Back to GetFilings.com
NEW YORK STATE ELECTRIC & GAS CORPORATION
(Registrant)
FORM 10-K
---------
ANNUAL REPORT
For Fiscal Year Ended December 31, 1994
To
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
TABLE OF CONTENTS
Page
PART I
Item 1. Business
(a) General development of business. . . . . . . . . 3
Rates and regulatory matters . . . . . . . . . . 3
Diversification. . . . . . . . . . . . . . . . . 5
(b) Financial information about industry segments . . 6
(c) Narrative description of business
Principal business . . . . . . . . . . . . . . . 6
New product or segment . . . . . . . . . . . . . 9
Sources and availability of raw materials. . . 9
Franchises . . . . . . . . . . . . . . . . . . .10
Seasonal business. . . . . . . . . . . . . . . .10
Working capital items. . . . . . . . . . . . . .11
Single customer. . . . . . . . . . . . . . . . .11
Backlog of orders. . . . . . . . . . . . . . . .11
Business subject to renegotiation. . . . . . . .11
Competitive conditions . . . . . . . . . . . . .11
Research and development . . . . . . . . . . . .14
Environmental matters. . . . . . . . . . . . . .14
Water quality. . . . . . . . . . . . . . . . .15
Air quality. . . . . . . . . . . . . . . . . .15
Waste disposal . . . . . . . . . . . . . . . .17
Number of employees. . . . . . . . . . . . . . .19
(d) Financial information about foreign and domestic
operations and export sales. . . . . . . . . .19
Item 2. Properties . . . . . . . . . . . . . . . . . . . . .20
Item 3. Legal proceedings. . . . . . . . . . . . . . . . . .21
Item 4. Submission of matters to a vote of security holders.26
Executive officers of the Registrant . . . . . . . . . . . . .26
PART II
Item 5. Market for Registrant's common stock and related
stockholder matters. . . . . . . . . . . . . . . .27
Item 6. Selected financial data. . . . . . . . . . . . . . .28
Principal sources of electric and natural gas revenues . . . .28
Item 7. Management's discussion and analysis of financial
condition and results of operations. . . . . . . .29
TABLE OF CONTENTS (Cont'd)
Page
Item 8. Financial statements and supplementary data. . . . .48
Financial Statements
Consolidated Balance Sheets. . . . . . . . . . . .48
Consolidated Statements of Income. . . . . . . . .50
Consolidated Statements of Cash Flows. . . . . . .51
Consolidated Statements of Changes in
Common Stock Equity. . . . . . . . . . . . . . .52
Notes to Consolidated Financial Statements . . . . .53
Report of Independent Accountants. . . . . . . . . .80
Financial Statement Schedules
II. Allowance for Doubtful Accounts-Accounts
Receivable . . . . . . . . . . . . . . . .81
Item 9. Changes in and disagreements with accountants on
accounting and financial disclosure. . . . . . . .82
PART III
Item 10. Directors and executive officers of the Registrant .82
Item 11. Executive compensation . . . . . . . . . . . . . . .82
Item 12. Security ownership of certain beneficial owners
and management . . . . . . . . . . . . . . . . . .82
Item 13. Certain relationships and related transactions . . .82
PART IV
Item 14. Exhibits, financial statement schedules, and
reports on Form 8-K
(a) List of documents filed as part of this report
Financial statements . . . . . . . . . . . . .82
Financial statement schedules. . . . . . . . .82
Exhibits
Exhibits delivered with this report. . . . .83
Exhibits incorporated herein by reference. .83
(b) Reports on Form 8-K. . . . . . . . . . . . . . .88
Signatures . . . . . . . . . . . . . . . . . . . . . . . . . .89
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.
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 .
Commission file number 1-3103-2.
NEW YORK STATE ELECTRIC & GAS CORPORATION
(Exact name of Registrant as specified in its charter)
New York 15-0398550
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
P. O. Box 3287, Ithaca, New York 14852-3287
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (607) 347-4131
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange on
Title of each class which registered
First Mortgage Bonds, 7 5/8% Series
due 2001 (Due November 1, 2001) New York Stock Exchange
First Mortgage Bonds, 8 5/8% Series
due 2007 (Due November 1, 2007) New York Stock Exchange
3.75% Cumulative Preferred Stock
(Par Value $100) New York Stock Exchange
7.40% Cumulative Preferred Stock
(Par Value $25) New York Stock Exchange
Adjustable Rate Cumulative Preferred
Stock, Series B (Par Value $25) New York Stock Exchange
Common Stock (Par Value $6.66 2/3) 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:
Title of Class
4 1/2% Cumulative Preferred Stock (Series 1949) (Par Value $100)
4.15% Cumulative Preferred Stock (Par Value $100)
4.40% Cumulative Preferred Stock (Par Value $100)
4.15% Cumulative Preferred Stock (Series 1954) (Par Value $100)
* * * * * * * * * * *
Indicate by check mark whether the Registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months
(or for such shorter period that the Registrant was required to
file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes X . No .
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of Regulation S-K is not contained herein,
and will not be contained, to the best of Registrant's knowledge,
in definitive proxy or information statements incorporated by
reference in Part III of this Form 10-K or any amendment to this
Form 10-K [ ].
* * * * * * * * * * *
The aggregate market value as of February 28, 1995 of the
common stock held by non-affiliates of the Registrant was
$1,537,310,781.
Common stock - 71,502,827 shares outstanding as of February
28, 1995.
DOCUMENTS INCORPORATED BY REFERENCE
Document 10-K Part
The company has incorporated by reference
certain portions of its Proxy Statement
dated March 31, 1995 which will be filed
with the Commission prior to April 30, 1995. III
PART I
Item 1. Business
(a) General development of business
New York State Electric & Gas Corporation (company) was
organized under the laws of the State of New York in 1852.
The following general developments have occurred in the
business of the company since January 1, 1994:
Rates and regulatory matters
(See Item 1(c)(i) - Principal business and 1(c)(x) - Competitive
conditions.)
Rate Matters
In September 1993 the company reached a three-year electric
and natural gas rate-settlement agreement (Agreement) with the
Public Service Commission of the State of New York (PSC) covering
the period August 1, 1993 through July 31, 1996. Under the
Agreement, the allowed return on equity was 10.8% in year one,
11.4% in year two and 11.4% (subject to an indexing mechanism) in
year three. Shareholders were allowed to keep 100% of any
earnings above the allowed return in year one. Shareholders and
customers are to share, on a 50%/50% basis, any earnings over the
allowed return in years two and three. The calculation of
earnings over the allowed return includes regulatory adjustments
(such as the elimination of the impact of incentives and sharing
mechanisms) and certain normalizing adjustments (such as
spreading the 1993 restructuring charge over the term of the
Agreement). For year one, the twelve months ended July 31, 1994,
the company's earned return on equity, with adjustments, as
discussed above, was 10.3%. The earned returns on electric equity
and natural gas equity, with adjustments, were 10.1% and 12.7%
respectively, for year one.
The Agreement also includes a modified revenue decoupling
mechanism (RDM) for electric sales. Rates are based on sales
forecasts. Since actual sales may differ significantly from
forecasted sales because of conservation efforts, unusual weather
or changing economic conditions, revenues collected may be more
or less than forecasted. Subject to the limits described below,
the modified RDM lets the company adjust for most of the
differences between forecasted and actual sales. For example, if
revenues exceed the forecast for a given year, the excess is
passed back to customers in a future year. If revenues are below
the forecast, customers receive a surcharge in a future year.
The company must share revenue excesses or shortfalls from sales
to most large commercial and industrial customers on a 70%/30%
(customer/shareholder) basis. In 1994 the company accrued $22.3
million under the modified RDM compared with $3.9 million in
1993. In 1993 the modified RDM covered only the period August
through December.
Customer savings of $21 million in production and
transmission operating costs are imputed over the three years of
the Agreement, at $7 million each year, whether or not such
savings are realized.
The estimated total electric price increases anticipated by
the Agreement are $99.6 million, or 7.4%, in year one; $109.5
million, or 7.6% in year two; and $87.8 million, or 5.6% in year
three. These include base rate increases plus estimated price
increases for fuel, purchased power and other costs that are
collected through the fuel adjustment clause (FAC). Actual costs
collected through the FAC could vary from estimates, causing the
total electric price increases to change.
The base rate increases for natural gas allowed by the
Agreement are $7.5 million, or 2.9%, in year one; $8.2 million,
or 3.0%, in year two; and $7.2 million, or 2.5%, in year three.
They do not include changes in natural gas costs, which will be
collected through the gas adjustment clause. Natural gas costs
can be expected to rise and fall with overall natural gas market
conditions. Such fluctuations will affect the total natural gas
price increases.
The Agreement also provides for the stated base rate
increases for electricity and natural gas to be adjusted up or
down in the second and third years, as well as the year after the
agreement period (year four). Base rates can be adjusted for
several factors, such as electric sales, incentive mechanisms and
other true-ups from the prior year. The electric base rate
increases could be adjusted upward by up to 1.5% in years two and
three and 1.6% in year four. The natural gas base rate increases
could be adjusted upward by up to 1.0% in year two and 1.2% in
year three. The Agreement does not specify a limit on the upward
adjustment for natural gas base rates for year four. There is no
limit to any downward adjustment of base rates for electric and
natural gas.
In June 1994 the company finalized its filing of adjustments
to the second-year electric and natural gas rates in accordance
with the terms of the Agreement. The company took voluntary
action to lower the estimated total electric price increase to
7.8%. The electric price increase, which was primarily due to
increases in mandated purchases of electricity from non-utility
generators (NUGs), increases in taxes and sales shortfalls
related to mandated conservation programs and the weak economy in
New York State, would have been substantially greater than 7.8%
without the voluntary action. The filed natural gas base rate
increase was 1.9%. On August 15, 1994, the PSC issued an Opinion
and Order that approved the electric price increase of 7.8% and
the 1.9% natural gas base rate increase effective August 1, 1994.
In addition, the PSC directed the company and staff of the PSC to
begin discussions on modifying the Agreement to mitigate the
projected third-year electric increase and bring rate
predictability and stability to future years. Those discussions
began in October 1994 and are continuing.
The Agreement provides incentives (rewards or penalties) to
the company for controlling production costs (PCI), improving
customer service and implementing demand-side management (DSM)
programs. Those incentives could have increased the company's
allowed return to 12.3% or decreased it to 9.95% in year one,
increase it to 13.05% or decrease it to 10.4% in year two, and
increase it to 13.25% or decrease it to 10.2% in year three. In
June 1994 the company calculated and recorded a production-cost
penalty for 1993 of $13.0 million, or 12 cents per share. This
was the maximum permitted by the Agreement.
