
competition by requiring utilities to purchase power from non-utility generating
companies at prices in excess of the utilities' internal cost of production, has
established various incentive mechanisms in rate proceedings to provide lower
cost energy, and has authorized flexible pricing for certain large customers who
have "realistic competitive alternatives".
Phase I of a PSC proceeding to address various issues related to increasing
competition in the New York State electric energy markets was completed in the
summer of 1994. The PSC approved flexible rate discounts for non-residential
electric customers who have competitive alternatives and adopted specific
guidelines for such rates. The PSC noted that flexible rates being offered by
the Company should serve as one of the models for other utilities within the
State. Phase II of this proceeding is currently underway with an objective to
identify regulatory and ratemaking practices that will assist in a transition to
a more competitive electric energy market, including investigating the
establishment of an efficient wholesale competitive market, and various issues
relating to retail competition. In a Notice issued in December 1994 inviting
comments on proposed principles to guide the transition to competition, the PSC
set forth nine general principles as follows. First, competition is endorsed,
especially at the wholesale level. Second, service affordability must be
maintained. Third, research programs, environmental protection, energy
efficiency and fuel diversity must be preserved. Fourth, safety and reliability
must not be jeopardized. Fifth, new industry structures should provide
increased choice for customers, consumer protection, efficiency incentives and
flexibility to accommodate individual utilities. Sixth, more competition should
lead to less regulation. Seventh, the current vertically integrated industry is
incompatible with effective competition. Eighth, utilities that cooperate in
the furthering of these principles should have a reasonable opportunity to
recover their costs. Ninth, changes in the industry should result in rising
income levels.
While the Company is in agreement with the spirit underlying most of the
principles described above, their
28
implementation could subsequently alter the nature and magnitude of the business
risks faced by the Company. This is especially true of any change resulting
from the seventh principle. In general, the Company believes market-based
solutions to the challenges facing this industry will ultimately result in the
greatest shareholder value, and it will continue to work to implement such
solutions. The Company cannot predict when Phase II will be completed or the
final outcome of this proceeding.
GAS UTILITY COMPETITION. Competition in the Company's gas business has
existed for some time, as larger customers have had the option of obtaining
their own gas supply and transporting it through the Company's distribution
system. FERC Order 636 enables 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 has shifted from
interstate pipeline companies to local distribution companies, such as the
Company.
In October 1993 the PSC initiated a proceeding to address issues involving
the restructuring of gas utility services to respond to competition. In
December 1994, the PSC issued an order which established regulatory policies and
guidelines for natural gas distributors. The requirements of the order having
the greatest impact on the Company are as follows. First, the Company must
offer its customers unbundled access to upstream facilities such as storage and
transportation capacity on the interstate pipelines with which the Company does
business. Second, the Company may offer to package an individual supply of gas
to an individual customer in cases where that would lower the Company's overall
cost of supplying gas. Third, the Company must offer an aggregation program
whereby individual customers could join together in a pool for the purpose of
purchasing gas from a supplier; in such cases the Company would still provide
the service of distributing the gas on the Company's system. Fourth, the PSC
allow the full recovery of the transition costs resulting from FERC Order 636,
and require that a share of these costs be borne by firm transportation
customers. Fifth, the PSC will institute a future proceeding to consider
incentive-based gas cost recovery mechanisms, a departure from the full flow-
through mechanism in place today. Lastly, the PSC will institute a separate
proceeding to bring about programs ensuring that all customers have access to a
basic, affordable gas service. The Company is reviewing these policies and, at
the present time, is unable to predict their impact.
COMPETITION AND THE COMPANY'S PROSPECTIVE FINANCIAL POSITION. The stock of
New York utilities, including the Company, has dropped during the past year
reflecting, in part, investor concern over the impact of the competitive and
regulatory changes which have occurred. Some critics have suggested that
certain New York State utilities should write down certain regulatory or
generating assets as a result of these changes. The Company has deferred
certain costs and is recognizing them as expenses when they are reflected in
rates and
29
recovered from customers as permitted by Statement of Financial Accounting
Standard No. 71 (SFAS-71). These costs are shown as Regulatory Assets on the
Company's Balance Sheet and a discussion and summarization of such Regulatory
Assets is presented in Note 10 of the Notes to Financial Statements. Deferral
of these costs is appropriate while the Company's rates are regulated under a
cost-of-service approach. In a purely competitive pricing approach, such costs
might not have been incurred or deferred. Accordingly, if the Company's rate
setting were changed from a cost-of-service approach and it was no longer
allowed to defer these costs under SFAS-71, certain of these assets may not be
fully recoverable. In addition, stranded assets (or other costs) arise when
investments are made in facilities or costs are incurred to service customers
and such costs may not be fully recoverable in rates. Examples include purchase
power contracts (i.e. the Kamine/Besicorp Allegany L.P. contract, see Projected
Capital and Other Requirements) or uneconomic generating assets. Excluding the
Kamine/Besicorp Allegany L.P. contract, estimates of stranded asset costs are
highly sensitive to the competitive wholesale market price assumed in the
estimation for electricity. The amount of stranded assets at December 31, 1994
cannot be determined at this time, but could be significant. While the Company
currently believes that its regulatory and stranded assets are probable of
recovery in rates, industry trends have moved more toward competition, and in a
purely competitive environment, it is not clear to what extent, if any,
writeoffs of such assets may occur.
THE COMPANY'S RESPONSE. The growing pace of competition in the energy
industry has been a primary focus of management over the past three years. The
Company accepts the challenges of this new environment and is working to
anticipate the impact of increased competition. Its business strategy for one
year and in summary for five years, focuses on improving cost-effective service
while reducing expenses and maintaining a competitive return for the
shareholder. The Company is engaged in a continuous process improvement program
to find opportunities for improved service and efficiency. It has implemented
three work force reduction programs during 1993 and 1994 which have had, and
will continue to have, a favorable impact on reducing operating costs, while
still enabling the Company to deliver safe, quality service. Also, the Company
in August 1994 streamlined its internal organization by combining 14 division-
sized functions into three functional areas as part of an ongoing effort to
provide customers with the best possible service at the lowest possible price.
The Company is operating under 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. By settlement with the PSC and
others, the Company has a competitive rate tariff that allows negotiated rates
with larger industrial and commercial customers
30
that have competitive electric supply options. Furthermore, the Company has
proposed for PSC approval two new flexible pricing tariffs to encourage economic
development and new business growth in our service territory.
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 mitigate its costs and increase earnings in the new gas business
environment.
The Company is evaluating all the factors which impact the rates it charges
its customers and therefore its competitive position, both with respect to
industrial and commercial customers as well as residential customers. In that
regard, it is reviewing its regulatory assets (costs which have been deferred
for collection in future rates) and generating facilities for their impact on
the Company's rate structure. The Company's workforce reduction programs,
efforts to control fixed and operational costs and decisions to delay any
collection of incentives earned under the 1993 Rate Agreement (see Regulatory
Matters) all relate to a focus on trying to maintain a rate structure which has
long-term benefits for the competitive presence of the Company in the industry.
The Company is reviewing its financing strategies as they relate to debt and
equity structures, the cost of these structures including the dividend program
and their impact on the Company's rate structure. All of these evaluations are
in the context of the new competitive environment and the ability of the Company
to shift from a fully regulated to a more competitive and growth-
oriented organization.
In addition to strategies aimed at creating a competitive rate structure,
the Company is reviewing strategies which may enhance it's ability to respond to
competitive forces and regulatory change. These strategies may include business
partnerships or combinations with other companies, internal restructuring
involving a separation of some or all of its wholesale and retail businesses,
and acquisitions of related businesses. No assurance can be given that any of
these potential strategies will be pursued or the corresponding results on the
financial condition or competitive position of the Company.
LIQUIDITY AND CAPITAL RESOURCES
During 1994 cash flow from operations, together with proceeds from external
financing activity (see Consolidated Statement of Cash Flows), provided the
funds for construction expenditures, the retirement of long-term debt and short-
term borrowings and the retirement and refinancing of Preferred Stock.
31
Capital requirements during 1995 are anticipated to be satisfied primarily from
the use of internally generated funds.
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.
Under Federal and New York State laws and regulations, the Company is
required to purchase the electrical output of unregulated cogeneration
facilities which meet certain criteria (Qualifying Facilities). With the
exception of one contract which the Company was compelled by regulators to enter
into with Kamine/Besicorp Allegany L.P. (Kamine) for approximately 55 megawatts
of capacity, the Company has no other long-term obligations to purchase energy
from Qualifying Facilities.
Under State law and regulatory requirements in effect at the time the
contract with Kamine was negotiated, the Company was required to pay Kamine a
price for power that is substantially greater than the Company's own cost of
production and other purchases. Since that time, the State law mandating a
minimum price higher than the Company's own costs has been repealed and PSC
estimates of future prices on which the contract was based have declined
dramatically.
In September 1994 the Company filed a lawsuit against Kamine seeking to
void its contract for the forced purchase of unneeded electricity at above-
market prices which would result in substantial cost increases for the Company's
customers. The Company estimates that Kamine will owe the Company $400 million
by the midpoint of the contract term and if the contract extends to its full 25-
year term, the total amount of such overpayments (plus interest) could reach
approximately $700 million. Alternatively, the Company sought relief to ensure
that its customers would pay no more for the Kamine power than they would pay
for power from the Company's other sources of electricity. Kamine answered the
Company's complaint, seeking to force the Company to take and pay for power at
the above-market rates and claiming damages in an unspecified amount alleged to
have been caused by the Company's conduct. The Company is unable to predict the
ultimate outcome of this litigation. The Company began receiving test
generation from the Kamine facility during the last quarter of 1994. In late
December 1994, the Company announced it would no longer be accepting electric
power from this facility because it is the Company's position, in addition to
other beliefs, that the Kamine facility is no longer a "Qualifying Facility" as
specified under Federal regulations.
32
On January 27, 1995 Kamine initiated a lawsuit against the Company in
Federal District Court for the Western District of New York for alleged anti-
trust violations by the Company that are based on the same issues that are
raised by the Company's New York State Court lawsuit. The Kamine lawsuit seeks
injunctive relief similar to that requested in Kamine's answer to the Company's
lawsuit in New York State Court and damages of $420 million. The Company intends
to vigorously defend against this lawsuit, but is unable to predict the outcome
at this time.
The Company's most current Integrated Resource Plan (IRP) explores
options for complying with the 1990 Clean Air Act Amendments. The IRP is part of
an ongoing planning process to examine options for the future with regard to
generating resources and alternative methods of meeting electric capacity
requirements. Activities are currently under way to:
- Modify Units 2, 3, and 4 at Russell Station and Unit 12 at Beebee
Station, all coal-fired facilities, to meet Federal Environmental
Protection Agency standards and Clean Air Act requirements,
- Explore possible partnerships with certain large customers to use
alternative generation or existing generation to mutual benefit,
- Use demand side management programs to reduce the need for
generating capacity, and
- Replace the two steam generators at the Ginna Nuclear Plant.
Replacement of the two steam generators at the Ginna Nuclear Plant is
expected to be completed in 1996. Much of the preliminary preparation is being
done during the normal annual refueling and maintenance outages. The Company
anticipates that the 1996 outage for refueling and final replacement will take
about 70 days. Cost of the replacement is estimated at $115 million; about $40
million for the units, about $50 million for installation and the remainder for
engineering and other services. As discussed under Regulatory Matters, a three-
year rate settlement establishes a mechanism to share variances from the
estimated $115 million cost between customers and the Company.
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.
33
CAPITAL REQUIREMENTS AND ELECTRIC OPERATIONS. Electric production
plant expenditures in 1994 included $31 million of expenditures made at the
Company's Ginna Nuclear Plant, of which $16 million was incurred for preparation
to replace the steam generators. The Company spent $15 million on this project
in 1993. In addition, nuclear fuel expenditures of $11 million were incurred at
Ginna during 1994. A refueling outage at Ginna normally occurs annually for a
period of approximately 40 to 50 days. Refueling is expected to take place on
an 18-month cycle once the new steam generators are installed.
Exclusive of fuel costs, the Company's 14 percent share of electric
production plant expenditures at the Nine Mile Two nuclear facility totaled $5
million in 1994. Expenditures of $5 million during 1994 were also 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 and resumed full
operation on December 3, 1993. The next refueling outage for Nine Mile Two is
scheduled for April 1995.
Electric transmission and distribution expenditures, as presented in
the Capital Requirements table, totaled $26 million in 1994, 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. The Empire State Pipeline
(Empire), an intrastate natural gas pipeline subject to PSC regulation between
Grand Island and Syracuse, New York commenced operation in November 1993.
Empire provides capacity for up to 50 percent of the Company's gas requirements.
The Company is participating as an equity owner of Empire, along with
subsidiaries of Coastal Corporation and Westcoast Energy Inc. The PSC
authorized the Company to invest up to $20 million in Empire. The Company's
share of ownership in Empire will depend upon final project costs and method of
financing selected by Empire. In June 1993 Empire secured a $150 million credit
agreement, the proceeds of which were used to finance approximately 75 percent
of the total construction cost and initial operating expenses. At December 31,
1994 the Company had invested a net amount of $10.3 million in Energyline and
was committed to provide a guarantee for $9.7 million of the borrowings under
the credit agreement.
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 resulted in gas
property construction requirements of $20 million in 1994.
ENVIRONMENTAL ISSUES
GENERAL. 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
34
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. 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. (See Note 10 of the Notes to Financial Statements.)
FEDERAL CLEAN AIR ACT AMENDMENTS. 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. A range of capital costs
between $20 million and $30 million has been estimated for the implementation of
several potential scenarios which would enable the Company to meet the
foreseeable NOx and sulphur dioxide requirements of the Amendments. These
capital costs would be incurred between 1996 and 2000. The Company estimates
that it could also incur up to $2.1 million of additional annual operating
expenses, excluding fuel, to comply with the Amendments. 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.
REDEMPTION OF SECURITIES
Discretionary redemption of securities totaled $24.5 million during
1994. A $16 million first mortgage bond maturity and $11.3 million of sinking
fund obligations were also a part of the Company's capital requirements in 1994.
Capital requirements in 1993 included a $75 million first mortgage
bond maturity, $17 million of sinking fund obligations, and discretionary first
mortgage bond redemptions of $120 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 1992 to 1994 and the current estimate of
capital requirements through 1997 are summarized in the Capital Requirements
table.
35
Capital Requirements
- -------------------------------------------------------------------------------------------------------------
Actual Projected
------------------------ ------------------------
1992 1993 1994 1995 1996 1997
Type of Facilities (Millions of Dollars)
- -------------------------------------------------------------------------------------------------------------
Electric Property
Production $ 47 $ 54 $ 42 $ 56 $ 66 $ 31
Transmission and Distribution 35 29 26 24 34 36
Street Lighting and Other 2 2 1 1 1 1
----- ----- ----- ----- ----- -----
Subtotal 84 85 69 81 101 68
Nuclear Fuel 11 16 16 19 21 21
----- ----- ----- ----- ----- -----
Total Electric 95 101 85 100 122 89
Gas Property 19 20 20 17 19 19
Common Property 15 21 12 11 17 21
----- ----- ----- ----- ----- -----
Total 129 142 117 128 158 129
Carrying Costs
Allowance for Funds Used During
Construction (AFUDC) 2 2 2 4 2 1
Deferred Financing Charges
Included in Other Income 3 1 - - - -
----- ----- ----- ----- ----- -----
Total Construction Requirements 134 145 119 132 160 130
Securities Redemptions, Maturities
and Sinking Fund Obligations* 160 212 52 - 18 30
----- ----- ----- ----- ----- -----
Total Capital Requirements $ 294 $ 357 $ 171 $ 132 $ 178 $ 160
----- ----- ----- ----- ----- -----
* Excludes prospective refinancings.
FINANCING AND CAPITAL STRUCTURE
Capital requirements in 1994 were satisfied primarily by a
combination of internally generated funds and short-term borrowings and
the Company foresees modest near-term financing requirements. With an
increasingly competitive environment, the Company believes maintaining
a high degree of financial flexibility is critical. In this regard, the
Company's long-term objective is to control capital expenditures, to
move to a less leveraged capital structure and to increase the common
equity percentage of capitalization toward the 50 percent range.
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, and other factors.
36
FINANCING. Under provisions of the Company's 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. At December 31, 1994,
including the $32.0 million of unsecured indebtedness already outstanding as
discussed in the following paragraph, the Company was able to issue $37.5
million of additional unsecured debt under this provision.
Short-term credit is available from certain banks pursuant to a $90
million revolving credit agreement which continues until December 31, 1997 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 to provide for borrowing up to $30 million for the exclusive
purpose of financing FERC Order 636 transition costs (see Energy Supply and
Costs-Gas) and up to $20 million as needed from time to time for other working
capital needs. Borrowings under this agreement, which can be renewed annually,
are secured by a lien on the Company's accounts receivable. The Company also
has unsecured lines of credit totaling $72 million with several other banks.
Funds available pursuant to these lines of credit are at the discretion of the
respective banks. At December 31, 1994 the Company had short-term borrowings
outstanding of $51.6 million, consisting of $32.0 million of unsecured short-
term debt and $19.6 million of secured short-term debt. In addition, borrowings
of $18.7 million associated with FERC Order 636 transition costs (recorded on
the Balance Sheet as a deferred credit) were outstanding at December 31, 1994.
In March 1994 the Company redeemed 180,000 shares of its 8.25%
Preferred Stock, Series R, representing all of the outstanding shares of this
series. At the Company's option, 120,000 of these shares were redeemed prior to
their normal sinking fund redemption date. Later that month, the Company issued
250,000 shares of 6.60% Preferred Stock, Series V.
During 1994 approximately 644,000 new shares of Common Stock were sold
through the Company's Automatic Dividend Reinvestment and Stock Purchase Plan
(ADR Plan), providing $14.8 million to help finance its capital expenditures
program. New shares issued in 1994 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 Company's retained earnings at December 31,
1994 were $74.6 million, a decrease of approximately $0.5 million compared with
a year earlier. Retained earnings were reduced by approximately $21.9 million
in September 1994 resulting from the charge for a workforce reduction program,
as discussed under the heading Earnings Summary. Common equity (including
retained earnings) comprised 44.5 percent of the
37
Company's capitalization at December 31, 1994, with the balance being comprised
of 7.3 percent preferred equity and 48.2 percent long-term debt. 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 10 of the Notes to Financial Statements. To
improve its capital structure, the Company currently anticipates the issuance of
new shares of Common Stock, primarily through the Company's ADR Plan. The
Company is reviewing its financing strategies as they relate to debt and equity
structures in the context of the new competitive environment and the ability of
the Company to shift from a fully regulated to a more competitive organization.
REGULATORY MATTERS
NEW YORK STATE PUBLIC SERVICE COMMISSION (PSC). The Company is
subject to PSC regulation of rates, service, and sale of securities, among other
matters. 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. 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 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 petition the PSC for relief.
In the first quarter of 1994 the Company filed with the PSC certain
adjustments required under various clauses of the 1993 Rate Agreement and new
rates were subsequently approved and became effective for the rate year
beginning July 1, 1994 (Year 2 under the Agreement). These new rates primarily
reflect adjustments for higher property taxes, a Federal tax rate increase, and
variations in electric sales between actual and projected levels offset, in
part, by operating and maintenance expense savings achieved in Year 1 under the
1993 Rate Agreement.
A summary of recent PSC rate decisions is presented in the table
titled Rate Increases. The amounts presented in this table do not include any
variations from the estimated cost of fuel included in base rates which are or
may be collected/refunded through the Company's fuel clause provisions (see
Operating Revenues and Sales).
38
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 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 3.0 9.23 11.50
July 1, 1995* 21,800 3.0 9.41 11.50
Gas 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* 7,400 3.0 8.90 11.50
July 1, 1995* 4,300 1.7 9.41 11.50
* See under heading Regulatory Matters for additional details. Amounts for 1995
are subject to certain adjustments to be filed with the PSC by the Company in
March 1995.
The 1993 Rate Agreement includes:
- Incentive mechanisms that have the potential to either
increase or reduce earnings from 5 to 110 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, 1995, these incentives have the potential to affect
earnings by approximately $12 million.
- Mechanisms for sharing costs between customers and
shareholders for operation and maintenance expense
variations. In general, these variances are shared 50% by
customers and 50% by the Company, unless those costs are
directly manageable by the Company, in which case there
is no sharing and such costs are to be absorbed/retained
by the Company.
- Mechanisms for sharing 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. If there is an overspending
variance, the Company will write off 50% of the net
cumulative amount of the variance.
39
- Sharing mechanism regarding the replacement of the Ginna Nuclear Plant
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. Replacement of the steam generators was made
subject to a final prudency review by the PSC.
- 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
base revenue increase shown in the table titled Rate Increases may be adjusted
up or down in Year 3. Negotiated electric base rate increases could be reduced
to zero or increased up to an additional 1.6% in Year 3 and 1.8% in the
following year. Negotiated gas base rate increases could also be reduced to
zero or increased up to an additional 1.6% in Year 3, and 1.8% in the following
year, exclusive of the impact of Empire going into service.
Contained in the rate order for Year 2 is recognition of $9.6 million
related to the Company's performance in Year 1, recovery of which the Company
has delayed for future consideration. The $9.6 million is comprised of the
following:
- $1.9 million for ERAM,
- $6.7 million for an Integrated Resource
Management Incentive or relative electric
production efficiency, and
- $1.0 million for a Service Quality Incentive.
In electing to delay for possible future recovery those incentive amounts for
which it was entitled, the Company gave consideration to the current and future
competitive environment and its objective for minimizing price impacts on the
customer while protecting earnings for shareholders.
The Company obtained PSC approval for a new flexible pricing tariff
for major industrial and commercial electric customers in a settlement approved
by the PSC in March 1994. This tariff allows 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 will absorb 30 percent of any net revenues lost as a
result of such discounts through June 1996, while the remainder may be recovered
from other customers.
40
The portion recoverable after June 1996 is expected to be determined in a future
Company rate proceeding. Under these tariff provisions, the Company has
negotiated long-term electric supply contracts with three of its large
industrial and commercial electric customers at discounted rates. It intends to
pursue negotiations with other large customers as the need and opportunity
arise. The Company has not experienced any customer loss due to competitive
alternative arrangements.
The PSC Staff is currently reviewing the Company's application for the
recovery of certain deferred gas costs as discussed under the heading Energy
Supply and Cost - Gas.
The PSC has been conducting proceedings to investigate various issues
regarding the emerging competitive environment in the electric and gas business
in New York State, as noted under the heading Competition.
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. Of the total
undercharges, $2.3 million had previously been expensed and $5.2 million had
been deferred on the Company's Balance Sheet. In March 1994, the PSC approved a
December 1993 settlement among the Company, PSC Staff and another party
providing for the recovery in rates of $2.6 million over three years. The
Company wrote off $2.0 million of the undercharges as of December 31, 1993,
reducing 1993 earnings by four cents per share, net of tax. In April 1994 the
Company wrote off an additional $0.6 million reducing 1994 earnings by
approximately one cent per share, net of tax. Due to rate increase limitations
established for Year 2 of the rate settlement, the Company is precluded from
recovering the undercharges until Year 3, which begins July 1, 1995.
In June 1992 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 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.
RESULTS OF OPERATIONS
The following financial review identifies the causes of significant
changes in the amounts of revenues and expenses, comparing 1994 to 1993 and 1993
to 1992. The Notes to Financial Statements contain additional information.
OPERATING REVENUES AND SALES
Compared with a year earlier, operating revenues rose
41
five percent in 1994 following a six percent increase in 1993. Operating
revenues in 1994 were pushed higher by gains in retail customer electric and gas
revenues, while revenues from the sale of electric energy to other utilities
were basically unchanged from a year earlier. Customer revenue increases in
1994 resulted primarily from rate relief and recovery of higher fuel costs.