The PCI is based on a comparison of the company with a 19-
company peer group (which includes the company). The production
measure compared is the relative change in production and certain
other costs per megawatt-hour of retail sales occurring between
the applicable calendar year and a base period (1989-1992). The
company calculated the PCI penalty for 1993 using data reported
in the peer group's Federal Energy Regulatory Commission (FERC)
Form 1 Reports, which the company received in May 1994. The
company's PCI penalty for 1993 was due primarily to a
significantly lower increase in retail sales (after adjusting for
the effect of sales lost due to DSM programs) for the company
than for the peer group. It was also due to a greater increase
in DSM program costs and purchased power costs for the company
than for the peer group.
The company believes that a penalty for its PCI performance
in 1994 is unlikely. This is primarily because of the company's
recent cost-reduction efforts and improved sales compared to the
sales increase of the peer group, which is projected to be less
than the peer group's sales increase in 1993. This estimate
includes the company's actual performance through December 31,
1994. However, it was necessary to make certain assumptions
regarding the peer group's 1994 performance since the actual
information needed for this calculation will not be available
until the peer group's FERC Form 1 Reports become available in
May 1995. As an example, retail sales units and certain
production costs for the peer group were assumed to continue at
the levels achieved through the first nine months of 1994. The
maximum PCI allowed for 1994 by the agreement is a reward or
penalty of $17.5 million, or 16 cents per share.
Diversification
Diversification will play an important role in the company's
future. The company's primary objective is to enhance the
competitiveness of its core electric and natural gas businesses.
At the same time the company is actively evaluating opportunities
for investment closely related to its core businesses that have
the potential to augment future earnings. In April 1992 the PSC
issued an order allowing the company to invest up to 5% of its
consolidated capitalization (approximately $180 million at
December 31, 1994) in one or more subsidiaries that may engage or
invest in energy-related or environmental-services businesses and
provide related services.
The company has been making investments in unregulated
companies through its wholly owned subsidiary, NGE Enterprises,
Inc. (NGE). NGE owns two unregulated businesses - EnerSoft
Corporation (EnerSoft) and XENERGY, Inc. (XENERGY).
EnerSoft, a computer software company, was formed in May
1993 to produce and market software for natural gas utilities,
marketers and pipeline operators. Through an alliance with the
New York Mercantile Exchange, EnerSoft is developing Channel 4, a
natural gas and pipeline capacity trading and information system
for the North American market. While development of the system
has taken longer than anticipated, Channel 4 is expected to be
commercially available in the spring of 1995. Like most other
start-up companies, EnerSoft has been incurring operating losses.
The company expects that EnerSoft will continue to incur
operating losses in the near term.
In June 1994 NGE acquired all of the outstanding stock of
XENERGY, an energy services, information systems and energy-
consulting company that specializes in energy management,
conservation engineering and demand-side management. XENERGY
currently provides a broad range of services to utilities
throughout the United States, Canada, Spain and France. It also
provides energy services, conservation engineering and DSM
services to governmental agencies at both the state and federal
levels, and to a large number of end users.
NGE is exploring environmental-services opportunities with
both domestic and foreign strategic partners.
As of December 31, 1994 and 1993, the company had invested
approximately $47 million and $3 million, respectively, in NGE to
finance its diversified investments. For the years ended
December 31, 1994 and 1993, NGE incurred net losses of $6.0
million and $1.4 million, respectively.
(b) Financial information about industry segments
See Note 14 to the Consolidated Financial Statements on
page 78.
(c) Narrative description of business
(i) Principal business
The company's principal business is generating, purchasing,
transmitting, and distributing electricity and purchasing,
transporting, and distributing natural gas. The service
territory, 99% of which is located outside the corporate limits
of cities, is in the central, eastern, and western parts of the
State of New York. The service territory has an area of
approximately 19,500 square miles, and a population of 2,400,000.
The larger cities in which the company serves both electricity
and natural gas are Binghamton, Elmira, Auburn, Geneva, Ithaca,
and Lockport. The company serves approximately 799,000 electric
retail customers and 231,000 natural gas retail customers. Its
service territory reflects a diversified economy, including high-
tech firms, light industry, agriculture, colleges and
universities, and recreational facilities. No customer accounts
for 5% or more of either electric or natural gas revenues. For
the years 1994, 1993, and 1992, 84%, 85%, and 86%, respectively,
of operating revenue was derived from electric service and 16%,
15%, and 14%, respectively, was derived from natural gas service.
The 1994-1995 winter peak load of 2,558 megawatts (mw), was
set on February 6, 1995. This is 53 mw less than the previous
all time peak of 2,611 mw set during the 1993-1994 winter on
January 19, 1994. Power supply capability to meet peak loads is
currently 3,284 mw. This is composed of 2,543 mw of generating
capacity (90% coal-fired, 7% nuclear, and 3% hydroelectric) and
1,108 mw of purchases offset by 367 mw of firm sales. The
purchases are composed of 594 mw from NUGs and 514 mw from the
New York Power Authority (NYPA). Most purchases from NYPA are
hydroelectric power.
On February 14, 1995, the company filed a petition with the
FERC asking for relief from having to pay approximately $2
billion more than its avoided costs for power purchased over the
life of the two NUG contracts mentioned below. The company
believes that the overpayments under these two contracts violate
the Public Utility Regulatory Policies Act of 1978 (PURPA). The
relief the company is seeking could take the form of FERC taking
any one or more of the following actions: issuing a declaratory
order deeming the overpayments to be in violation of PURPA;
taking direct action to modify the rates under the two contracts;
directing the PSC to modify the rates; revising its rules
implementing PURPA or waiving its rules implementing PURPA.
The company is currently required to purchase 594 mw of NUG
power. The company is required to make payments under these
contracts only for the power it receives or when the company
directs the NUG to reduce its output under the terms of the
contract. Two contracts the company has with NUGs each provide
more than 5% of current system capability. One contract, with
Lockport Energy Associates, L.P., provides for 177 mw or 5.4%,
and the other, with Saranac Power Partners, L.P., provides for
240 mw or 7.3%. During 1994, 1993 and 1992 the company purchased
approximately $214 million, $138 million and $71 million,
respectively, of NUG power, including termination costs. The
company estimates that NUG power purchases, excluding termination
costs, over the next five years will be as follows:
1995 1996 1997 1998 1999
(Millions)
$274 $312 $322 $333 $344
Increases in the cost of NUG power purchases will contribute
significantly to expected electric price increases in August
1995.
The company has implemented a number of DSM programs. As
part of its three-year rate agreement (See Item 1(a)-Rates and
regulatory matters - Rate Matters), the rewards the company could
earn for conducting efficient DSM programs were reduced from 15%
to 5% of the net resource savings achieved by these programs.
For 1995 the company expects to earn approximately $1 million in
rewards as a result of DSM programs.
In 1994 customers saved approximately 64 million kilowatt-
hours (kwh) on an annualized basis through DSM programs. These
programs cost $14 million in 1994 and will cost approximately $11
million in 1995. The customer savings estimated for 1995 are 54
million kwh on an annualized basis. At both December 31, 1994
and 1993, the company had approximately $73 million of deferred
DSM program costs on its consolidated balance sheets. The two-
year (1993-1994) DSM plan, which received PSC approval, was
modified to improve cost-effectiveness and reduce rate impacts.
In August 1994 the company submitted its 1995 DSM plan to the PSC
proposing DSM goals and budgets for the years 1995 through 2000.
The company expects to change its DSM approach in 1995 to move
toward promoting energy-efficient equipment in the mass market
and phasing out rebates for individual customers.
On February 6, 1995, the company experienced its 1994-1995
maximum peak daily sendout for natural gas of 400,235 dekatherms.
This is 31,521 dekatherms less than the 1993-1994 peak of 431,756
dekatherms set on January 19, 1994.
The following table provides information on the company's
estimated sources and uses of funds for 1995-1997. This forecast
is subject to periodic review and revision. Actual capital
expenditures may change to reflect the imposition of additional
regulatory requirements and the company's continued focus on
optimizing capital expenditures.
1995 1996 1997 Total
(Millions)
Sources of funds
Internal funds $298 $288 $284 $870
Long-term financing 39 - - 39
---- ---- ---- ----
Total $337 $288 $284 $909
==== ==== ==== ====
Uses of funds
Capital expenditures
Cash $185 $258 $180 $623
AFDC* 3 6 4 13
---- ---- ---- ----
Total capital
expenditures 188 264 184 636
---- ---- ---- ----
Retirement of securities and
sinking fund obligations 63 26 78 167
Repayment of
short-term debt 55 20 33 108
Working capital, deferrals
and other 31 (22) (11) (2)
---- ---- ---- ----
Total $337 $288 $284 $909
==== ==== ==== ====
*Allowance for funds used during construction.
As shown in the preceding table, internal sources of funds
represent 137% of capital expenditures for 1995-1997.
The company's 1994 capital expenditures for its core
electric and natural gas businesses totaled approximately
$248 million. Most of the expenditures were for the extension of
service, improvements at existing facilities, compliance with the
Clean Air Act Amendments of 1990, and other environmental
requirements. The company received $24 million from governmental
and other sources in 1994 to partially offset expenditures for
compliance with the Clean Air Act Amendments of 1990.
Capital expenditures projected for 1995-1997 have been
limited and reflect planned cuts of more than $200 million. This
represents one of the many actions the company is taking to
address competition (See Item 1(c)(x)- Competitive conditions).
Capital expenditures will be primarily for extension of service,
necessary improvements at existing facilities, the natural gas
storage project, referred to below, compliance with the Clean Air
Act Amendments of 1990 (1990 Amendments) and other environmental
requirements (See Item 1(c)(xii)- Environmental matters). The
company expects to finance these capital expenditures entirely
with internally generated funds. The company forecasts that its
current reserve margin, coupled with more efficient use of energy
and purchases of power from NUGs, eliminates the need for
additional generating capacity until after the year 2007.
(ii) New product or segment
(See Item 1(a)-Diversification.)
(iii) Sources and availability of raw materials
Electric
In 1994, approximately 89% of the company's generation was
coal-fired steam electric, 9% nuclear and 2% hydroelectric power.