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) 1994 1993 1994 1993
- ----------------------------------------------------------------------------------------------
Customer Revenues (Estimated) from:
Rate Increases $18,647 $21,827 $ 4,155 $ 8,087
Fuel Costs 3,171 9,093 29,989 25,593
Weather Effects (Heating & Cooling) (1,166) 200 (3,362) 700
Customer Consumption 1,726 4,374 (2,406) 1,381
Other (3,185) (4,806) 3,977 (3,777)
------- ------- ------- -------
Total Change in Customer Revenues 19,193 30,688 32,353 31,984
Electric Sales to Other Utilities 244 (9,180) - -
------- ------- ------- -------
Total Change in Operating Revenues $19,437 $21,508 $32,353 $31,984
Changes in FUEL AND PURCHASED POWER COST REVENUES normally have been earnings
neutral in the past. 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 1993 and $3.9 million in 1994,
primarily reflecting actual experience in both electric fuel costs and
generation mix compared with rate assumptions. Deferred costs associated with
the DOE's assessment for future uranium enrichment decontamination and certain
transition costs incurred by the Company's gas supply pipeline companies and
billed to the Company are being recovered through the Company's fuel adjustment
clauses.
The effect of WEATHER variations on operating revenues is most measurable in
the Gas Department, where revenues from
42
spaceheating 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 spaceheating. Weather in the Company's service area during
1993 was colder than normal, in contrast to 1994 which was warmer than normal,
despite record-setting cold weather in January 1994. Overall, weather during
1994 was 4.9 percent warmer than 1993 on a calendar-month heating degree day
basis. Warmer than normal summer weather during 1994 and 1993 boosted electric
energy sales to meet the demand for air conditioning usage. 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.
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 cycle month basis for the months of October through May, inclusive.
The weather normalization adjustment for a billing cycle applies 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 1994 and 1993 by approximately $1.25 million and $1.2
million respectively. Adjustments will continue through June 1996 in accordance
with the 1993 Rate Agreement for weather which is colder than normal. However,
beginning in January 1995 and continuing until May 1995, the Company elected to
discontinue the operation of this clause in circumstances where the weather is
warmer than normal because of the unusually mild weather that has been
experienced in its service territory and the adverse effects on customer bills.
The earnings impact of this decision in 1995 will range between $3.5 and $8.7
million depending on the duration of mild weather for the heating season.
Compared with a year earlier, KILOWATT-HOUR SALES OF ENERGY TO RETAIL
CUSTOMERS were nearly flat in 1994, after climbing about one percent in 1993.
Electric demand for air conditioning usage had a significant impact on such
sales in each of these years. During 1993 and 1994, an increase in combined
sales to residential and commercial customers more than offset a decline in
sales to industrial customers, which occurred as a result, in part, of a decline
in local manufacturing employment. The Company had a net gain of over 2,600 new
electric customers during 1994, including nearly 350 new commercial customers.
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 1993 and 1994 reflect the
sale of energy at a lower average rate per megawatt hour, a
43
result, in part, of competition and greater availability of energy. With the
possibility of 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 distribute this
gas, which amounted to 13.6 million dekatherms in 1994 and 12.4 million
dekatherms in 1993. These purchases have caused decreases in customer revenues,
with offsetting decreases in purchased gas expenses, but in general do not
adversely affect earnings because transportation customers are billed at rates
which, except for the cost of buying and transporting gas to our city gate,
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 COMBINED, including unbilled sales, were
down about two percent in 1994, after being nearly flat in 1993. These changes
reflect, primarily, the effect of weather variations on therm sales to customers
with spaceheating. If adjusted for normal weather conditions, residential gas
sales would have increased about 0.6 percent in 1994 over 1993, while
nonresidential sales, including gas transported, would have increased
approximately 1.9 percent in 1994. The average use per residential gas
customer, when adjusted for normal weather conditions, was slightly down in
1994, following a modest decrease in 1993.
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 $44.0 million in 1994
after increasing $40.2 million in 1993. These increases were driven by higher
gas purchased for resale costs in each comparison period. The increases in
operating expenses were mitigated by the Company's continuing efforts to curtail
increases in maintenance and other operation expenses. Operating expenses are
summarized in the table titled Operating Expenses.
44
OPERATING EXPENSES
- --------------------------------------------------------------------------------
INCREASE OR (DECREASE) FROM PRIOR YEAR
(Thousands of Dollars)
1994 1993
- --------------------------------------------------------------------------------
Fuel for Electric Generation $ (910) $ (2,505)
Purchased Electricity 5,439 1,857
Gas Purchased for Resale 27,506 25,593
Other Operation 515 8,757
Maintenance (6,624) (1,027)
Depreciation 3,284 (176)
Amortization of Other Plant - (675)
Taxes Charged to Operating Expenses
Local, State and Other Taxes 2,886 2,640
Federal Income Tax 11,915 5,739
-------- --------
Total Change in Operating Expenses $ 44,011 $ 40,203
======== ========
ENERGY COSTS - ELECTRIC. For both comparison periods, 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. The average cost of coal and nuclear fuel decreased in 1994 over
1993.
The Company purchases electric power to supplement its own generation when
needed to meet load or reserve requirements, and when such power is available at
a cost lower than the Company's production cost. For both comparison periods,
the increase in purchased electricity expense was primarily caused by an
increase in kilowatt-hours purchased. Average rates for purchased electricity
declined in 1994 and in 1993.
ENERGY SUPPLY AND COSTS - GAS. As a result of the implementation of FERC
Order 636, and the commencement of operation of Empire, the Company now
purchases all of its required gas supply directly from numerous producers and
marketers under contracts containing varying terms and conditions. The Company
holds firm transportation capacity on ten 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.
The Company acquires gas supply and transportation capacity based on its
requirements to meet peak loads which generally occur in the winter months.
With Empire going on-line, the Company's gas supply and transportation capacity
have also
45
been enhanced and increased. The Company expects to have excess gas and
transportation capacity at various times throughout the year which it will
attempt to sell separately or bundled as a package to customers outside the
Company's franchise area. The Company is also able to mitigate transportation
costs via the capacity release market. To what extent the Company can
successfully achieve the assignment or sale of any excess gas and/or
transportation capacity, or at what price, cannot be determined at the present
time.
As a result of the restructuring of the gas transportation industry by FERC
and related decisions, there will be a number of changes in this aspect of the
Company's business over the next several years. These changes will require the
Company to pay a share of certain transition costs incurred by the pipelines as
a result of the FERC-ordered industry 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 $44 and $52 million. A substantial portion
of such costs will be on the CNG system of which approximately $27 million was
billed to the Company in December 1993 and subsequently paid by the Company.
The Company has entered into a $30 million credit agreement with a domestic bank
to provide funds for the Company's transition cost liability to CNG. At
December 31, 1994 the Company had $18.7 million of borrowings outstanding under
the credit agreement. The Company has begun collecting those costs through the
Gas Clause Adjustment in its rates.
It was primarily an increase in average purchased gas rates that pushed up the
cost of gas purchased for resale for both comparison periods. These higher
rates reflect, in part, increased demand charges and newly assessable gas
service restructuring charges as a result of FERC Order 636. In contrast to
1993, a decrease in the volume of gas purchased for resale helped to mitigate
the overall increase in purchased gas expense in 1994.
A reconciliation of gas costs incurred and gas costs billed to customers is
done annually, as of August 31, and the excess or deficiency is refunded to or
recovered from customers during a subsequent period. In October 1994 the
Company submitted to the PSC its annual reconciliation providing for recovery of
$24 million of deferred gas costs, which was substantially higher than in
previous years due to the factors mentioned above.
The Staff of the PSC has reviewed the Company's application for recovery of
these deferred costs and various other parties requested that the PSC conduct
hearings to determine whether and on what terms the deferral should be
recovered. On December 19, 1994 the PSC instituted a proceeding to review the
Company's practices regarding acquisition of pipeline capacity, the deferred
costs of the capacity and the Company's recovery of those costs. The costs
included in the
46
deferral have ordinarily been recovered in the past and the Company believes
that they should be recovered in this instance; however, it is possible that
with respect to these costs, the PSC may not recognize all of them in rates. If
that were to occur, the Company would be compelled to discontinue deferring and
recovering costs above the allowed amount, and would recognize the disallowed
costs as they were incurred as a charge against earnings. In addition, in a
more adverse decision, the PSC could order the Company to refund a portion of
such costs previously collected from ratepayers. Pending the conclusion of the
proceeding, the PSC directed the Company to recover FERC Order 636 transition
costs over a five-year period and all other unrecovered gas costs over 18
months.
As an interim measure, on February 1, 1995, the PSC directed the Company to
remove from existing rates $16 million of gas revenues representing a portion of
the costs attributable to excess capacity over the remaining term of the
contracts. Prospective capacity release credits obtained by the Company are to
be used to offset such amounts. These deferred costs are subject to recovery by
the Company from customers, with interest, to the extent the Company's actions
are found prudent.
The Company cannot predict to what extent the deferred costs
described above would be recoverable in rates.
The Company's purchased gas expense charged to customers will be
higher during the 1994-95 heating season for the reasons described above.
OPERATING EXPENSES, EXCLUDING FUEL. After rising approximately $8.8 million
in 1993, the growth in other operation expenses remained flat in 1994, a direct
result of the Company's cost control efforts and workforce reduction programs.
For 1994, higher costs for the Company's demand side management program, claims,
and uncollectibles were offset by lower payroll and employee welfare costs due
to employee reductions and reduced expenses for contractors and consultants.
The change in other operation expenses for the 1993 comparison period reflects
primarily increased payroll costs and demand side management expenses partially
offset by lower fire and liability insurance costs, transportation, materials
and supplies, and legal expense.
Statement of Financial Accounting Standards 112 (SFAS-112), "Employees'
Accounting for Postemployment Benefits", was adopted by the Company during the
first quarter of 1994. SFAS-112 requires the Company to recognize the
obligation to provide postemployment benefits to former or inactive employees
after employment but before retirement. The additional postemployment
obligation at the time of the accounting change was approximately $11 million
and is being deferred on the Balance Sheet. The Company anticipates filing with
the PSC for recovery of the incremental expenses as the result of the adoption
of SFAS-112.
Statement of Financial Accounting Standards 115 (SFAS-115), "Accounting for
Certain Investments in Debt and
47
Equity Securities" was also adopted by the Company in the first quarter of 1994
and requires that debt and equity securities not held to maturity or held for
trading purposes be recorded at fair value with unrealized gains and losses
excluded from earnings and recorded as a separate component of shareholders'
equity. The Company's accounting policy, as prescribed by the PSC, with respect
to its nuclear decommissioning trusts is to reflect the trusts' assets at market
value and reflect unrealized gains and losses as a change in the corresponding
accrued decommissioning liability.
Lower maintenance expense in both comparison periods reflects reduced payroll
and contractor costs.
Despite an increase in depreciable plant in both comparison periods,
depreciation declined moderately in 1993 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. For the 1994
comparison period, the higher depreciation expense reflects the increase in
depreciable plant.
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 increased property tax rates and generally higher property
assessments. The 1994 comparison period also reflects certain assessments for
prior years' taxes.
During the first quarter of 1993, the Company adopted SFAS-109 entitled
"Accounting for Income Taxes" issued by the FASB in February 1992. The
Company's adoption of SFAS-109 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. In 1993, the Company adjusted it's tax reserve balances to reflect
this new rate. Such adjustment had no material effect on the Company's
financial condition or results of operations.
OTHER STATEMENT OF INCOME ITEMS
Variations in non-operating Federal income tax reflect mainly accounting
adjustments related to retirement enhancement programs (see Earnings Summary),
regulatory disallowances, and employee performance incentive programs (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
48
during the third and fourth quarters of 1993 and the third quarter of 1994.
These programs are discussed under Earnings Summary.
Recorded under the caption Regulatory Disallowances is the recognition of the
1992 PSC order related to a March 1991 ice storm, and a 1993 settlement with the
PSC, as supplemented in 1994, regarding certain 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. Other--Net Income and Deductions for 1993 and
1994 results mainly from the recognition of employee performance incentive
programs in each of those years. These programs recognize employees'
achievements in meeting corporate goals and reducing expenses. For the 1994
comparison period, Other--Net Income and Deductions also reflects higher
miscellaneous interest revenues.
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 1992-1994. The average short-term debt outstanding decreased in 1993 and
1994.
49
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, 1994.
Consolidated Balance sheets at December 31, 1994 and 1993.
Consolidated Statement of Cash Flows for each of the three years
ended December 31, 1994.
Notes to Consolidated Financial Statements.
Financial Statement Schedules -
The following Financial Statement Schedule is 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 II - Valuation and Qualifying Accounts
B. Supplementary Data
Interim Financial Data.
50
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, 1994 and 1993, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1994, in conformity with generally accepted accounting principles.
These financial statements are the responsibility of the Company's management;
our responsibility is to express an opinion on these financial statements based
on our audits. We conducted our audits of these statements in accordance with
generally accepted auditing standards which require that we plan and perform the
audit to obtain reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements,
assessing the accounting principles used and significant estimates made by
management, and evaluating the overall financial statement presentation. We
believe that our audits provide a reasonable basis for the opinion expressed
above.
As discussed in Note 1 to the financial statements, the Company adopted the
provisions of Statement of Financial Accounting Standards No. 112, "Employers'
Accounting for Postemployment Benefits" in 1994.
PRICE WATERHOUSE LLP
Rochester, New York
January 20, 1995 (except for Note 10,
as to which the date is February 1, 1995)
51
Consolidated Statement of Income
-----------------------------------------------
(Thousands of Dollars) Year Ended December 31 1994 1993 1992
- ------------------------------------------------------------------------------------------------------------------
Operating Revenues
Electric $ 658,148 $ 638,955 $ 608,267
Gas 326,061 293,708 261,724
---------- ---------- ----------
984,209 932,663 869,991
Electric sales to other utilities 16,605 16,361 25,541
---------- ---------- ----------
Total Operating Revenues 1,000,814 949,024 895,532
Operating Expenses ---------- ---------- ----------
Fuel Expenses
Fuel for electric generation 44,961 45,871 48,376
Purchased electricity 37,002 31,563 29,706
Gas purchased for resale 194,390 166,884 141,291
---------- ---------- ----------
Total Fuel Expenses 276,353 244,318 219,373
---------- ---------- ----------
Operating Revenues Less Fuel Expenses 724,461 704,706 676,159
Other Operating Expenses ---------- ---------- ----------
Operations excluding fuel expenses 235,896 235,381 226,624
Maintenance 55,069 61,693 62,720
Depreciation and amortization 87,461 84,177 85,028
Taxes - local, state and other 129,778 126,892 124,252
Federal income tax 61,245 49,330 43,591
---------- ---------- ----------
Total Other Operating Expenses 569,449 557,473 542,215
---------- ---------- ----------
Operating Income 155,012 147,233 133,944
Other Income and Deductions ---------- ---------- ----------
Allowance for other funds used during construction 396 153 164
Federal income tax 16,259 9,827 4,195
Pension Plan Curtailment (33,679) (8,179) -
Regulatory disallowances (600) (1,953) (8,215)
Other, net (4,853) (7,074) 6,155
---------- ---------- ----------
Total Other Income and (Deductions) (22,477) (7,226) 2,299
---------- ---------- ----------
Income Before Interest Charges 132,535 140,007 136,243
Interest Charges ---------- ---------- ----------
Long term debt 53,606 56,451 60,810
Other, net 6,566 6,707 7,178
Allowance for borrowed funds used during construction (2,012) (1,714) (2,184)
---------- ---------- ----------
Total Interest Charges 58,160 61,444 65,804
---------- ---------- ----------
Net Income 74,375 78,563 70,439
Dividends on Preferred Stock 7,369 7,300 8,290
---------- ---------- ----------
Earnings Applicable to Common Stock $ 67,006 $ 71,263 $ 62,149
---------- ---------- ----------
Weighted Average Number of Shares for Period (000's) 37,327 35,599 33,258
---------- ---------- ----------
Earnings per Common Share $ 1.79 $ 2.00 $ 1.86
- ------------------------------------------------------ ---------- ---------- ----------
Consolidated Statement of Retained Earnings
----------------------------------------------
(Thousands of Dollars) Year Ended December 31 1994 1993 1992
- -----------------------------------------------------------------------------------------------------------------
Balance at Beginning of Period $ 75,126 $ 66,968 $ 61,515
Add
Net Income 74,375 78,563 70,439
Adjustment Associated With Stock Redemption (1,398) (933) -
--------- --------- ---------
Total 148,103 144,598 131,954
--------- --------- ---------
Deduct
Dividends declared on capital stock
Cumulative preferred stock 7,369 7,300 8,290
Common Stock 66,168 62,172 56,696
--------- --------- ---------
Total 73,537 69,472 64,986
--------- --------- ---------
Balance at End of Period $ 74,566 $ 75,126 $ 66,968
- ----------------------------------------------------- --------- --------- ---------
The accompanying notes are an integral part of the financial statements.
52
Consolidated Balance Sheet -------------------------------------
(Thousands of Dollars) At December 31 1994 1993*
- -------------------------------------------------------------------------------------------------------
Assets
Utility Plant
Electric $2,284,634 $2,234,530
Gas 370,205 356,484
Common 135,975 125,428
Nuclear fuel 190,337 174,357
---------- ----------
2,981,151 2,890,799
Less: Accumulated depreciation 1,263,637 1,190,801
Nuclear fuel amortization 159,461 144,282
---------- ----------
1,558,053 1,555,716
Construction work in progress 128,860 112,750
---------- ----------
Net Utility Plant 1,686,913 1,668,466
---------- ----------
Current Assets
Cash and cash equivalents 2,810 2,327
Accounts receivable, net of allowance for doubtful accounts:
1994 - $ 950; 1993 - $ 600 110,417 104,753
Unbilled revenue receivable 54,270 61,330
Materials and supplies, at average cost
Fossil fuel 7,908 5,983
Construction and other supplies 13,264 13,644
Gas stored underground 24,315 38,989
Prepayments 23,535 21,563
---------- ----------
Total Current Assets 236,519 248,589
---------- ----------
Investment in Empire 38,560 38,560
Deferred Debits
Unamortized debt expense 18,343 19,326
Nuclear generating plant decommissioning fund 49,011 38,930
Nine Mile Two deferred costs 33,462 34,513
Deferred finance charges - Nine Mile Two 19,242 19,242
Other Deferred Debits 19,214 27,073
Regulatory assets -
Income taxes 205,794 241,741
Uranium enrichment decommissioning deferral 20,169 23,421
Deferred ice storm charges 19,111 21,621
FERC 636 transition costs 32,479 41,265
Demand side management costs 19,807 20,573
Deferred fuel costs - gas 33,845 5,754
Other regulatory assets 33,727 14,310
---------- ----------
Total Deferred Debits 504,204 507,769
---------- ----------
Total Assets $2,466,196 $2,463,384
- ------------------------------------------------------------ ========== ==========
* Reclassified for comparative purposes.
The accompanying notes are an integral part of the financial statements.
53
Consolidated Balance Sheet -------------------------------------
(Thousands of Dollars) At December 31 1994 1993*
- -------------------------------------------------------------------------------------------------------
Capitalization and Liabilities
Capitalization
Long term debt - mortgage bonds $ 643,278 $ 655,731
- promissory notes 91,900 91,900
Preferred stock redeemable at option of Company 67,000 67,000
Preferred stock subject to mandatory redemption 55,000 42,000
Common shareholders' equity
Common stock 670,569 652,172
Retained earnings 74,566 75,126
---------- ----------
Total Common Shareholders' Equity 745,135 727,298
---------- ----------
Total Capitalization 1,602,313 1,583,929
---------- ----------
Long Term Liabilities (Department of Energy)
Nuclear waste disposal 70,895 68,055
Uranium enrichment decommissioning 16,931 21,749
---------- ----------
Total Long Term Liabilities 87,826 89,804
---------- ----------
Current Liabilities
Long term debt due within one year -- 21,250
Preferred stock redeemable within one year -- 6,000
Note Payable - Empire 29,600 29,600
Short term debt 51,600 68,100
Accounts payable 42,934 52,596
Dividends payable 18,818 18,066
Taxes accrued 3,471 6,472
Interest accrued 11,967 12,955
Other 22,937 19,491
---------- ----------
Total Current Liabilities 181,327 234,530
---------- ----------
Deferred Credits and Other Liabilities
Accumulated deferred income taxes 402,894 425,648
Deferred finance charges - Nine Mile Two 19,242 19,242
Pension costs accrued 75,912 31,919
Other 96,682 78,312
---------- ----------
Total Deferred Credits and Other Liabilities 594,730 555,121
---------- ----------
Commitments and Other Matters (Note 10) -- --
---------- ----------
Total Capitalization and Liabilities $2,466,196 $2,463,384
- ------------------------------------------------------- ========== ==========
* Reclassified for comparative purposes.
The accompanying notes are an integral part of the financial statements.
54
Consolidated Statement of Cash Flows
-----------------------------------------------
(Thousands of Dollars) Year Ended December 31 1994 1993 1992
- ---------------------------------------------------------------------------------------------------------------------------
CASH FLOW FROM OPERATIONS
Net income $ 74,375 $ 78,563 $ 70,439
Adjustments to reconcile net income to net cash provided
from operating activities:
Depreciation and amortization 87,461 84,177 85,028
Amortization of nuclear fuel 18,048 18,861 18,803
Deferred fuel - electric (1,967) (2,072) 2,543
Deferred fuel - gas (28,091) (11,500) 4,896
Deferred income taxes 13,193 15,232 10,466
Allowance for funds used during construction (2,408) (1,867) (2,348)
Unbilled revenue, net 7,060 (5,107) (6,631)
Deferred ice storm costs 2,510 2,576 12,234
Nuclear generating plant decommissioning fund (10,081) (9,381) (10,328)
Changes in certain current assets and liabilities:
Accounts receivable (5,664) (12,461) (8,239)
Materials and supplies - fossil fuel (1,925) 6,290 (1,507)
- construction and other supplies 380 (514) (591)
- gas stored underground 14,674 (28,991) (2,942)
Taxes accrued (3,001) (7,271) 1,693
Accounts payable (9,662) 12,018 (13,404)
Interest accrued (988) (2,506) (852)
Other current assets and liabilities, net 317 6,113 (2,528)
Other, net 61,881 10,966 (5,832)
--------- --------- ---------
Total Operating $ 216,112 $ 153,126 $ 150,900
- --------------------------------------------------------- ========= ========= =========
CASH FLOW FROM INVESTING ACTIVITIES
Utility Plant
Plant additions $(103,737) $(125,744) $(115,792)
Nuclear fuel additions (15,890) (15,530) (11,763)
Less: Allowance for funds used during construction 2,408 1,867 2,348
--------- --------- ---------
Additions to Utility Plant (117,219) (139,407) (125,207)
Investment in Empire - net -- 884 (9,846)
Other, net (150) (1,907) 490
--------- --------- ---------
Total Investing $(117,369) $(140,430) $(134,563)
- --------------------------------------------------------- ========= ========= =========
CASH FLOW FROM FINANCING ACTIVITIES
Proceeds from:
Sale/Issue of common stock $ 17,369 $ 61,254 $ 63,928
Sale of preferred stock 25,000 -- --
Sale of long term debt, mortgage bonds -- 200,000 160,500
Short term borrowings (16,500) 17,300 (8,700)
Retirement of long term debt (33,750) (200,249) (160,000)
Retirement of preferred stock (18,000) (12,000) --
Capital stock expense 1,028 (615) (1,735)
Discount and expense of issuing long term debt (531) (7,909) (6,368)
Dividends paid on preferred stock (7,328) (7,548) (8,290)
Dividends paid on common stock (65,457) (60,893) (55,216)
Other, net (91) (1,468) (185)
--------- --------- ----------
Total Financing $ (98,260) $ (12,128) $ (16,066)
--------- --------- ----------
Increase in cash and cash equivalents $ 483 $ 568 $ 271
Cash and cash equivalents at beginning of year $ 2,327 $ 1,759 $ 1,488
--------- --------- ----------
Cash and cash equivalents at end of year $ 2,810 $ 2,327 $ 1,759
- --------------------------------------------------------- ========= ========= ==========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
------------------------------------------
(Thousands of Dollars) Year Ended December 31 1994 1993 1992
- ---------------------------------------------------------------------------------------------------------------------
Cash Paid During the Year
Interest paid (net of capitalized amount) $ 57,186 $ 60,852 $ 64,431
Income taxes paid $ 28,411 $ 32,779 $ 22,911
- --------------------------------------------------------- ========= ========= =========
The accompanying notes are an integral part of the financial
statements.
55
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 ratemaking and accounting practices and policies of the PSC.