About 39% of the company's steam electric generation in 1994 was
supplied from its one-half share of the output from the Homer
City Generating Station, which is owned in common with
Pennsylvania Electric Company. An additional 36% was supplied
from the company's Kintigh Generating Station, and the remaining
25% was supplied from its other generating stations which are
located in New York State.
Coal
Coal for the New York generating stations is obtained
primarily from Pennsylvania and West Virginia. Of the 3.4
million tons of coal purchased for the New York generating
stations in 1994, approximately 73% was purchased under
contract and the balance on the open market. Coal purchased
under contract is expected to be approximately 89% of the
estimated 3.0 million tons to be purchased in 1995.
The annual coal requirement for the Homer City
Generating Station is approximately 4.2 million tons, the
majority of which is obtained under long-term contracts.
During 1994, approximately 62% of Homer City Generating
Station coal was obtained under these contracts. The
company anticipates obtaining approximately 66% of the 1995
requirements under these contracts. The balance will be
purchased under short-term contracts and, when necessary, on
the open market.
Nuclear
During the spring of 1995, Niagara Mohawk Power
Corporation (Niagara Mohawk), the operator of the Nine Mile
Point nuclear generating unit No. 2 (NMP2), in which the
company has an 18% interest, will install reload No. 4 into
the reactor core at NMP2. This planned refueling will
support NMP2 operations through September 1996. Enrichment
services are under contract with the U.S. Enrichment
Corporation for 100% of the enrichment requirements through
1995 and 70% of the requirements through 1998. Fuel
fabrication services are under contract through 2004 .
Approximately 40% of the uranium and conversion requirements
are under contract through 1998.
Natural Gas
As a result of FERC Order 636 (See Item (x)-Competitive
conditions), the company completed a major restructuring of its
natural gas transportation, storage, and supply contracts.
Bundled pipeline sales, natural gas and transportation contracts
have been eliminated thereby giving the company greater
flexibility with respect to its supply of natural gas. The
natural gas supply mix now includes long-term, short-term, and
spot natural gas purchases transported on both firm and
interruptible transportation contracts. During 1994, about 58%
of the company's natural gas supply was purchased from various
suppliers under long-term and short-term sales contracts and 42%
on the monthly spot natural gas market to maximize natural gas
cost savings. The company's natural gas supply is expected to be
purchased in 1995 in a similar proration as described previously
for 1994.
As one response to the competitive pressures faced by its
natural gas business, the company plans to build a natural gas
storage project near Seneca Lake, north of Watkins Glen, New
York. The project, which will cost $59 million and be regulated
by the PSC, includes a storage facility and two separate
pipelines to transport the natural gas. Its primary purpose is
to ensure adequate supply to the company's core natural gas
customers. The project will also increase supply flexibility,
allow the company to retire propane plants and ultimately reduce
pipeline demand charges. The company expects to receive PSC
approval for the project and begin construction in 1995. The
storage facility is scheduled to be in service for the 1996-1997
heating season.
(iv) Franchises
(See Item 1(c)(x) - Competitive conditions.)
The company has, with minor exceptions, valid franchises
from the municipalities in which it renders service to the
public. In 1994, the company obtained PSC authorizations for
natural gas distribution service in the towns of Canaan, Junius
and Tyre.
(v) Seasonal business
Sales of electricity are highest during the winter months
primarily due to space heating usage and fewer daylight hours.
Sales of natural gas are highest during the winter months
primarily due to space heating usage.
(vi) Working capital items
The company has been granted, through the ratemaking
process, an allowance for working capital to operate its ongoing
electric and natural gas utility services.
(vii) Single customer - Not applicable
(viii) Backlog of orders - Not applicable
(ix) Business subject to renegotiation - Not applicable
(x) Competitive conditions
(See Item 1(c)(iii) - Sources and availability of raw
materials.)
Competition and deregulation are the foremost challenges
currently facing the electric and natural gas industries and will
increasingly present both opportunities and risks. There is the
potential to gain new customers as well as the risk of losing
existing customers. While the transition to a competitive
marketplace in the electric industry is just beginning, the
transition in the natural gas industry is further along: the
production sector is now fully deregulated, and the interstate
transmission and distribution sectors are in various stages of
increasing competition.
In the electric industry, proceedings studying the
possibility of introducing more competition and restructuring in
some states, such as New York and California, may be paving the
way for industry change nationwide. However, a number of complex
issues (including transition costs and recovery of prudently
incurred costs) must be addressed before restructuring can be
accomplished. This makes it difficult to predict how soon
market-driven competition will be established.
Contributing to increasing competition in the utility
industry are legislation and regulatory policies such as the
National Energy Policy Act of 1992 (Energy Policy Act) and FERC
Order 636. The Energy Policy Act, enacted in October 1992,
provides open access at the wholesale level to electric
transmission services and is contributing to major changes in the
electric industry. FERC Order 636, which took effect in November
1993, requires interstate natural gas pipeline companies to offer
customers unbundled, or separate, services.
A major challenge to the company's electric business
continues to be its ability to retain and expand its industrial
base. The company's industrial customers, accounting for about
15% of total electric revenues, will increasingly have more
supply alternatives available to them. Those alternatives
currently include cogeneration, self-generation and fuel
switching. Industrial customers can also decide to relocate.
There are other competitive pressures as well. More
efficient technologies and more economical alternative fuels and
renewable energy sources may increasingly challenge traditional
energy sources. Another possibility is that municipalities would
establish their own electric systems within the company's service
territory.
The prospect of limited sales growth due to New York's
sluggish economy is another challenge. Low growth potential for
the company's core businesses makes it difficult to improve
earnings and lower prices.
Faced with growing competition and more efficient
technologies, utilities are increasingly focusing on the price of
their products. The company's electric prices have been rising.
The major contributors to these increases have been mandated
purchases of power from NUGs (See Item 1(c)(i) - Principal
business), rising taxes, DSM programs, and compliance with
environmental laws and regulations. DSM programs are initiatives
designed to help customers use energy efficiently. Recent
natural gas price increases have been caused by higher purchased
gas costs, primarily due to transition costs resulting after FERC
Order 636 and higher pipeline transportation costs.
The company has developed flexible rates that allow it to
negotiate long-term contracts with both its electric and its
natural gas customers. The contracts may cover existing load,
new load, or both. To date, 12 major electric industrial
customers have signed contracts ranging from three to seven
years. These contracts retain more than $36 million and add
another $7 million in annual revenues, which together represent
2.7% of the company's total electric annual revenues. Also each
month the company develops over 275 natural gas prices to compete
with the alternative fuels available.
The PSC has initiated a generic proceeding to study the
broad subject of flexible, competitive rates. In July 1994
during Phase I of this proceeding, the PSC issued an opinion
which approved flexible rate discounts for nonresidential
electric customers having competitive alternatives. In approving
the offering of discounts, the PSC adopted several guidelines
that reaffirmed most of the company's flexible pricing programs.
In August 1994 the PSC instituted Phase II of the
proceeding to address competitive opportunities available to
electric customers and investigate the future regulation of
electric service in light of competition. The overall objective
is to identify regulatory and ratemaking practices that will
assist the transition to a more competitive electric industry.
Proposed principles to guide this transition were issued for
comment by the PSC in December 1994.
This proceeding could affect the eligibility of electric
utilities in New York State to apply Statement of Financial
Accounting Standards No. 71, "Accounting for the Effects of
Certain Types of Regulation" (SFAS 71). If the company could no
longer meet the criteria of SFAS 71 for all or a part of its
business, the company would have to expense certain previously
deferred costs. Although the company believes it will continue
to meet the criteria of SFAS 71 in the near future, it cannot
predict what effect a competitive marketplace or future actions
of the PSC will have on its ability to continue to do so.
In June 1994 the FERC issued a Notice of Proposed Rulemaking
(NOPR) to address transition costs and invited representatives of
the utility industry to comment on or suggest alternatives to the
proposals. Transition costs are costs that utilities may incur
(and that may become unrecoverable) as the industry moves from a
heavily regulated environment to a less-regulated, competitive
environment.
In December 1994 the company and a coalition of other New
York State utilities filed joint comments addressing legal issues
raised by the NOPR. The company also filed a separate document
that addressed technical issues specific to the company. The
coalition comments urge the FERC to set a national policy that
will ensure recovery of transition costs so that competition will
benefit all customers fairly. In a purely competitive
environment, costs that utilities are required to bear (such as
taxes, purchases of NUG power and DSM programs) would be
difficult to recover because customers would have the opportunity
to buy electricity from competitors who do not bear such costs,
such as NUGs and municipal utilities. This could leave remaining
customers bearing the full burden of those costs.
In 1994 the gas business operated its first full year under
FERC Order 636 (See Note 11 to the Consolidated Financial
Statements on page 75). Ultimately FERC Order 636 should prove
beneficial to the company and its natural gas customers by
providing greater opportunities to access natural gas supply,
transportation and storage. Increased choices should result in
lower natural gas costs in the intermediate and long term.
In December 1994 the PSC issued an order in its proceeding
(instituted in late 1993) to investigate natural gas utility
issues in view of FERC Order 636 and to determine to what extent
New York State should adopt the federal policies. The PSC order
also established a generic proceeding to investigate performance-
based natural gas purchasing incentives and the availability and
affordability of natural gas as the transition to a more
competitive environment develops. While they found the majority
of the PSC's findings favorable, the company and certain other
parties to the proceeding have asked for a rehearing on certain
points that they believe are inconsistent with the overall goal
of encouraging competition. The company has already taken
advantage of several new opportunities, including flexible
customer rates, unbundling of services, and access to the
secondary market for natural gas supplies and pipeline capacity.
During 1994 the company took a number of difficult steps to
address the competitive challenges it faces. Foremost among them
were the restructuring and workforce reduction completed in the
first quarter of 1994 (see Note 6 to the Consolidated Financial
Statements on page 63) and the decision to reduce the common
stock dividend in the fourth quarter of 1994 (See Item 7 -
Liquidity and Capital Resources - Common Stock Dividend Policy).
Other steps the company has taken to address competitive
pressures during 1994 include reducing capital expenditures and
DSM program costs, placing two generating units on long-term cold
standby, creating a customer service business unit and moving
responsibility for fuel procurement and bulk power sales to the
generation department.
In order to help it meet the challenges of competition, the
company has a five-year strategic plan. This plan will be
updated annually. Following are some of the goals the company
has set for 1995:
- Improve earnings per share by at least 5% over 1994.
- Achieve excellence in customer service and meet
all customer service targets (See Item 1(a) - Rates and
regulatory matters-Rate Matters).
- Negotiate a positive modification to the company's
existing three-year electric rate agreement.
- Develop greater rate flexibility to retain existing
customers and attract new ones, and to properly price
value-added services.
- Obtain PSC approval and begin construction of the $59
million Seneca Lake Gas Storage Project.
- Successfully introduce EnerSoft's Channel 4 trading system
in the spring of 1995 (See Item 1(a)-Diversification).
(xi) Research and development
Expenditures on research and development in 1994, 1993, and
1992 amounted to $14.5 million, $18.9 million, and $14.6 million,
respectively, principally for the company's internal research
programs and for contributions to research administered by the
Electric Power Research Institute, the Empire State Electric
Energy Research Corporation, the New York Gas Group, and the New
York State Energy Research and Development Authority. These
expenditures are designed to improve existing technologies and to
develop new technologies for the production, distribution, and
customer use of energy.
(xii) Environmental matters
(See Item 3-Legal proceedings)
The company is subject to regulation by the federal
government and by state and local governments in New York and
Pennsylvania with respect to environmental matters and is also
subject to the New York State Public Service Law requiring
environmental approval and certification of proposed major
transmission facilities.
The company continually assesses actions that may need to be
taken to ensure compliance with changing environmental laws and
regulations. Any additional compliance programs will increase
the cost of electric and natural gas service by requiring changes
in the company's operations and facilities. Historically, rate
recovery has been authorized for the cost incurred to comply with
environmental laws and regulations.
Capital additions to meet environmental requirements during
the three years ended December 31, 1994 were approximately $116
million and are estimated to be $24 million for 1995, $28 million
for 1996, and $17 million for 1997.
Water quality
The company is required to comply with federal and state
water quality statutes and regulations including the Clean Water
Act (Water Act). The Water Act requires that generating stations
be in compliance with federally issued National Pollutant
Discharge Elimination System Permits (NPDES Permits) or state
issued State Pollutant Discharge Elimination System Permits
(SPDES Permits), which reflect water quality considerations for
the protection of the environment. The company has SPDES Permits
for its six coal-fired generating stations in New York and has
applied for permit renewals for all of those stations. Permits
for these stations have either been renewed or are currently
being negotiated with the State of New York, in which case the
existing permits for those facilities remain in effect. The
company's Homer City Generating Station received a revised NPDES
Permit in September 1994 from the Pennsylvania Department of
Environmental Resources (PaDER) sections of which it is
contesting. The Homer City Station will continue to operate
under the existing permit conditions until this matter is
resolved. The SPDES permit for NMP2 was recently renewed.
In connection with the issuance of permits under the Water
Act, the company has conducted studies of the effects of its coal
pile operations on groundwater quality at its Hickling, Jennison,
Milliken, and Greenidge Stations. New York State groundwater
standards are sometimes exceeded at certain locations at each of
those stations and remedial action may be required. Jennison
Station will require remedial action which is estimated to cost
up to $1 million. The remedial action, if required, at Hickling,
Milliken, and Greenidge Stations is estimated to cost $7.4
million. The company expects to recover these expenditures in
rates, since the company has been allowed by the PSC to recover
similar costs in rates, such as groundwater protection costs to
meet permit conditions and regulatory requirements. Remedial
action has already been performed at the Goudey Station and the
company is currently monitoring the groundwater quality at this
station. Groundwater monitoring data for Kintigh Station does
not indicate facility induced groundwater contamination.
Groundwater studies have been initiated at the Homer City
Station.
Air quality
The company is required to comply with federal and state air
quality statutes and regulations. All stations have the required
federal or state operating permits. Stack tests and continuous
emission monitoring indicate that the stations are generally in
compliance with permit emission limitations, although occasional
opacity exceedances occur. Efforts continue in the identifi-
cation and elimination of the causes of opacity exceedances.
The Clean Air Act Amendments of 1990 (1990 Amendments) will
result in expenditures of approximately $174 million, on a
present value basis, over a 25-year period, for all capital and
operating and maintenance expenses related to the reduction of
sulfur dioxide and nitrogen oxides at several of the company's
coal-fired generating stations, of which $106.5 million had been
incurred as of December 31, 1994. The cost to comply with the
sulfur dioxide and nitrogen oxide limitations includes the
construction of an innovative flue gas desulfurization (FGD)
system and a nitrogen oxide reduction system that was recently
completed at the company's Milliken Generating Station. The
company estimates that approximately a 1% electric rate increase
will be required for the cost of reducing sulfur dioxide and
nitrogen oxide emissions in both Phase I (which began on January
1, 1995) and Phase II (begins January 1, 2000), as discussed
below. In addition, the company anticipates that it will have to
significantly reduce its nitrogen oxide emissions even further by
the year 2003, which includes an interim reduction in the year
1999, as a result of proposed U.S. Environmental Protection
Agency (EPA) regulations. The cost to comply with these proposed
regulations cannot be estimated at this time, since the reduction
will be based on additional research scheduled to be completed
later in the decade. As a result of the 1990 Amendments, the
company plans to reduce its annual sulfur dioxide emissions by an
amount that will allow the company to meet the sulfur dioxide
levels established for the company, which are approximately a 49%
reduction from approximately 138,000 tons in 1989 to 71,000 tons
by the year 2000.
The cost of controlling toxic emissions under the 1990
Amendments, if required, cannot be estimated at this time, since
the type and level of reductions that may be required is
dependent on a study currently being performed by the EPA, which
is scheduled to be completed by the end of 1995. Regulations may
be adopted at the state level that would limit toxic emissions
even further, at an additional cost to the company. The company
anticipates that the costs incurred to comply with the 1990
Amendments will be recoverable through rates based on previous
rate recovery of required environmental costs.
The 1990 Amendments require the EPA to allocate annual
emissions allowances to each of the company's coal-fired
generating stations based on statutory emissions limits. An
emissions allowance represents an authorization to emit, during
or after a specified calendar year, one ton of sulfur dioxide.
During Phase I, the company estimates that it will have
allowances in excess of the affected coal-fired generating
stations' actual emissions. The company's present strategy is to
bank these allowances for use in later years. By using a banking
strategy, it is estimated that Phase II allowance requirements
will be met through the year 2005 by utilizing the allowances
banked during Phase I, which includes the extension reserve
allowances discussed below, together with the company's Phase II
annual emissions allowances. This strategy could be modified
should market or business conditions change. In addition to the
annual emissions allowances allocated to the company by the EPA,
the company has received a portion of the extension reserve
allowances issued by the EPA to utilities electing to build
scrubbers in Phase I, as a result of a pooling agreement that it
entered into with other utilities who were also eligible to
receive some of these extension reserve allowances.
Certain other environmental regulations limit the amount of
particulate matter which may be emitted into the environment.
The company and Pennsylvania Electric Company may find it
necessary either to upgrade or install additional equipment at
the Homer City Generating Station in order to consistently meet
the particulate emission requirements.
Waste disposal
The company has received or applied for SPDES Permits, Solid
Waste Disposal Facilities Permits, and applicable local permits
for its active ash disposal sites for its New York generating
stations. Groundwater standards have been exceeded in areas
close to portions of the Milliken and Weber ash disposal sites.
Corrective actions have been taken and studies are continuing to
monitor the effectiveness of the corrective actions.
The company has received NPDES permits, a Solid Waste
Disposal Permit, and applicable local permits for its active ash
disposal site for the Homer City Generating Station and for the
active refuse disposal site for the Homer City Coal Cleaning
Plant. In September 1993 the company completed its study of
costs to comply with the new Pennsylvania residual waste
regulations governing solid waste disposal over the next 30
years.
As a result of existing and new solid waste disposal
legislation and regulations in Pennsylvania, the company will
incur approximately $28 million, on a present value basis, of
additional costs over the next 30 years at the Homer City
Generating Station. The majority of these costs will be incurred
over the next 10 years to install new equipment, modify or
replace existing equipment, and improve the design of a proposed
expansion of disposal facilities. The company expects to recover
these expenditures in rates, since the company has been allowed
by the PSC to recover similar costs in rates, such as groundwater
protection costs to meet permit conditions and regulatory
requirements.
Due to existing and proposed legislation and regulations,
and legal proceedings commenced by governmental bodies and
others, the company may also incur costs from the past disposal
of hazardous substances produced during the company's operations
or those of its predecessors. The company has been notified by
the EPA and the New York State Department of Environmental
Conservation (NYSDEC), as appropriate, that it is among the
potentially responsible parties (PRPs) who may be liable to pay
for costs incurred to remediate certain hazardous substances at
nine waste sites, not including the company's inactive gas
manufacturing sites, which are discussed below. With respect to
the nine sites, seven sites are included in the New York State
Registry of Inactive Hazardous Waste Sites (New York State
Registry) and two of those sites are also included on the
National Priorities List.
Any liability may be joint and several for certain of these
sites. The company has recorded a liability related to four of
these nine sites, which is reflected in the company's
consolidated balance sheets at December 31, 1994, in the amount
of $1.1 million. The ultimate cost to remediate these sites may
be significantly more than this amount and will be dependent on
such factors as the remedial action plan selected, the extent of
site contamination, and the portion attributed to the company.
The company has notified the EPA and the NYSDEC, as appropriate,
that it believes it has no responsibility at three sites and has
already incurred expenditures related to remediation at another
site. The company has not, as yet, determined whether it has any
responsibility at the remaining site. A deferred asset has also
been recorded in the amount of $2.1 million, of which $1.0
million relates to costs that have already been incurred. The
company believes it will recover these costs, since the PSC has
allowed other utilities to recover these types of remediation
costs and has allowed the company to recover similar costs in
rates, such as investigation and cleanup costs relating to
inactive gas manufacturing sites. The estimated liability of
$1.1 million was derived by multiplying the total estimated cost
to clean up a particular site by the related company contribution
factor. Estimates of the total cleanup costs were determined by
using information related to a particular site, such as
investigations performed to date at a site or from the data
released by a regulatory agency. In addition, this estimate was
based upon currently available facts, existing technology, and
presently enacted laws and regulations. The contribution factor
is calculated using either the company's percentage share of the
total PRPs named, which assumes all PRPs will contribute equally,
or the company's estimated percentage share of the total
hazardous wastes disposed of at a particular site, or by using a
1% contribution factor for those sites at which it believes that
it has contributed a minimal amount of hazardous wastes. The
company has notified its former and current insurance carriers
that it seeks to recover from them certain of these cleanup
costs. However, the company is unable to predict the amount of
insurance recoveries, if any, that it may obtain.