Energyline Corporation, which is a wholly-owned subsidiary, 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. 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% of the total
construction cost and initial operating expenses. Energyline is obligated to
pay its 20% share of the balance outstanding subject to a maximum commitment of
$9.7 million under the credit agreement. Excluding the loan commitment, at
December 31, 1994 the Company had invested a net amount of $10.3 million in
Energyline.
PRINCIPLES OF CONSOLIDATION. The consolidated financial statements include the
accounts of the Company and its wholly-owned subsidiaries Roxdel and Energyline.
All intercompany balances and transactions have been eliminated.
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% 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.
In addition, there is a similar 50%/50% sharing process of variances
from forecasted margins derived from sales and the
56
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. Beginning July 1994 through December 31, 1994, $7.3 million was
recoverable from customers. The company is not currently recognizing ERAM
amounts as part of income. The ultimate recognition, if any, will be determined
based on a filing with the PSC during 1995.
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 applies only if the actual
heating degree days are lower than 97.5% or higher than 102.5% of the normal
heating degree days. Weather normalization adjustments lowered gas revenues in
1994 and 1993 by approximately $1.25 million and $1.2 million respectively.
Adjustments will continue through June 1996 in accordance with the 1993 multi-
year rate settlement agreement for weather which is colder than normal (also see
Note 10).
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 period.
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% per annum of average depreciable property in
1994, 1993, and 1992.
57
FERC ORDER 636. Under this order, gas supply and pipeline companies are allowed
to pass restructuring and transition costs associated with the implementation of
the order on to their customers. The Company, as a customer, has estimated
total costs to range between $44 and $52 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 $33.7
million of these costs were paid to various suppliers, of which $15 million has
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 Consolidated 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 ranged
from 3.9% to 7.1% during the three-year period ended December 31, 1994.
The Company did not accrue 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. Statement of Financial Accounting Standards (SFAS) 109,
Accounting for Income Taxes, was adopted by the Company during the first quarter
of 1993 (see Note 2).
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 Financial Accounting Standards Board 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
58
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.
POSTEMPLOYMENT BENEFITS. SFAS-112, "Employers ' Accounting for Postemployment
Benefits", was adopted by the Company during the first quarter of 1994. SFAS-
112 requires the Company to recognize the obligation to provide postemployment
benefits to former or inactive employees after employment but before retirement.
The additional postemployment obligation at the time of the accounting change
was approximately $11 million and is being deferred on the balance sheet.
INVESTMENTS IN DEBT AND EQUITY SECURITIES. SFAS-115, "Accounting for Certain
Investments in Debt and Equity Securities" was adopted by the Company in the
first quarter 1994 and requires that debt and equity securities not held to
maturity or held for trading purposes be recorded at fair value with unrealized
gains and losses excluded from earnings and recorded as a separate component of
shareholders' equity. The Company's accounting policy, as prescribed by the
PSC, with respect to its nuclear decommissioning trusts is to reflect the
trusts' assets at market value and reflect unrealized gains and losses as a
change in the corresponding accrued decommissioning liability.
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.
59
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) 1994 1993 1992
---- ---- ----
Charged to operating expense:
Current $35,658 $33,453 $36,101
Deferred 25,587 15,877 7,490
------- ------- -------
Total 61,245 49,330 43,591
Charged (Credited) to other income: ------- ------- -------
Current (7,419) (9,182) (7,171)
Deferred (6,408) 1,787 5,402
Investment tax credit (2,432) (2,432) (2,426)
------- ------- -------
Total (16,259) (9,827) (4,195)
------- ------- -------
Total Federal income tax expense $44,986 $39,503 $39,396
------- ------- -------
The following is a reconciliation of the difference between the amount
of Federal income tax expense reported in the Consolidated Statement of Income
and the amount computed by multiplying the income by the statutory tax rate.
(Thousands of Dollars) 1994 1993 1992
% of % of % of
Pretax Pretax Pretax
Amount Income Amount Income Amount Income
------ ------ ------ ------ ------ ------
Net Income $ 74,375 $ 78,563 $ 70,439
Add: Federal income tax expense 44,986 39,503 39,396
-------- -------- --------
Income before Federal income tax $119,361 $118,066 $109,835
-------- -------- --------
Computed tax expense $ 41,776 35.0 $ 41,323 35.0 37,344 34.0
Increases (decreases) in tax resulting
from: Difference between tax
depreciation and amount deferred 6,685 5.6 6,337 5.4 6,775 6.2
Investment tax credit (2,432) (2.0) (2,432) (2.1) (2,426) (2.2)
Miscellaneous items, net (1,043) (0.9) (5,725) (4.8) (2,297) (2.1)
--------- ---- --------- ------- -------- ----
Total Federal income tax expense $ 44,986 37.7 $ 39,503 33.5 $ 39,396 35.9
A summary of the components of the net deferred tax liability is as
follows:
(Thousands of Dollars) 1994 1993 1992
---- ---- ----
Nuclear decommissioning ($13,390) ($11,518) ($13,087)
Nine Mile disallowance (10,276) (15,200) (19,569)
Alternate minimum tax (9,584) (27,908) (27,611)
Accelerated depreciation 184,941 164,821 174,237
Investment tax credit 32,723 34,305 55,206
Deferred ice storm charges 4,930 5,642 6,519
Depreciation previously flowed through 200,956 246,127 -
Other 12,594 29,379 (4,022)
-------- -------- --------
Total $402,894 $425,648 $171,673
The Company adopted SFAS-109 "Accounting for Income Taxes" in 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 and 1994 was $241 million and $206 million, respectively. 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 1993
the statutory income tax rate was 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.
As of December 31, 1994, the regulatory asset recognized by the Company as a
result of adopting SFAS-109 is attributed to $184 million in depreciation, $21
million to property taxes, $18 million of deferred finance charges - Nine Mile
Two and $3 million of Miscellaneous items offset by $18 million attributed to
investment tax credits and $2 million to revenue taxes.
60
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)
----------------------
1994 1993
Accumulated benefit obligation, including
vested benefits of $330.5 in 1994 and
$286.1 in 1993 $ (354.8)* $ (309.3)*
========== =========
Projected benefit obligation for service
rendered to date $ (433.5)* $ (429.5)*
Less - Plan assets at fair value, primarily
listed stocks and bonds 451.7 490.3
-------- ---------
Plan assets in excess of projected benefits 18.2 60.8
Unrecognized net loss (gain) from past
experience different from that assumed
and effects of changes in assumptions (110.9) (110.6)
Prior service cost not yet recognized in
net periodic pension cost 13.4 13.7
Unrecognized net obligation at December 31 3.4 4.2
--------- ---------
Pension costs accrued $ (75.9)** $ (31.9)***
=========== ===========
* Actuarial present value
** Includes $43.3 million pension plan curtailment charge.
*** Includes $9.2 million pension plan curtailment charge.
Net pension cost included the following
components: (Millions)
-------------------------------
Service cost - benefits earned during 1994 1993 1992
the period $ 8.2 $ 8.7 $ 8.8
Interest cost on projected benefit
obligation 32.2 30.0 27.9
Actual return on plan assets 0.8 (60.2) (35.1)
Net amortization and deferral (40.0) 24.3 5.5
--------- ------- -------
Net periodic pension cost $ 1.2 $ 2.8 $ 7.1
========= ======= =======
61
During 1994, the Company offered to its employees a Temporary Retirement
Enhancement Program (TREP 3). A total of 399 employees elected to participate
in TREP 3 resulting in a net curtailment charge of $43.3 million including $71.1
million cost of the enhanced benefit offset by a curtailment gain of $27.8
million. In connection with the curtailment, the Company revalued the projected
benefit obligation as of September 30, 1994 utilizing the then current discount
rate of 8.25%.
The projected benefit obligation at December 31, 1994, September 30, 1994 and
December 31, 1993 assumed discount rates of 8.50%, 8.25%, and 7.25%,
respectively and long-term rate of increase in future compensation levels of
6.00%. The assumed long-term rate of return on plan assets was 8.50%. 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 1994 and 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 1994, the health care benefit consisted of a contribution of up to $193 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 as the benefit becomes
due.
62
The plans' funded status reconciled with the Company's balance sheet is as
follows:
Accumulated postretirement benefit (Millions)
obligation: ------------------
1994 1993
Retired employees $(42.4) $(39.9)
Active employees (26.4) (24.9)
------ ------
$(68.8) $(64.8)
Less - Plan assets at fair value 0.0 0.0
------ ------
Accumulated postretirement benefit
obligation (in excess of) less than
fair value of assets (68.8) (64.8)
Unrecognized net loss (gain) from past experience
different from that assumed and effects
of changes in assumptions 0.8 2.9
Prior service cost not yet recognized in
net periodic pension cost 5.6 1.7
Unrecognized net obligation at December 31 47.9 50.7
------ ------
Accrued postretirement benefit cost $(14.5) $ (9.5)
====== ======
Net periodic postretirement benefit
cost included the following components:
(Millions)
------------------
Service cost - benefits attributed to 1994 1993
the period $ 0.9 $ 0.7
Interest cost on accumulated postretirement
benefit obligation 4.9 4.6
Actual return on plan assets 0.0 0.0
Net amortization and deferral 3.4 2.2
------ ------
Net periodic postretirement benefit cost $ 9.2 $ 7.5
====== ======
The Accumulated Postretirement Benefit Obligation at December 31, 1994 and
1993 assumed discount rates of 8.50% and 7.25%, respectively and long-term rate
of increase in future compensation levels of 6 percent.
63
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 Consolidated Statement of Income.
(Thousands of Dollars)
1994 1993 1992
---- ---- ----
Electric
Operating Information
Operating revenues $ 674,753 $ 655,316 $ 633,808
Operating expenses, excluding
provision for income taxes 489,982 486,951 482,968
---------- ---------- ----------
Pretax operating income 184,771 168,365 150,840
Provision for income taxes 52,842 43,845 38,046
---------- ---------- ----------
Net operating income $ 131,929 $ 124,520 $ 112,794
---------- ---------- ----------
Other Information
Depreciation and amortization $ 75,211 $ 72,326 $ 73,213
Nuclear fuel amortization $ 18,048 $ 18,861 $ 18,803
Capital expenditures $ 93,477 $ 112,022 $ 100,974
Investment Information
Identifiable assets (a) $1,920,504 $1,978,009 $1,671,492
Gas
Operating Information
Operating revenues $ 326,061 $ 293,708 $ 261,724
Operating expenses, excluding
provision for income taxes 294,575 265,510 235,029
---------- ---------- ----------
Pretax operating income 31,486 28,198 26,695
Provision for income taxes 8,403 5,485 5,545
---------- ---------- ----------
Net operating income $ 23,083 $ 22,713 $ 21,150
---------- ---------- ----------
Other Information
Depreciation and amortization $ 12,250 $ 11,851 $ 11,815
Capital expenditures $ 23,742 $ 27,385 $ 24,231
Investment Information
Identifiable assets (a) $ 487,333 $ 491,563 $ 354,528
(a) Excludes cash, unamortized debt expense and other common items.
64
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 Consolidated 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, 1994
----------------------------------------
Plant In Service Balance $ 98.1 $ 876.6
Accumulated Provision For Depreciation $ 34.5 $ 452.1
Plant Under Construction $ 0.6 $ 8.3
==================================================================================
The Plant in Service and Accumulated Provision for Depreciation balances for
Nine Mile Point Nuclear Unit No. 2 shown above include disallowed costs of
$374.3 million. Such costs, net of income tax effects, were previously written
off in 1987 and 1989.
65
NOTE 6. LONG TERM DEBT
First Mortgage Bonds
- ---------------------------------------------------------------------------------------
(Thousands of Dollars)
Principal Amount
------------------------
December 31
% Series Due 1994 1993
- ---------------------------------------------------------------------------------------
4 5/8 U Sept. 15, 1994 $ - $ 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
8 3/8 CC Sept. 15, 2007 50,000 50,000
6 1/2 EE/(a)/ Aug. 1, 2009 10,000 10,000
10.95 FF Feb. 15, 2005 - 2,750
13 7/8 JJ June 15, 1999 - 15,000
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 30,000
7.15 (b)(c) Feb. 10, 2003 39,000 39,000
7.13 (b)(c) Mar. 3, 2003 1,000 1,000
7.64 (c) Mar. 15, 2023 33,000 33,000
7.66 (c) Mar. 15, 2023 5,000 5,000
7.67 (c) Mar. 15, 2023 12,000 12,000
6.375 (b)(c) July 30, 2003 40,000 40,000
7.45 (c) July 30, 2023 40,000 40,000
-------- --------
644,000 677,750
Net bond discount (722) (769)
Less: Due within one year - 21,250
-------- --------
Total $643,278 $655,731
======== ========
(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 the 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
entitled "First Mortgage Bonds, Designated Secured Medium-Term Notes, Series
A" with maturities that range from seven years to thirty years.