A number of the company's inactive gas manufacturing sites
have been listed in the New York State Registry. In late March
1994 the company entered into an Order on Consent with the NYSDEC
requiring the company to investigate and, where necessary,
remediate 33 of the company's 38 known inactive gas manufacturing
sites. The schedule for investigating and remediating these 33
sites will be determined through further negotiations with the
NYSDEC. The company has a program to investigate and initiate
necessary remediation at its 38 known inactive gas manufacturing
sites. Expenditures through the year 2009 are estimated at
$32.5 million, including the impact of the Order on Consent.
This estimate was determined by using the company's experience
and knowledge related to these sites as a result of the
investigation and remediation that the company has performed to
date. It is based upon currently available facts, existing
technology, and presently enacted laws and regulations. This
liability to investigate and initiate remediation, as necessary,
at the known inactive gas manufacturing sites, is reflected in
the company's consolidated balance sheets at December 31, 1994
and 1993 in the amount of $32.5 million and $25 million,
respectively. The company also has recorded a corresponding
deferred asset, since it expects to recover such expenditures in
rates, as the company has previously been allowed by the PSC to
recover such costs in rates. The PSC has asked its staff to
prepare a recommendation on a generic policy for these types of
expenditures by the spring of 1995. The company has notified its
former and current insurance carriers that it seeks to recover
from them certain of these cleanup costs. However, the company
is unable to predict the amount of insurance recoveries, if any,
that it may obtain.
A low level radioactive waste management and contingency
plan for NMP2 provides assurance that NMP2 is properly prepared
to handle interim storage of low level radioactive waste until
1998.
Niagara Mohawk has contracted with the U.S. Department of
Energy (DOE) for disposal of high level radioactive waste (spent
fuel) from NMP2. The company is reimbursing Niagara Mohawk for
its 18% share of the cost under the contract (currently
approximately $1 per megawatt hour of net generation). The DOE's
schedule for start of operations of their high level radioactive
waste repository has slipped from 2003 to no sooner than 2010.
The company has been advised by Niagara Mohawk that the NMP2
Spent Fuel Storage Pool has a capacity for spent fuel that is
adequate until 2014. If further DOE schedule slippage should
occur, construction of pre-licensed dry storage facilities would
extend the on-site storage capability for spent fuel at NMP2
beyond 2014.
(xiii) Number of employees
The company had 4,192 employees as of December 31, 1994.
(d) Financial information about foreign and domestic operations
and export sales - Not applicable
Item 2. Properties
The company's electric system includes coal-fired, nuclear,
hydroelectric, and internal combustion generating stations,
substations, and transmission and distribution lines, all of
which are located in the State of New York, except for the Homer
City Generating Station and related facilities which are located
in the Commonwealth of Pennsylvania. Generating facilities are:
Name and location of station Generating
capability (mw)
Coal-fired
Goudey (Binghamton, N.Y.) 84 *
Greenidge (Dresden, N.Y.) 108 *
Hickling (East Corning, N.Y.) 82
Jennison (Bainbridge, N.Y.) 69
Milliken (Lansing, N.Y.) 310
Kintigh (Somerset, N.Y.) 675
Homer City (Homer City, Pa.) 950**
-----
Total coal-fired 2,278
Nuclear
NMP2 (Oswego, N.Y.) 189***
Hydroelectric (Various - 9 locations) 69
Internal combustion (Various - 2 locations) 7
-----
Total - all stations 2,543
=====
* In 1994 the company placed one unit at both
Goudey and Greenidge on long-term cold standby.
These units had a combined capability of 97
megawatts.
** Company's 50% share of the generating capability.
***Company's 18% share of the generating capability.
The company owns 432 substations having an aggregate
transformer capacity of 13,142,800 Kilovolt-amperes. The
transmission system consists of 4,834 circuit miles of line and
the distribution system of 33,503 pole miles of overhead lines
and 1,790 miles of underground lines.
The company's natural gas system consists of the
distribution of natural gas through 482 miles of transmission
pipelines (over 3-inch equivalent) and 5,775 miles of
distribution pipelines (under 3-inch equivalent).
Somerset Railroad Corporation (SRC), a wholly-owned
subsidiary, owns a rail line consisting of 15 1/2 miles of track
and related property rights in Lockport, Newfane, and Somerset,
New York which is used to transport coal and other materials to
the Kintigh Generating Station.
The company's first mortgage bond indenture constitutes a
direct first mortgage lien on substantially all of the company's
properties. Substantially all of the properties of SRC, other
than rolling stock, are subject to a lien of a mortgage and
security agreement.
Item 3. Legal proceedings
(See Item 1(a)-Rates and regulatory matters - Rate Matters,
1(c)(i)-Principal business, 1(c)(x)-Competitive conditions, and
1(c)(xii)-Environmental matters)
The company is unable to predict the ultimate disposition of
the matters referred to below in (b), (c), (d), (e), (f), (h),
(i), (j) and the first paragraph in (g). However, since the PSC
has allowed other utilities to recover these types of remediation
costs and has previously allowed the company to recover similar
costs in rates, such as investigation and clean-up costs relating
to coal tar sites, the company expects to recover in rates any
remediation costs that it may incur. Therefore, the company
believes that the ultimate disposition of the matters referred to
below in (b), (c), (d), (e), (f), (h), (i), (j) and the first
paragraph in (g) will not have a material adverse effect on its
results of operations or financial position.
(a) On January 27, January 31, and February 15, 1984, and on
June 29, 1987, numerous individual plaintiffs instituted lawsuits
in the Supreme Court of the State of New York (Broome County) for
personal injuries allegedly arising out of a transformer fire at
the State Office Building in Binghamton, New York, in February
1981. Multiple defendants, including the company, are named in
the actions which seek an aggregate of $329 million in
compensatory and punitive damages. Because the transformers
involved were not owned, installed, or serviced by the company,
the company believes that these claims against the company are
without merit.
(b) By letter dated February 29, 1988, the NYSDEC notified the
company that it had been identified as a PRP for investigation
and remediation of hazardous wastes at the Lockport City Landfill
Site (Lockport Site) in Lockport, New York. The Lockport Site is
listed on the New York State Registry. Five other PRPs have been
identified by the NYSDEC. The company believes that remediation
costs at the Lockport Site might rise to $6 million. The
Lockport Site is currently being remediated by the site owner,
the City of Lockport. By letter dated May 2, 1988, the company
notified the NYSDEC that it declined to finance remediation costs
because it believed that the NYSDEC had not demonstrated that a
significant threat to public health or the environment exists at
the Lockport Site.
(c) By letter dated December 10, 1990, the NYSDEC notified the
company that it had been identified as a PRP for investigation
and remediation of hazardous wastes at the Schreck's scrapyard
site (Schreck's Site) in the City of North Tonawanda, New York.
The Schreck's Site is listed on the New York State Registry.
Seven other PRPs were identified in the NYSDEC letter. On
February 3, 1992, the NYSDEC again notified the company that it
had been identified as a PRP for investigation and remediation
costs at the Schreck's Site, this time listing eight other PRPs.
The company has been offered an opportunity to conduct
remediation or finance remediation costs at the Schreck's Site,
failing which the NYSDEC might remediate the Schreck's Site
itself and commence an action to recover its costs and damages.
The NYSDEC currently estimates that remediation costs at the
Schreck's Site will be $4.5 million. By letter dated April 1,
1992, the company notified the NYSDEC that it believed it had no
responsibility for the alleged contamination at the Schreck's
Site, and it declined to conduct remediation or finance
remediation costs.
(d) By letter dated June 7, 1991, the NYSDEC notified the
company that it had been identified as a PRP at the Pfohl
Brothers Landfill, an inactive hazardous waste disposal site
(Pfohl Site) in Cheektowaga, New York. The Pfohl Site is listed
on the National Priorities List and the New York State Registry.
The NYSDEC offered the company an opportunity to enter into
negotiations with it to undertake the investigation and remedia-
tion of the Pfohl Site. The NYSDEC informed the company that if
it declined such negotiations, the NYSDEC would perform the
necessary work at the Pfohl Site using the Hazardous Waste
Remedial Fund and would seek recovery of its expenses from the
company. On July 3, 1991, the company responded to the NYSDEC by
declining to negotiate to undertake work at the Pfohl Site and it
noted that the NYSDEC had not shown any significant
responsibility on the part of the company for the situation at
the Pfohl Site. The company believes that remediation costs at
the Pfohl Site will be $35 million to $55 million. By letter
dated April 2, 1992, the NYSDEC again notified the company that
it had been identified as a PRP for the Pfohl Site and offered
the company an opportunity to conduct or finance the on-site
remedial design and action. This notice letter was also sent to
19 other PRPs. Ten of these other named PRPs have agreed to
perform the remedial work required by the NYSDEC. By letter
dated June 1, 1992, the company notified the NYSDEC that it
declined to perform such remedial work because it believed that
it was not a significant contributor to the Pfohl Site.
(e) By letter dated January 21, 1992, the NYSDEC notified the
company that it had been identified as a PRP at the Peter Cooper
Corporation's Landfill Site (Peter Cooper Site) in the village of
Gowanda, New York. Three other PRPs were identified in the
NYSDEC letter. The NYSDEC letter also notified the company that
state surface water and groundwater standards had been exceeded
at the Peter Cooper Site and offered the company an opportunity
to conduct or finance a remedial program. NYSDEC indicated that
if the company did not agree to enter into a consent order it
would perform the necessary work itself or seek a court order
requiring the company to conduct the work. The company believes
that remediation costs at the Peter Cooper Site might rise to $16
million. By letter dated May 12, 1992, the company notified the
NYSDEC that it believed it had no responsibility for the alleged
contamination at the Peter Cooper Site, and it declined to
conduct remediation or finance remediation costs.
(f) By letter dated April 20, 1992, the EPA notified the company
that it had been identified as a PRP at the Bern Metals Removal
Site (Bern Metals Site) in Buffalo, New York. Six other PRPs
have been identified by the EPA. The EPA has taken response
actions at the Bern Metals Site, including investigation,
excavation, and removal of drums and contaminated soil, and
implementation of measures to prevent surface water run-off. The
EPA has demanded that the company reimburse the EPA Hazardous
Substances Superfund $2 million in response costs incurred to
date by the EPA, with interest accruing from the date of the
demand. Future response or remedial costs which the EPA may
incur at the Bern Metals Site are not covered by the EPA demand
and the EPA has reserved its rights relating to any such costs.