66
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 1993 and 1994 requirements were met by certification
of additional property.
On February 15, 1994 the Company redeemed $2.75 million principal amount of its
First Mortgage 10.95% Bonds, Series FF, pursuant to a sinking fund provision.
On June 15, 1994 the Company redeemed all of its outstanding $15 million
principal amount of First Mortgage 13 7/8% Bonds, Series JJ, due June 15, 1999.
Of the $15 million total, $2.5 million was redeemed through a mandatory sinking
fund provision, and the remaining $12.5 million was redeemed at the Company's
option.
There are no sinking fund requirements for the next five years. Bond maturities
for the next five years are:
(Thousands of Dollars)
---------------------------------------------------------
1995 1996 1997 1998 1999
---------------------------------------------------------
Series V $18,000
Series W $20,000
Series X $30,000
Series Y $30,000
---------------------------------------------------------
$ - $18,000 $20,000 $30,000 $30,000
Promissory Notes
- --------------------------------------------------------------------------------
(Thousands of Dollars)
December 31
Issued Due 1994 1993
- --------------------------------------------------------------------------------
November 15, 1984/(d)/ October 1, 2014 $ 51,700 $ 51,700
December 5, 1985/(e)/ November 15, 2015 40,200 40,200
------- --------
Total $ 91,900 $ 91,900
======= ========
(d) 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, 1997. 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 2.82% for 1994, 2.19% for 1993 and 2.74% for 1992. The
interest rate will be adjusted monthly unless converted to a fixed rate.
(e) 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, 1997. The annual
interest rate was adjusted to 3.10% effective November 15, 1992, to 2.75%
effective November 15, 1993 and to 4.40% effective November 15, 1994. The
interest rate will be adjusted annually unless converted to a fixed rate.
67
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 1994 of 8.62% for long term
debt with similar terms and average maturities (13 years), the fair value of the
Company's long term debt outstanding (including Promissory Notes as described
above) is approximately $667 million at December 31, 1994.
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.
68
NOTE 7. PREFERRED AND PREFERENCE STOCK
Type, by Order Par Shares Shares
of Seniority Value Authorized Outstanding
- -------------- ----- ---------- -----------
Preferred Stock (cumulative) $100 2,000,000 1,220,000*
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, 1994 1994 1993 (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, 1994 1994 1993 (per share)
- ------- ------ ----------------- --------- --------- -----------------
8.25 R - $ - $18,000 Not Applicable
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
6.60 V 250,000 25,000 - Not Before 3/1/04+
------- ------- -------
550,000 $55,000 $48,000
Less: Due within one year - - 6,000
------- ------- -------
Total 550,000 $55,000 $42,000
------- -------
+ Thereafter at $100.00
69
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. The Company redeemed the remaining 180,000 shares on March 1, 1994 at
- ---------
$100 per share. Capital stock expense of $1.4 million was charged against
retained earnings in connection with the redemption of the Series R Preferred
Stock in 1994.
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.
SERIES V. The Series V is subject to a mandatory sinking fund sufficient to
- ---------
redeem on each March 1 beginning in 2004 to and including 2008, 12,500 shares at
$100 per share and on March 1, 2009, the balance of the outstanding shares. The
Company has the option to redeem up to an additional 12,500 shares on the same
terms and dates as applicable to the mandatory sinking fund.
Based on an estimated dividend rate at year-end 1994 of 7.50% for Preferred
Stock, subject to mandatory redemption, with similar terms and average
maturities (8.65 years), the fair value of the Company's Preferred Stock,
subject to mandatory redemption, is approximately $54 million at December 31,
1994.
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.
70
Note 8. Common Stock
At December 31, 1994, there were 50,000,000 shares of $5 par value Common Stock
authorized, of which 37,669,963 were outstanding. No shares of Common Stock are
reserved for options, warrants, conversions, or other rights. There were
549,135 shares of Common Stock reserved and unissued for shareholders under the
Automatic Dividend Reinvestment and Stock Purchase Plan and 138,870 shares
reserved and unissued for employees under the RG&E Savings Plus Plan.
Capital stock expense increased in 1992 and 1993 primarily due to expenses
associated with the public sale of Common Stock. Redemption of the Company's
8.25% Preferred Stock, Series R, decreased capital stock expense by $0.9 million
in 1993 and $1.4 million in 1994.
COMMON STOCK
PER SHARES AMOUNT
SHARE OUTSTANDING (THOUSANDS)
------ ----------- -----------
Balance, January 1, 1992 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
Decrease (Increase) in
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
Decrease (Increase) in
Capital Stock Expense (615)
----------- -----------
Balance, December 31, 1993 36,911,265 $ 652,172
Automatic Dividend Reinvestment 20.313-
and Stock Purchase Plan 25.088 644,478 14,797
Savings Plus Plan 20.313-
24.875 114,220 2,572
Decrease (Increase) in
Capital Stock Expense 1,028
---------- ----------
Balance, December 31, 1994 37,669,963 $ 670,569
71
NOTE 9. SHORT TERM DEBT
At December 31, 1994 and December 31, 1993, the Company had short term debt
outstanding of $51.6 million and $68.1 million, respectively. The weighted
average interest rate on short term debt outstanding at year end 1994 was 6.01%
and was 4.50% for borrowings during the year. For 1993, the weighted average
interest rate on short term debt outstanding at year end was 3.46% and was 3.48%
for borrowings during the year.
The Company has a $90 million revolving credit agreement for a term of three
years. In November of 1994 the Company was granted a one-year extension of the
commitment termination date to December 31, 1997. Commitment fees related to
this facility amounted to $169,000 per year in 1994, 1993, and 1992.
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, 1994, the Company would be able to incur $37.5 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.
The Company has entered into a Loan and Security Agreement to provide for
borrowings up to $30 million for the exclusive purpose of financing Federal
Energy Regulatory Commission (FERC) Order 636 transition costs(636 Notes) and up
to $20 million as needed from time to time for other working capital needs
(Secured Notes). Borrowings under this agreement, which can be renewed
annually, are secured by a lien on the Company's accounts receivable.
Additional unsecured lines of credit totaling $72 million (Unsecured Notes) are
also available from several other banks, at their discretion.
At December 31, 1994, borrowings outstanding were $18.7 million of 636 Notes
(recorded on the Balance Sheet as a deferred credit), $19.6 million of Secured
Notes, and $32.0 million of Unsecured Notes.
72
NOTE 10. COMMITMENTS AND OTHER MATTERS
CAPITAL EXPENDITURES.
The Company's 1995 construction expenditures program is currently
estimated at $132 million, including $30 million related to replacement of the
steam generators at the Ginna Nuclear Plant. The Company has entered into
certain commitments for purchase of materials and equipment in connection with
that program.
NUCLEAR-RELATED MATTERS.
DECOMMISSIONING TRUST. The Company is 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.
Under accounting procedures approved by the PSC, the Company has
collected approximately $70.1 million through December 31, 1994. In connection
with the Company's rate settlement completed in August 1993, the PSC approved
the collection during the rate year ending June 30, 1995 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 $163.0 million for
Ginna and $37.1 million for the Company's 14% share of Nine Mile Two (January
1994 dollars). This estimate is based principally on the application of a
Nuclear Regulatory Commission (NRC) formula to determine minimum funding with an
additional allowance for removal of non-contaminated structures. 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 believes that decommissioning costs are likely to exceed these
estimates but is unable to predict the costs at this time. The Company
currently anticipates performing a site specific cost analysis of
decommissioning at Ginna during 1995.
The NRC requires reactor licensees to submit funding plans that
establish minimum NRC external funding levels for reactor decommissioning. The
Company's plan, filed in 1990, consists of an external decommissioning trust
fund covering both its Ginna Plant and its Nine Mile Two share. The Company is
depositing in an external decommissioning trust the amount of the NRC minimum
funding requirement only. Since 1990, the Company has contributed $45.7 million
to this fund and, including investment returns, the fund has a balance of $49.0
million as of December 31, 1994. The amount attributed to the allowance for
removal of non-contaminated structures is being held in an internal reserve.
The internal reserve balance as of December 31, 1994 is $24.4 million.
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
73
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.
The Staff of the Securities and Exchange Commission and the Financial
Accounting Standards Board are currently studying the recognition, measurement
and classification of decommissioning costs for nuclear generating stations in
the financial statements of electric utilities. If current accounting practices
for such costs were changed, the annual provisions for decommissioning costs
would increase, the estimated cost for decommissioning could be reclassified as
a liability rather than as accumulated depreciation and trust fund income from
the external decommissioning trusts could be reported as investment income
rather than as a reduction to decommissioning expense. If annual
decommissioning costs increased, the Company would defer the effects of such
costs pending disposition by the Public Service Commission.
URANIUM ENRICHMENT DECONTAMINATION AND DECOMMISSIONING FUND. As part
of the National Energy Act (Energy 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 $22.1
million, excluding inflation and interest. The first installment of $1.6
million was paid in 1993. The Company made the second of 15 payments for this
purpose in April 1994, remitting approximately $1.4 million. The third of 15
payments (approximately $1.5 million) was made in October 1994. A liability has
been recognized on the financial statements along with a corresponding
regulatory asset. For the two facilities the Company's liability at December
31, 1994 is $18.5 million ($16.9 million as a long-term liability and $1.6
million as a current liability). In October 1993, the Company began recovery of
this deferral through its fuel adjustment clause. The Company believes that the
full amount of the assessment will be recoverable in rates as described in the
Energy Act.
NUCLEAR FUEL DISPOSAL COSTS. The Nuclear Waste Policy Act (Nuclear
Waste Act) of 1982, as amended, requires the United States Department of Energy
(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 by the Company in
June 1985. The Company estimates the fees, including accrued interest, owed to
the DOE to be $70.9 million at December 31, 1994. The Company is allowed by the
PSC to recover these costs in rates. The estimated fees are classified as a
long-term liability and interest is accrued at the current three-month Treasury
bill rate, adjusted
74
quarterly. The Act also requires the DOE to provide for the disposal of nuclear
fuel irradiated after April 6, 1983, for a charge of one mill ($.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.
SPENT NUCLEAR FUEL LITIGATION. The Nuclear Waste Act obligates the
DOE to accept for disposal spent nuclear fuel ("SNF") starting in 1998. Since
the mid-1980s the Company and other nuclear plant owners and operators have paid
substantial fees to the DOE for the disposal of SNF. DOE has indicated that it
may not be in a position to accept SNF in 1998. On June 20, 1994, Northern
States Power Company and other owners and operators of nuclear power plants
filed suit against DOE and the U.S. in the U.S. Court of Appeals for the
District of Columbia Circuit asking for a declaration that DOE is not acting in
accordance with law, seeking orders directing DOE to submit to the Court a
description of and progress reports on a program to begin acceptance of SNF by
1998, and requesting other relief at appropriate times including an order
allowing petitioners to pay fees into an escrow fund rather than to DOE. The
Company has joined Northern States and the other petitioners in this litigation.
On September 9, 1994, the DOE responded to the petition by filing a motion to
dismiss stating that (1) the petition was premature, (2) it has taken no "final"
action that would be subject to review and (3) any injury suffered as a result
of its failure to begin spent fuel acceptance in 1998 is too speculative. On
September 30, 1994, the petitioners filed their opposition to the DOE's motion.
On October 14, 1994, DOE filed its reply to the petitioners' opposition.
NUCLEAR FUEL ENRICHMENT SERVICES. The Company has a contract with the
United States Enrichment Corporation (USEC), formerly part of the DOE, for
nuclear fuel enrichment services which assures provision for 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 and 2004. 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. Negotiations are underway with
Urenco, a European enrichment facility to fill all or part of the unfilled
enrichment services through 2002. The estimated cost of enrichment services
utilized for the next seven years (priced at the most current rates) is expected
to be $6 million in 1995 and ranges from $10 million to $13 million every 18
months thereafter.
75
INSURANCE PROGRAM. The Price-Anderson Act establishes a Federal
program insuring against public liability in the event of a nuclear accident at
a licensed U.S. reactor. 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 $79.3 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 a surcharge for New
York State premium taxes. The Company's interests in two nuclear units could
thus expose it to a potential liability for each accident of $90.4 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.
Claims alleging radiation-induced injuries to workers at nuclear
reactor sites 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. If an
insuring program's losses exceeded its other resources available to pay claims,
the Company could be subject to maximum assessments in any one policy year of
approximately $5.0 million and $19.5 million in the event of losses under the
replacement power and property damage coverages, respectively.
NON-UTILITY GENERATING CONTRACT. Under Federal and New York State
laws and regulations, the Company is required to purchase the electrical output
of unregulated cogeneration facilities which meet certain criteria (Qualifying
Facilities). With the exception of one contract which the Company was compelled
by regulators to enter into with Kamine/Besicorp Allegany L.P. (Kamine) for
approximately 55 megawatts of capacity, the Company has no other long-term
obligations to purchase energy from Qualifying Facilities.
Under State law and regulatory requirements in effect at the time the
contract with Kamine was negotiated, the Company was required to pay Kamine a
price for power that is substantially greater than the Company's own cost of
production and other purchases. Since that time the State law mandating a
minimum price higher than the Company's own costs has been repealed and PSC
estimates of future prices on which the contract was based have declined
dramatically.
76
In September 1994, the Company filed a lawsuit against Kamine seeking
to void its contract for the forced purchase of unneeded electricity at above-
market prices which would result in substantial cost increases for the Company's
customers. The Company estimates that Kamine will owe the Company $400 million
by the midpoint of the contract term and if the contract extends to its full 25
year term, the total amount of such overpayments (plus interest) could reach
approximately $700 million. Alternatively, the Company sought relief to ensure
that its customers would pay no more for the Kamine power than they would pay
for power from the Company's other sources of electricity. Kamine answered the
Company's complaint, seeking to force the Company to take and pay for power at
the above-market rates and claiming damages in an unspecified amount alleged to
have been caused by the Company's conduct. The Company is unable to predict the
ultimate outcome of this litigation. The Company began receiving test
generation from the Kamine facility during the last quarter of 1994. In late
December 1994, the Company announced it would no longer be accepting electric
power from this facility because it is the Company's position, in addition to
other beliefs, that the Kamine facility is no longer a "Qualifying Facility" as
specified under Federal regulations.
On January 27, 1995, Kamine initiated a lawsuit against the Company in
Federal District Court for the Western District of New York for alleged anti-
trust violations by the Company that are based on the same issues that are
raised by the Company's New York State Court lawsuit. The Kamine lawsuit seeks
injunctive relief similar to that requested in Kamine's answer to the Company's
lawsuit in New York State Court and damages of $420 million. The Company
intends to vigorously defend against this lawsuit, but is unable to predict the
outcome at this time.
ENVIRONMENTAL MATTERS.
The following table lists various sites where past waste handling and
disposal has or may have occurred that are discussed below:
Estimated
Site Name Location Company Cost
- --------- -------- ------------
COMPANY-OWNED SITES:
West Station Rochester, NY Ultimate costs have
East Station Rochester, NY not been determined.
Front Street Rochester, NY The Company has
Brewer Street Rochester, NY incurred aggregate
Brooks Avenue Rochester, NY costs for these sites
Canandaigua Canandaigua, NY through December 31,
1994 of $2.5 million.
77
SUPERFUND AND OTHER SITES:
Quanta Resources* Syracuse, NY Ultimate costs have
Frontier Chemical not been determined.
Pendleton* Pendleton, NY The Company has
Maxey Flats* Morehead, KY incurred aggregate
Mexico Milk Mexico, NY costs for these sites
Byron Barrel and Drum Bergen, NY through December 31,
Fulton Terminals* Oswego, NY 1994 of $0.2 million.
PAS of Oswego* Oswego, NY
* orders on consent signed.
COMPANY-OWNED WASTE SITE ACTIVITIES. As part of its commitment to
environmental excellence, the Company is conducting proactive Site Investigation
and/or Remediation (SIR) efforts at six Company-owned sites where past waste
handling and disposal may have occurred. Remediation activities at three of
these sites are in various stages of planning or completion and the Company is
conducting a program to restore, as necessary to meet environmental standards,
the other three sites. The Company anticipates spending $10 million over the
next five years on SIR initiatives. Approximately $4.5 million has been
provided for in rates through June 1996 ($1.5 million annually) 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.
The Company owns, and was the prior owner or operator of, a number of
locations within the vicinity of the Lower Falls of the Genesee River, which had
been identified by the New York State Department of Environmental Conservation
(NYSDEC). The preceding paragraph includes references to Company owned property
in this vicinity. 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 manufactured gas plant sites within the larger, original site once
the State of New York adopts new Federal hazardous waste criteria. These
manufactured gas plant sites make up three of the six sites referenced in the
previous paragraph. There is at least some material at one of the individual
manufactured gas plant sites that could trigger relisting. The Company is
unable to predict what further listing action NYSDEC may take.
As already mentioned, the Company and its predecessors formerly owned
and operated three manufactured gas facilities within the Lower Falls area. In
September 1991, the Company initiated a study of
78
subsurface conditions in the vicinity of retired facilities at its West Station
manufactured gas property and has since commenced the removal of soils
containing hazardous substances in order to minimize any potential long-term
exposure risks. Cleanup efforts have been temporarily suspended while the
Company investigates more cost effective remedial technologies. The Company has
obtained a research permit (including an air permit) in order to evaluate the
burning of material from its West Station property in a coal-fired boiler as a
possible disposal strategy. At the second of the three manufactured gas plant
sites known as East Station, an interim remedial action was undertaken in late
1993. Groundwater monitoring wells were also installed to assess the quality of
the groundwater at this location. The Company has informed the NYSDEC of the
results of the samples taken. These results may indicate that some further
action may be required.
At the third Lower Falls area property owned by the Company (Front
Street) where gas manufacturing took place, a boring placed in Fall 1988 for a
sewer system project showed a layer containing a black viscous material. The
study of the layer 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 since the report's submittal.
The Company is formulating plans for long term management of the site.
Another property owned by the Company where gas manufacturing took
place is located in Canandaigua, New York. No residues of the former gas
production operations have been discovered there, although investigative work
has been limited to date.
On another portion of the Company's property in the Lower Falls
(Brewer Street), 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 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
79
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 an existing 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 most recent 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 an inactive hazardous waste disposal
site. The Company is unable to assess what implications the NYSDEC letter may
have for the County's claim against it.
Monitoring wells installed at another Company facility (Brooks Avenue)
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. In December 1994, the NYSDEC granted a permit for the storage of
hazardous wastes at this location. Conditions of the permit require additional
investigation and corrective action of the hazardous constituents at the site.
It is estimated that such investigations may cost approximately $100,000. The
cost of corrective actions cannot be determined until investigations are
completed.
SUPERFUND AND OTHER SITES. The Company has been or may be associated
as a potentially responsible party (PRP) at seven sites not owned by it, but for
which the Company has been identified as a PRP. The Company has signed orders
on consent for five of these sites and recorded estimated liabilities totaling
approximately $0.8 million.
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 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 and has signed a consent
order to that effect. The Company, in the lower tier of PRPs, paid its $27,500
share of such cost. Although the NYSDEC has not yet made an assessment for
certain response and investigation costs it has
80
incurred at the site, nor is there as yet any information on which to determine
the cost to design and conduct at the site any remedial measures which Federal
or state authorities may require, the Company does not expect its costs to
exceed $250,000.
On May 21, 1993, the Company was notified by NYSDEC that it was
considered a PRP for the Frontier Chemical Pendleton Superfund Site located in
Pendleton, NY. The Company has signed, along with other participating parties,
an Administrative Order on Consent with NYSDEC. The Order on Consent obligates
the parties to implement a work plan and remediate the site. The PRPs have
negotiated a work plan for site remediation and have retained a consulting firm
to implement the work plan. 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. In April 1994, the Company recorded an
estimated liability of $0.7 million for site remediation based on preliminary
allocation. Subsequent work has indicated that total is likely to be lower when
final.
The Company is involved in the investigation and cleanup of the Maxey
Flats Nuclear Disposal Site in Morehead, Kentucky and has signed various consent
orders to that effect. The Company has contributed to a study of the site and
estimates that its share of the cost of investigation and remediation would
approximate $205,000.
The Company has been named as a PRP at three other sites and has been
associated with another site for which the Company's share of total projected
costs is not expected to exceed $120,000. Actual Company expenditures for these
sites are dependent upon the total cost of investigation and remediation and the
ultimate determination of the Company's share of responsibility for such costs
as well as the financial viability of other identified responsible parties since
clean-up obligations are joint and several.
FEDERAL CLEAN AIR ACT AMENDMENTS. 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. A range of capital costs
between $20 million and $30 million has been estimated for the implementation of
several potential scenarios which would enable the Company to meet the
foreseeable NOx and sulphur dioxide requirements of the Amendments. These
capital costs would be incurred between 1996 and 2000. The Company estimates
that it could also incur up to $2.1 million of additional annual operating
expenses, excluding fuel, to comply with the Amendments. 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.
81
GAS COST RECOVERY.
As a result of the restructuring of the gas transportation industry by
the Federal Energy Regulatory Commission (FERC) pursuant to Order No. 636 and
related decisions, there will be a number of changes in this aspect of the
Company's business over the next several years. These changes will require the
Company to pay a share of certain transition costs incurred by the pipelines as
a result of the FERC-ordered industry 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 $44 and $52 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 and
subsequently paid by the Company. The Company has entered into a $30 million
credit agreement with a domestic bank to provide funds for the Company's
transition cost liability to CNG. At December 31, 1994 the Company had $18.7
million of borrowings outstanding under the credit agreement. The Company has
begun collecting those costs through the Gas Clause Adjustment (GCA) in its
rates.
The Company is committed to transportation capacity on the Empire
State Pipeline (Empire) which commenced operation in November 1993, as well as
to upstream pipeline transportation and storage services. The Company also has
contractual obligations with CNG and upstream pipelines whereby the Company is
subject to charges for transportation and storage services for a period
extending to the year 2001. The combined CNG and Empire transportation capacity
exceeds the Company's current requirements. This temporary excess has occurred
largely due to the Company's initiatives to diversify its supply of gas and the
industry changes and increasing competition resulting from the implementation of
FERC Order 636.
Under FERC rules, the Company may transfer its excess transportation
capacity in the market. The Company is attempting to do that, whenever
possible. The Company also 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. While
CNG has already secured letters of intent for a substantial portion of such
capacity and has ordered compressors and other related equipment associated with
the planned modifications to CNG's pipeline, whether and to what extent CNG
and/or the Company can successfully negotiate the assignment of the excess
capacity, or at what price, cannot be determined at the present time. The
ability of CNG to market this capacity may depend on FERC approval of rolled-in
(rather than incremental) rate treatment for the CNG new facility costs
necessary to serve the letter of intent customers. Several CNG customers have
protested CNG's proposed rolled-in rate treatment, arguing that such costs
should be borne as incremental by the letter of intent customers. The FERC has
issued a preliminary determination on non-environmental issues in which they
82
concluded that it would be in the public interest to authorize construction and
operation of the proposed facilities. Subsequent to the protests filed in
response to the proposed rolled-in rate treatment of the facility costs, the
Company entered into an amended and restated marketing agreement with CNG. As a
result of this agreement and the negotiations surrounding its implementation,
CNG is prepared to file a settlement agreement with the FERC, reflecting certain
changes in the facilities and their cost. The impact of the changes on rates is
favorable to the approval of rolled-in treatment of the facility costs. As a
result, the Company anticipates that there will not be significant objection to
the settlement, however, the timing of the FERC decision on the settlement and
with respect to environmental issues cannot be determined at the present time
and that decision is necessary to implement the permanent assignment of the
excess capacity. The Company has also exercised its option to postpone for one
year the commencement of certain Empire-related transportation service that was
scheduled for November 1994. The Company will continue to pursue other options
for the release of the capacity.