In addition to the foregoing, the NYSDEC, by letter dated
July 21, 1992, notified the company that it had been identified
as a PRP at the Bern Metals Site, which the NYSDEC defined to
include an adjacent property known as the Universal Iron & Metal
Site (Bern Metals/Universal Iron Site). The Bern
Metals/Universal Iron Site is listed on the New York State
Registry. The NYSDEC has also identified eight other PRPs for
the Bern Metals/Universal Iron Site. The NYSDEC has requested
that the company, and the eight other identified PRPs, enter into
negotiations in which the company and the other identified PRPs
would agree to finance or conduct a Remedial Investigation and
Feasibility Study (RI/FS) designed to determine what further
remediation or removal actions may be appropriate for the Bern
Metals/Universal Iron Site. The NYSDEC has provided no estimate
of the cost of the response action it proposes. By letter dated
December 3, 1992, the company declined to negotiate with NYSDEC
to finance or conduct an RI/FS for the Bern Metals/Universal Iron
Site, because the company believes it was only a very small
contributor to the Bern Metals/Universal Iron Site. In addition,
the company believes that it does not have any connection with
the Universal Iron & Metal Site.
(g) By letter dated April 20, 1992, the EPA notified the company
that the EPA had reason to believe that the company was a PRP for
the Clinton-Bender Removal Site (Clinton-Bender Site) in Buffalo,
New York. Five other PRPs have been identified by the EPA. Nine
private residential lots and one commercial property at the
Clinton-Bender Site are contaminated with lead, allegedly due to
run-off from the adjacent Bern Metals Site. The EPA has
requested that the company perform the necessary removal work at
the Clinton-Bender Site and the company is doing so in
conjunction with four other identified PRPs. The total cost of
the removal actions to be performed at the Clinton-Bender Site is
estimated to be $3.1 million.
On November 3, 1993, the company was served with a summons
and complaint filed on behalf of certain of the homeowners at the
Clinton-Bender Site. Seven other defendants were named in the
complaint, which was filed in the New York State Supreme Court,
Erie County. The action has since been removed to the U.S.
District Court for the Western District of New York (District
Court). In their complaint, plaintiffs make general allegations
that the defendants violated federal environmental laws without
alleging facts in support of these allegations. Plaintiffs also
allege personal injury, property damage, and fear of cancer which
they claim were caused by the presence of hazardous substances on
their property, allegedly resulting from the disposal of such
substances by the defendants at the Bern Metals Site. Any
liability incurred as a result of these claims may be joint and
several. The plaintiffs ask for $30 million in direct damages
from all defendants, as well as treble damages (for unspecified
reasons) from all defendants, and an additional $10 million in
punitive damages from each defendant. The company and some of
the other defendants in this matter have made a motion to the
District Court for dismissal of all claims based upon the Clean
Air Act, the Clean Water Act, and the Comprehensive Environmental
Response, Compensation, and Liability Act of 1980 (CERCLA), which
are the only claims based upon federal causes of action. A
decision on this motion is still pending. The company believes
that the ultimate disposition of this matter will not have a
material adverse effect on its results of operations or financial
position.
(h) By letter dated February 12, 1993, NYSDEC notified the
company that it had been identified as a PRP for remediation of
hazardous wastes at the Booth Oil Site (Booth Oil Site) in North
Tonawanda, New York. The Booth Oil Site is listed on the New
York State Registry. Nineteen other PRPs have been identified by
the NYSDEC. Booth Oil Company is a waste oil re-refiner and
recycler. The company had sent waste oils to Booth Oil Company
for disposal as had numerous other companies in the Buffalo area.
According to NYSDEC, the Booth Oil Site is contaminated with
PCBs, lead, and other substances. NYSDEC has requested that the
company and the other identified PRPs conduct remediation at the
Booth Oil Site pursuant to an Order on Consent to be negotiated
with NYSDEC. NYSDEC has estimated that the present value of
costs for on-site treatment alternatives range from $12 million
to $24 million. The PRPs have presented an alternate concept for
remediation of the site and are awaiting a response from the
NYSDEC.
(i) On June 14, 1994, the company was served with a summons and
complaint joining the company as a defendant in an action that
was filed in the United States District Court for the Northern
District of New York. The plaintiffs are five companies which
have been required by the EPA to conduct remedial activities at
the Rosen Brothers Site (Rosen Site) in the City of Cortland, New
York. The Rosen Site was the location of a scrap metal
processing operation and industrial waste disposal site between
approximately 1971 and 1985, and it is now allegedly contaminated
with hazardous substances including heavy metals, solvents and
PCBs. The Rosen Site is listed on the National Priorities List
and the New York State Registry. Among other claims, the
plaintiffs seek contribution under CERCLA, from the company and
sixteen other defendants for the costs of complying with the EPA
order to remediate the Rosen Site. The plaintiffs allege that
the company was a contributor to the Rosen Site of transformers
which may have contained PCBs. Liability under CERCLA may be
joint and several. No remedy has yet been selected by EPA for
the Rosen Site and, therefore, the total amount of remedial costs
eventually to be incurred by the plaintiffs is currently unknown.
By letter dated August 16, 1994, the EPA notified the
company that the EPA had reason to believe that the company was a
PRP for the Rosen Site. The EPA has requested that the company
participate in the RI/FS currently being prepared for the Rosen
Site by the other named PRPs. By letter dated October 20, 1994,
the company declined to participate in this study because it
believes that no facts have been established showing that it was
responsible for any contamination at the Site.
(j) By letter dated February 8, 1995, the EPA notified the
company that the EPA had reason to believe that the company was a
PRP for the Quanta Resources Site, which was a waste oil
reclamation/recycling facility that operated until 1981 in
Syracuse, New York. A large volume of product and waste material
was left behind when operations ceased. The Quanta Resources
Site is listed on the New York State Registry. 140 other PRPs
were identified in the EPA letter. The EPA has taken response
actions at the Quanta Resources Site, including sampling,
monitoring, investigative, corrective and enforcement measures.
The EPA has demanded that the company and the other PRPs
reimburse the EPA Hazardous Substances Superfund approximately
$500,000 in response costs incurred to date by the EPA. Future
response or remedial costs which the EPA may incur at the Quanta
Resources Site are not covered by the EPA demand and the EPA has
reserved its rights relating to any such costs.
(k) By complaint dated October 31, 1991, General Motors
Corporation (GM) commenced a lawsuit against the company in the
U. S. District Court for the Western District of New York. GM
alleges, among other claims, that the company violated various
federal antitrust laws in connection with billings for electric
service provided by the company at GM's Harrison Radiator Plant
at Lockport, New York. GM's claims are for damages incurred and
to be incurred. The company estimates that GM is claiming
approximately $8 million, after trebling. The company believes
that it has not violated the federal antitrust laws and that this
lawsuit is without merit.
On October 5, 1993, the Magistrate to whom the case had been
referred issued a decision recommending that GM's complaint be
dismissed. On July 12, 1994, the District Judge responsible for
the case, after reviewing GM's exceptions to the decision and the
company's reply adopted the Magistrate's recommended decision in
its entirety and dismissed the complaint. On August 9, 1994, GM
filed an appeal of that decision. On October 10, 1994, the
company and GM stipulated that GM would withdraw its appeal,
subject to GM's right to renew it, while the parties attempted to
resolve their differences. On December 29, 1994, the parties
stipulated to extend to April 3, 1995 GM's right to renew its
appeal.
(l) By complaint dated August 12, 1994, as amended October 19,
1994, a class action lawsuit was commenced against the company
and James A. Carrigg, Chairman, President and Chief Executive
Officer of the company (Defendants) in the United States District
Court for the Eastern District of New York. The lawsuit was
brought by two alleged shareholders purporting to act on behalf
of purchasers of the company's Common Stock pursuant to its
Dividend Reinvestment and Stock Purchase Plan between May 15 and
August 10, 1994, and on behalf of purchasers of the company's
securities on the open market between March 15, 1994 and August
10, 1994. The complaint alleges that certain statements in the
company's Form 10-K for 1993 and the company's Annual Report to
Shareholders for 1993 relating to the company's diversification
program and common stock dividend violated the federal securities
laws. Plaintiffs are seeking to recover damages in an
unspecified amount. The Defendants believe that this lawsuit is
without merit and intend to defend this action vigorously.
Item 4. Submission of matters to a vote of security holders -
Not applicable.
* * * * * * * * * *
Executive officers of the Registrant
Positions, offices and
business experience -
Name Age January 1990 to date
James A. Carrigg 61 Chairman, President and Chief Execu-
tive Officer, January 1991 to date;
Chairman and Chief Executive Officer,
to January 1991.
Jack H. Roskoz 56 Executive Vice President, January 1995
to date; Senior Vice President-Electric
Business Unit, April 1990 to January
1995; Senior Vice President, to April
1990.
Richard P. Fagan 54 Senior Vice President-Management
Services Business Unit, April 1990 to
date; Senior Vice President-
Administration, to April 1990.
Michael I. German 44 Senior Vice President-Gas Business
Unit, December 1994 to date; Senior
Vice President, American Gas Assoc-
iation, Arlington, Virginia, to Decem-
ber 1994.
Gerald E. Putman 44 Senior Vice President-Customer Service
Business Unit, January 1995 to date;
Vice President-Fuel Supply and Opera-
tion Services, May 1993 to January
1995; Vice President-East Region
Electric, September 1992 to May 1993;
Executive Assistant to the Chairman,
President and Chief Executive Officer,
January 1991 to September 1992;
District Manager, Auburn, NY, to
January 1991.
Daniel W. Farley 39 Vice President and Secretary, May 1991
to date; Secretary, to May 1991.
Carl E. Johnson 52 Vice President-Human Resources & Com-
munications, January 1995 to date;
Vice President-Consumer Services, Com-
munications & Human Resources, Febru-
ary 1994 to January 1995; Vice Presi-
dent-Consumer Services & Communications
January 1991 to February 1994; General
Manager, Southeast Area to January
1991.
Executive officers of the Registrant (Cont'd)
Positions, offices and
business experience -
Name Age January 1990 to date
Sherwood J. Rafferty 47 Vice President and Treasurer, September
1990 to date; Treasurer, to September
1990.
Jeffrey K. Smith 46 Vice President-Generation, January
1995 to date; Executive Assistant to
the Chairman, President and Chief
Executive Officer, February 1994 to
January 1995; Assistant to the Senior
Vice President-Electric Business Unit,
October 1991 to February 1994; Manager-
Plant Operations Services, January 1991
to October 1991; Manager-Strategic
Planning, to January 1991.
Ralph R. Tedesco 41 Vice President-Strategic Growth
Business Unit, February 1994 to date;
Executive Assistant to the Chairman,
President and Chief Executive Officer,
September 1992 to February 1994;
Manager, Corporate Performance June
1991 to September 1992; Manager,
Research and Development, to June 1991.
Gary J. Turton 47 Controller and Chief Accounting
Officer, December 1994 to date;
Assistant Controller, to December 1994.
Denis E. Wickham 46 Vice President-Electric Resource
Planning, January 1991 to date;
Assistant to Senior Vice President, to
January 1991.
The company has entered into an agreement with James A.
Carrigg which provides for his employment as Chairman, President
and Chief Executive Officer of the company for a term ending on
December 31, 1996, with automatic one-year extensions unless
either he or the company gives notice that the agreement is not
to be extended.
Each officer holds office for the term for which he or she
is elected or appointed, and until his or her successor shall be
elected and shall qualify. The term of office for each officer
extends to and expires at the meeting of the Board of Directors
following the next annual meeting of shareholders.
PART II
Item 5. Market for Registrant's common stock and related
stockholder matters
See Note 15 to the Consolidated Financial Statements on page
79.
Item 6. Selected Financial Data
(Thousands-except per share amounts) 1994 1993 1992 1991 1990
- ------------------------------------------------------------------------------------------------------
Operating revenues $1,898,855 $1,800,149 $1,691,689 $1,555,815 $1,496,780
Net income $187,645 $166,028* $183,968 $168,643 $158,013
Earnings per share $2.37 $2.08* $2.40 $2.36 $2.48
Dividends paid per share $2.00 $2.18 $2.14 $2.10 $2.06
Average shares outstanding 71,254 69,990 67,972 62,906 58,678
Book value per share of common stock(year end) $23.28 $22.89 $22.85 $22.16 $21.85
Interest charges $139,725 $145,450 $155,388 $163,526 $173,390
AFDC and non-cash return $7,974 $8,003 $6,482 $7,541 $5,776
Depreciation and amortization $178,326 $164,568 $158,977 $152,380 $147,659
Other taxes $210,729 $204,962 $200,941 $178,185 $158,770
Capital expenditures $224,306 $245,029 $245,618 $245,883 $210,725
Total assets $5,222,905 $5,287,958 $5,077,916 $4,924,836 $4,737,431
Long-term obligations,capital leases and
redeemable preferred stock $1,776,081 $1,755,629 $1,883,927 $1,897,465 $1,766,457
*Net income and earnings per share for 1993 include the effects of restructuring expenses, which
decreased net income by $17.2 million, and decreased earnings per share by 25 cents.
Principal Sources of Electric and Natural Gas Revenues
ELECTRIC 1994 % of Total 1993 % of Total 1992 % of Total
-------------------------------------------------------------------------
Kwh Sales (millions):
Residential 5,399 27.0 % 5,423 28.0 % 5,472 28.4 %
Commercial 3,315 16.6 3,298 17.1 3,283 17.0
Industrial 2,997 15.0 2,950 15.3 3,082 16.0
Other 1,437 7.2 1,417 7.3 1,457 7.5
----------- ------- ----------- ------- ----------- -------
Total retail 13,148 65.8 13,088 67.7 13,294 68.9
Other electric utilities 6,827 34.2 6,233 32.3 6,003 31.1
----------- ------- ----------- ------- ----------- -------
Total 19,975 100.0 % 19,321 100.0 % 19,297 100.0 %
=========== ======= =========== ======= =========== =======
Operating Revenues (thousands):
Residential $679,124 42.4 % $635,155 41.6 % $601,042 41.4 %
Commercial 366,854 22.9 333,674 21.8 314,272 21.7
Industrial 245,218 15.3 228,215 14.9 225,832 15.5
Other 153,888 9.7 138,320 9.1 133,819 9.2
----------- ------- ----------- ------- ----------- -------
Total retail 1,445,084 90.3 1,335,364 87.4 1,274,965 87.8
Other electric utilities 141,902 8.9 147,175 9.6 143,413 9.9
Other operating revenues 13,089 .8 44,823 3.0 33,147 2.3
----------- ------- ----------- ------- ----------- -------
Total operating revenues $1,600,075 100.0 % $1,527,362 100.0 % $1,451,525 100.0 %
=========== ======= =========== ======= =========== =======
NATURAL GAS
Dekatherm(thousands):
Residential 24,662 42.1 % 25,080 43.2 % 24,913 44.2 %
Commercial 10,611 18.1 10,640 18.3 10,796 19.1
Industrial 2,180 3.7 1,820 3.2 1,689 3.0
Other 2,038 3.5 1,805 3.1 1,959 3.5
----------- ------- ----------- ------- ----------- -------
Total retail sales 39,491 67.4 39,345 67.8 39,357 69.8 %
Transportation of customer-owned
natural gas 19,133 32.6 18,701 32.2 17,009 30.2
----------- ------- ----------- ------- ----------- -------
Total natural gas deliveries 58,624 100.0 % 58,046 100.0 % 56,366 100.0 %
=========== ======= =========== ======= =========== =======
Operating Revenues(thousands):
Residential $185,073 61.9 % $170,734 62.6 % 152,325 63.4 %
Commercial 72,360 24.2 66,648 24.5 59,939 25.0
Industrial 11,542 3.9 9,602 3.5 8,092 3.4
Other 12,997 4.4 10,943 4.0 10,762 4.5
----------- ------- ----------- ------- ----------- -------
Sub-total 281,972 94.4 257,927 94.6 231,118 96.3
Transportation of customer-owned
natural gas 12,791 4.3 12,091 4.4 11,639 4.8
Unbilled revenue recognition-net 3,768 1.3 2,686 1.0 (3,626) (1.5)
Other natural gas revenue 249 - 83 - 1,033 .4
----------- ------- ----------- ------- ----------- -------
Total operating revenues $298,780 100.0 % $272,787 100.0 % $240,164 100.0 %
=========== ======= =========== ======= =========== =======
Item 7. Management's discussion and analysis of financial
condition and results of operations
Liquidity and Capital Resources
Competitive Conditions
Competition and deregulation are the foremost challenges
currently facing the electric and natural gas industries and will
increasingly present both opportunities and risks. There is the
potential to gain new customers as well as the risk of losing
existing customers. While the transition to a competitive
marketplace in the electric industry is just beginning, the
transition in the natural gas industry is further along: the
production sector is now fully deregulated, and the interstate
transmission and distribution sectors are in various stages of
increasing competition.
In the electric industry, proceedings studying the
possibility of introducing more competition and restructuring in
some states, such as New York and California, may be paving the
way for industry change nationwide. However, a number of complex
issues (including transition costs and recovery of prudently
incurred costs) must be addressed before restructuring can be
accomplished. This makes it difficult to predict how soon
market-driven competition will be established.
Contributing to increasing competition in the utility
industry are legislation and regulatory policies such as the
National Energy Policy Act of 1992 (Energy Policy Act) and
Federal Energy Regulatory Commission (FERC) Order 636. The
Energy Policy Act, enacted in October 1992, provides open access
at the wholesale level to electric transmission services and is
contributing to major changes in the electric industry. FERC
Order 636, which took effect in November 1993, requires
interstate natural gas pipeline companies to offer customers
unbundled, or separate, services.
A major challenge to the company's electric business
continues to be its ability to retain and expand its industrial
base. The company's industrial customers, accounting for about
15% of total electric revenues, will increasingly have more
supply alternatives available to them. Those alternatives
currently include cogeneration, self-generation and fuel
switching. Industrial customers can also decide to relocate.
There are other competitive pressures as well. More
efficient technologies and more economical alternative fuels and
renewable energy sources may increasingly challenge traditional
energy sources. Another possibility is that municipalities would
establish their own electric systems within the company's service
territory.
The prospect of limited sales growth due to New York's
sluggish economy is another challenge. Low growth potential for
the company's core businesses makes it difficult to improve
earnings and lower prices.
Faced with growing competition and more efficient
technologies, utilities are increasingly focusing on the price of
their products. The company's electric prices have been rising.
The major contributors to these increases have been mandated
purchases of power from non-utility generators (NUGs), rising
taxes, demand-side management (DSM) programs, and compliance with
environmental laws and regulations. DSM programs are initiatives
designed to help customers use energy efficiently. Recent
natural gas price increases have been caused by higher purchased
gas costs, primarily due to transition costs resulting after FERC
Order 636 and higher pipeline transportation costs.
The company has developed flexible rates that allow it to
negotiate long-term contracts with both its electric and its
natural gas customers. The contracts may cover existing load,
new load, or both. To date, 12 major electric industrial
customers have signed contracts ranging from three to seven
years. These contracts retain more than $36 million and add
another $7 million in annual revenues, which together represent
2.7% of the company's total electric annual revenues. Also each
month the company develops over 275 natural gas prices to compete
with the alternative fuels available.
The Public Service Commission of the State of New York (PSC)
has initiated a generic proceeding to study the broad subject of
flexible, competitive rates. In July 1994 during Phase I of this
proceeding, the PSC issued an opinion which approved flexible
rate discounts for nonresidential electric customers having
competitive alternatives. In approving the offering of
discounts, the PSC adopted several guidelines that reaffirmed
most of the company's flexible pricing programs.
In August 1994 the PSC instituted Phase II of the
proceeding to address competitive opportunities available to
electric customers and investigate the future regulation of
electric service in light of competition. The overall objective
is to identify regulatory and ratemaking practices that will
assist the transition to a more competitive electric industry.
Proposed principles to guide this transition were issued for
comment by the PSC in December 1994.
This proceeding could affect the eligibility of electric
utilities in New York State to apply Statement of Financial
Accounting Standards No. 71, "Accounting for the Effects of
Certain Types of Regulation" (SFAS 71). If the company could no
longer meet the criteria of SFAS 71 for all or a part of its
business, the company would have to expense certain previously
deferred costs. Although the company believes it will continue
to meet the criteria of SFAS 71 in the near future, it cannot
predict what effect a competitive marketplace or future actions
of the PSC will have on its ability to continue to do so.