A reconciliation of gas costs incurred and gas costs billed to
customers is done annually, as of August 31, and the excess or deficiency is
refunded to or recovered from customers during a subsequent period. In October
1994, the Company submitted to the PSC its annual GCA reconciliation providing
for recovery of $24 million of deferred gas costs, which was substantially
higher than in previous years principally due to factors mentioned above.
The Staff of the PSC has reviewed the Company's application for
recovery of deferred costs and the Consumer Protection Board, along with certain
individuals or groups of ratepayers, has requested that the PSC conduct hearings
to determine whether and on what terms the deferral should be recovered. On
December 19, 1994, the PSC instituted a proceeding to review the Company's
practices regarding acquisition of pipeline capacity, the deferred costs of the
capacity and the Company's recovery of those costs. The costs included in the
deferral have ordinarily been recovered in the past and the Company believes
that they should be recovered in this instance; however, it is possible that
with respect to these costs, the PSC may not recognize all of them in rates. If
that were to occur, the Company would be compelled to discontinue deferring and
recovering costs above the allowed amount, and would recognize the disallowed
costs as they were incurred as a charge against earnings. In addition, in a
more adverse decision, the PSC could order the Company to refund a portion of
such costs previously collected from ratepayers. Pending conclusion of the
proceeding, the PSC directed the Company to recover Order 636 transition costs
over a five-year period and all other unrecovered gas costs over 18 months.
As an interim measure, on February 1, 1995 the PSC directed the
Company to remove from existing rates $16 million of gas revenues representing a
portion of the costs attributable to excess capacity over the remaining term of
the contracts. Prospective capacity release credits obtained by the Company are
to be used to offset such amounts.
83
These deferred costs are subject to recovery by the Company from customers,
with interest, to the extent the Company's actions are found prudent.
The Company cannot predict to what extent the deferred costs described
above would be recoverable in rates.
The Company's purchased gas expense charged to customers will be
higher during the 1994-95 heating season for the reasons described above. In
addition, beginning in January 1995 and continuing until May 1995, the Company
elected to discontinue the operation of its weather normalization clause (see
Note 1) in circumstances where the weather is warmer than normal because of the
unusually mild weather that has been experienced in its service territory and
the adverse effects on customer bills. The earnings impact of this decision in
1995 will range between $3.5 and $8.7 million depending on the duration of mild
weather for the heating season.
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. Of the total
undercharges, $2.3 million had previously been expensed and $5.2 million had
been deferred on the Company's balance sheet. In March 1994, the PSC approved a
December 1993 settlement among the Company, PSC Staff and another party
providing for the recovery in rates of $2.6 million over three years. The
Company wrote off $2.0 million of the undercharges as of December 31, 1993,
reducing 1993 earnings by four cents per share, net of tax. In April 1994, the
Company wrote off an additional $0.6 million reducing 1994 earnings by
approximately one cent per share, net of tax. Due to rate increase limitations
established for the second year of the rate settlement, the Company is precluded
from recovering the undercharges until the third year of the rate settlement,
which begins July 1, 1995.
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 is 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 the appeals officers have indicated a decision may be
forthcoming on the service year issue in 1995. The Company
84
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.
The IRS has also completed in 1994 its audit of the Company's Federal
income tax returns for 1989 and 1990, which has resulted in a proposed refund of
$600,000. Since this refund arises from the contentious issues from the prior
audit, the Company has filed a protest with the IRS.
REGULATORY AND STRANDED ASSETS.
Certain costs are deferred and recognized as expenses when they are
reflected in rates and recovered from customers as permitted by Statement of
Financial Accounting Standard No. 71, "Accounting of the Effects of Certain
Types of Regulation". These costs are shown as Regulatory Assets. Such costs
arise from the traditional cost-of-service rate setting approach where all
prudently incurred costs are recoverable through rates. Deferral of these costs
is appropriate while the Company's rates are regulated under a cost-of-service
approach.
In a purely competitive pricing approach, such costs might not have
been incurred or deferred. Accordingly, if the Company's rate setting were
changed from a cost-of-service approach and it was no longer allowed to defer
these costs under SFAS 71, certain of these assets may not be fully recoverable.
Below is a summarization of the Regulatory Assets as of December 31,
1994.
Millions
of dollars
----------
Income Taxes $205.8
Deferred Ice Storm Charges 19.1
Uranium Enrichment Decommissioning Deferral 20.2
FERC 636 Transition Costs 32.5
Demand Side Management Costs Deferred 19.8
Deferred Fuel Costs - Gas 33.8
Other, net 33.7
--------
Total - Regulatory Assets $364.9
========
- Income Taxes: This amount represents the unrecovered portion of tax
benefits from accelerated depreciation and other timing differences
which were used to reduce tax expense in past years. The recovery
of this deferral is anticipated when the effect of the past
deductions reverses in future years.
85
- Deferred Ice Storm Charges: These costs result from the non-capital
storm damage repair costs following the March 1991 ice storm.
- Uranium Enrichment Decommissioning Deferral: This amount is
mandated to be paid to DOE over the next 13 years. The Energy
Policy Act of 1992 requires utilities to contribute such amounts
based on the amount of uranium enriched by DOE for each utility.
- FERC 636 Transition Costs: These costs are payable to gas supply
and pipeline companies which are passing various restructuring and
other transition costs on to the Company, as ordered by FERC.
- Demand Side Management Costs Deferred: These costs are Demand Side
Management costs which relate to programs initiated to increase
efficiency with which electricity is used.
- Deferred Fuel Costs - Gas: These costs are recoverable over future
years and arise from an annual reconciliation of gas revenues and
costs (as described in Note 1).
Stranded assets (or other costs) arise when investments are made in
facilities or costs are incurred to serve customers and such costs may not be
fully recoverable in rates. Examples include purchase power contracts (i.e.,
the Kamine contract) or uneconomic generating assets.
Excluding the Kamine contract described above, estimates of stranded
asset costs are highly sensitive to the competitive wholesale price assumed in
the estimation for electricity. The amount of stranded assets at December 31,
1994, cannot be determined at this time but could be significant.
While the Company currently believes that its regulatory and stranded
assets are probable of recovery in rates, industry trends have moved more toward
competition, and in a purely competitive environment, it is not clear to what
extent, if any, writeoffs of such assets may occur.
86
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, 1994 $ 243,697 $ 42,249 $ 25,618 $ 23,751 $ .63
September 30, 1994 * 229,982 41,007 4,912 3,046 .08
June 30, 1994 217,083 24,578 9,608 7,742 .20
March 31, 1994 310,052 47,178 34,237 32,467 .87
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
* Includes recognition of $21.9 million net-of-tax pension
plan curtailment
** 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
Item 9. Changes in and Disagreements with Accountants and Financial Disclosure.
None.
87
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 18, 1995, 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.
Registrant's definitive proxy statement dated March 6, 1995 will be filed with
the Securities and Exchange Commission prior to April 30, 1995. The information
required in Items 10 through 13 under the headings set forth above is
incorporated 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 18, 1995 is not deemed to be filed as
part of this Report.
88
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, 1994
Consolidated Balance Sheets at December 31, 1994 and 1993
Consolidated Statement of Cash Flows for each of the three years
ended December 31, 1994
Notes to Consolidated Financial Statements
(a) 2. Financial Statement Schedules - Included in Item 14 herein:
For each of the three years ended December 31, 1994
Schedule II - Valuation and Qualifying Accounts
(a) 3. Exhibits - See List of Exhibits
(b) Reports on Form 8-K:
The Company filed a Form 8-K, dated February 10, 1995 reporting under
Item 5. Other Events, information relating to gas cost recovery and
also cogeneration contract litigation.
89
ROCHESTER GAS AND ELECTRIC CORPORATION
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
(THOUSANDS OF DOLLARS)
FOR THE YEAR ENDED DECEMBER 31, 1992
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
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
FOR THE YEAR ENDED DECEMBER 31, 1994
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 $ 600 $ 350 $ 950
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, in 1993 was $6,241 and in 1994 was $9,000.
90
LIST OF 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* - Certificate of Amendment of the Certificate of
Incorporation of Rochester Gas and Electric
Corporation Under Section 805 of the Business
Corporation Law filed with the Secretary of
State of the State of New York on March 18,
1994. (Filed as Exhibit 4 in May 1994 on Form
10-Q for the quarter ended March 31, 1994, SEC
File No. 1-672.)
Exhibit 3-3* - By-Laws of the Company, as amended to date.
(Filed as Exhibit 3-2 in February 1994 on Form
10-K for the year ended December 31, 1993, SEC
File No. 1-672-2)
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)
Exhibit 4-2* - Certificate of Amendment of the Certificate of
Incorporation of Rochester Gas and Electric
Corporation Under Section 805 of the Business
Corporation Law filed with the Secretary of
State of the State of New York on March 18,
1994. (Filed as Exhibit 4 in May 1994 on Form
10-Q for the quarter ended March 31, 1994, SEC
File No. 1-672.)
Exhibit 4-3* - By-Laws of the Company, as amended to date.
(Filed as Exhibit 3-2 in February 1994 on Form
10-K for the year ended December 31, 1993, SEC
File No. 1-672-2)
Exhibit 4-4* - 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 4-5* - Supplemental Indenture, dated as of March 1,
1983 between the Company and Bankers Trust
Company, as Trustee (Filed as Exhibit 4-1 on
91
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, as amended to date.
Exhibit 10-4* - 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 10-5* - 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 10-6* - 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 10-7* - 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)
(A) Exhibit 10-8* - Rochester Gas and Electric Corporation Deferred
Compensation Plan. (Filed as Exhibit 10-14 in
February 1994 on Form 10-K for the year ended
December 31, 1993, SEC File No. 1-672-2)
(A) Exhibit 10-9 - Rochester Gas and Electric Corporation
Executive Incentive Plan, Restatement of
January 1, 1994.
(A) Exhibit 10-10 - Rochester Gas and Electric Corporation Long
Term Incentive Plan, Restatement of January 1,
1994.
Exhibit 23 - Consent of Price Waterhouse, independent
accountants
92
Exhibit 27 - Financial Date Schedule, pursuant to Item
601(c) of Regulation S-K.
* Incorporated by reference.
(A) Denotes executive compensation plans and arrangements.
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.
93
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 /s/ ROGER W. KOBER
-------------------------------------
(Roger W. Kober)
(Chairman of the Board, President
and Chief Executive Officer)
Date: February 16, 1995
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:
/s/ ROGER W. KOBER Chairman of the Board, February 16, 1995
- ------------------------------
(Roger W. Kober) President and Chief
Executive Officer
Principal Financial Officer:
/s/ THOMAS S. RICHARDS Senior Vice President, February 16, 1995
- ------------------------------
(Thomas S. Richards) Corporate Services and
General Counsel
Principal Accounting Officer:
/s/ DANIEL J. BAIER Controller February 16, 1995
- ------------------------------
(Daniel J. Baier)
94
SIGNATURE TITLE DATE
DIRECTORS:
WILLIAM BALDERSTON III Director February 16, 1995
- ----------------------------------
(William Balderston III)
ANGELO J. CHIARELLA Director February 16, 1995
- ----------------------------------
(Angelo J. Chiarella)
ALLAN E. DUGAN Director February 16, 1995
- ---------------------------------
(Allan E. Dugan)
WILLIAM F. FOWBLE Director February 16, 1995
- ----------------------------------
(William F. Fowble)
JAY T. HOLMES Director February 16, 1995
- ----------------------------------
(Jay T. Holmes)
ROGER W. KOBER Director February 16, 1995
- ----------------------------------
(Roger W. Kober)
DAVID K. LANIAK Director February 16, 1995
- ----------------------------------
(David K. Laniak)
THEODORE L. LEVINSON Director February 16, 1995
- ----------------------------------
(Theodore L. Levinson)
CONSTANCE M. MITCHELL Director February 16, 1995
- ----------------------------------
(Constance M. Mitchell)
CORNELIUS J. MURPHY Director February 16, 1995
- ----------------------------------
(Cornelius J. Murphy)
ARTHUR M. RICHARDSON Director February 16, 1995
- ----------------------------------
(Arthur M. Richardson)
M. RICHARD ROSE Director February 16, 1995
- ----------------------------------
(M. Richard Rose)