In June 1994 the FERC issued a Notice of Proposed Rulemaking
(NOPR) to address transition costs and invited representatives of
the utility industry to comment on or suggest alternatives to the
proposals. Transition costs are costs that utilities may incur
(and that may become unrecoverable) as the industry moves from a
heavily regulated environment to a less-regulated, competitive
environment.
In December 1994 the company and a coalition of other New
York State utilities filed joint comments addressing legal issues
raised by the NOPR. The company also filed a separate document
that addressed technical issues specific to the company. The
coalition comments urge the FERC to set a national policy that
will ensure recovery of transition costs so that competition will
benefit all customers fairly. In a purely competitive
environment, costs that utilities are required to bear (such as
taxes, purchases of NUG power and DSM programs) would be
difficult to recover because customers would have the opportunity
to buy electricity from competitors who do not bear such costs,
such as NUGs and municipal utilities. This could leave remaining
customers bearing the full burden of those costs.
In 1994 the gas business operated its first full year under
FERC Order 636 (see Note 11). Ultimately FERC Order 636 should
prove beneficial to the company and its natural gas customers by
providing greater opportunities to access natural gas supply,
transportation and storage. Increased choices should result in
lower natural gas costs in the intermediate and long term.
In December 1994 the PSC issued an order in its proceeding
(instituted in late 1993) to investigate natural gas utility
issues in view of FERC Order 636 and to determine to what extent
New York State should adopt the federal policies. The PSC order
also established a generic proceeding to investigate performance-
based natural gas purchasing incentives and the availability and
affordability of natural gas as the transition to a more
competitive environment develops. While they found the majority
of the PSC's findings favorable, the company and certain other
parties to the proceeding have asked for a rehearing on certain
points that they believe are inconsistent with the overall goal
of encouraging competition. The company has already taken
advantage of several new opportunities, including flexible
customer rates, unbundling of services, and access to the
secondary market for natural gas supplies and pipeline capacity.
As one response to the competitive pressures faced by its
natural gas business, the company plans to build a natural gas
storage project near Seneca Lake, north of Watkins Glen, New
York. The project, which will cost $59 million and be regulated
by the PSC, includes a storage facility and two separate
pipelines to transport the natural gas. Its primary purpose is
to ensure adequate supply to the company's core natural gas
customers. The project will also increase supply flexibility,
allow the company to retire propane plants and ultimately reduce
pipeline demand charges. The company expects to receive PSC
approval for the project and begin construction in 1995. The
storage facility is scheduled to be in service for the 1996-1997
heating season.
During 1994 the company took a number of difficult steps to
address the competitive challenges it faces. Foremost among them
were the restructuring and workforce reduction completed in the
first quarter of 1994 (see Note 6) and the decision to reduce the
common stock dividend in the fourth quarter of 1994 (see Common
Stock Dividend Policy).
Other steps the company has taken to address competitive
pressures during 1994 include reducing capital expenditures and
DSM program costs, placing two generating units on long-term cold
standby, creating a customer service business unit and moving
responsibility for fuel procurement and bulk power sales to the
generation department.
On February 14, 1995, the company filed a petition with the
FERC asking for relief from having to pay approximately $2
billion more than its avoided costs for power purchased over the
life of the two NUG contracts mentioned below. The company
believes that the overpayments under these two contracts violate
the Public Utility Regulatory Policies Act of 1978.
The company is currently required to purchase 594 megawatts
(mw) of NUG power. The company is required to make payments
under these contracts only for the power it receives or when the
company directs the NUG to reduce its output under the terms of
the contract. Two contracts the company has with NUGs each
provide more than 5% of current system capability. One contract
provides for 177 mw or 5.4%, and the other provides for 240 mw or
7.3%. During 1994, 1993 and 1992 the company purchased
approximately $214 million, $138 million and $71 million,
respectively, of NUG power, including termination costs. The
company estimates that NUG power purchases, excluding termination
costs, over the next five years will be as follows:
1995 1996 1997 1998 1999
(Millions)
$274 $312 $322 $333 $344
Increases in the cost of NUG power purchases will contribute
significantly to expected electric price increases in August
1995.
Diversification
Diversification will play an important role in the company's
future. The company's primary objective is to enhance the
competitiveness of its core electric and natural gas businesses.
At the same time the company is actively evaluating opportunities
for investment closely related to its core businesses that have
the potential to augment future earnings. In April 1992 the PSC
issued an order allowing the company to invest up to 5% of its
consolidated capitalization (approximately $180 million at
December 31, 1994) in one or more subsidiaries that may engage or
invest in energy-related or environmental-services businesses and
provide related services.
The company has been making investments in unregulated
companies through its wholly owned subsidiary, NGE Enterprises,
Inc. (NGE). NGE owns two unregulated businesses - EnerSoft
Corporation (EnerSoft) and XENERGY, Inc. (XENERGY).
EnerSoft, a computer software company, was formed in May
1993 to produce and market software for natural gas utilities,
marketers and pipeline operators. Through an alliance with the
New York Mercantile Exchange, EnerSoft is developing Channel 4, a
natural gas and pipeline capacity trading and information system
for the North American market. While development of the system
has taken longer than anticipated, Channel 4 is expected to be
commercially available in the spring of 1995. Like most other
start-up companies, EnerSoft has been incurring operating losses.
The company expects that EnerSoft will continue to incur
operating losses in the near term.
In June 1994 NGE acquired all of the outstanding stock of
XENERGY, an energy services, information systems and energy-
consulting company that specializes in energy management,
conservation engineering and demand-side management. XENERGY
currently provides a broad range of services to utilities
throughout the United States, Canada, Spain and France. It also
provides energy services, conservation engineering and DSM
services to governmental agencies at both the state and federal
levels, and to a large number of end users.
NGE is exploring environmental-services opportunities with
both domestic and foreign strategic partners.
As of December 31, 1994 and 1993, the company had invested
approximately $47 million and $3 million, respectively, in NGE to
finance its diversified investments. For the years ended
December 31, 1994 and 1993, NGE incurred net losses of $6.0
million and $1.4 million, respectively.
Common Stock Dividend Policy
In October 1994 the board of directors reduced the quarterly
common stock dividend from 55 cents per share to 35 cents per
share. This dividend reduction allows the company to achieve
greater financial flexibility and strength and the company
believes it will offer improved shareholder value over the long
term. Financial flexibility will be essential in a competitive
environment, and stronger utilities will command higher stock
valuations.
The company can give no assurances as to future dividend
levels. Dividends will depend on the company's earnings and
financial requirements, developments in the utility industry and
other factors. The company's long-term goal is a dividend payout
ratio of 60% to 65% of earnings. The board of directors will
continue to review the common stock dividend each quarter to
ensure that it is consistent with the company's long-term
interests.
Net Cash Provided by Operating Activities
Cash provided by operating activities in 1994 increased $38
million, up 9% from 1993. The increase was primarily due to a
reduction in cash used for working capital items in 1994. Net
cash from operating activities is derived by adjusting reported
net income for charges or credits that have no cash effect
(primarily depreciation, amortization and deferred income taxes)
and changes in working capital items.
Net Cash Used in Investing Activities
In 1994, cash used in investing activities decreased $86
million, down 28% from 1993. The change was primarily due to a
decrease in expenditures for utility plant construction.
The company's 1994 capital expenditures for its core
electric and natural gas businesses totaled approximately
$248 million. Most of the expenditures were for the extension of
service, improvements at existing facilities, compliance with the
Clean Air Act Amendments of 1990, and other environmental
requirements. The company received $24 million from governmental
and other sources in 1994 to partially offset expenditures for
compliance with the Clean Air Act Amendments of 1990.
Capital expenditures projected for 1995-1997 have been
limited and reflect planned cuts of more than $200 million. This
represents one of the many actions the company is taking to
address competition. Capital expenditures will be primarily for
extension of service, necessary improvements at existing
facilities, the natural gas storage project, compliance with the
Clean Air Act Amendments of 1990 and other environmental
requirements (see Note 9). The company expects to finance these
capital expenditures entirely with internally generated funds.
The company forecasts that its current reserve margin, coupled
with more efficient use of energy (see Conservation Programs) and
purchases of power from NUGs, eliminates the need for additional
generating capacity until after the year 2007.
The following table provides information on the company's
estimated sources and uses of funds for 1995-1997. This forecast
is subject to periodic review and revision. Actual capital
expenditures may change to reflect the imposition of additional
regulatory requirements and the company's continued focus on
optimizing capital expenditures.
1995 1996 1997 Total
(Millions)
Sources of funds
Internal funds $298 $288 $284 $870
Long-term financing 39 - - 39
---- ---- ---- ----
Total $337 $288 $284 $909
==== ==== ==== ====
Uses of funds
Capital expenditures
Cash $185 $258 $180 $623
AFDC* 3 6 4 13
---- ---- ---- ----
Total capital
expenditures 188 264 184 636
Retirement of securities and
sinking fund obligations 63 26 78 167
Repayment of
short-term debt 55 20 33 108
Working capital, deferrals
and other 31 (22) (11) (2)
---- ---- ---- ----
Total $337 $288 $284 $909
==== ==== ==== ====
*Allowance for funds used during construction.
As shown in the preceding table, internal sources of funds
represent 137% of capital expenditures for 1995-1997.
Net Cash Used in Financing Activities
Cash used in financing activities in 1994 increased $106
million, up 96% from 1993. This increase reflects a reduction of
cash provided from the issuance of preferred stock and the use of
cash provided by operating activities to reduce debt levels.
The company believes that maintaining financial integrity
and flexibility is critical to success in a competitive
environment. The dividend reduction,along with recent cost
reductions,will allow future cash flows to meet all of the
company's operating and capital needs. The company plans to use
its strong cash flow in excess of operating and capital needs
primarily to reduce debt in preparation for competition. The
company will also use its cash flow to invest in both regulated
and unregulated businesses that relate to its core businesses and
that have the potential to grow and yield value for the company's
shareholders. Since 1987 the company has reduced its debt from
61.9% to 46.7% of total capital and has raised its common stock
equity from 32.7% to 46%. Its goal is to achieve a 50% common
equity ratio.
The common stock equity ratio improved in 1994 primarily as a
result of retained earnings, the issuance of shares pursuant to
the Dividend Reinvestment and Stock Purchase Plan (DRP), the
repayment at maturity of $100 million of 8 3/8% bonds in August
1994 and the repayment of the $50 million revolving credit
agreement note. The company received $22.7 million from the
issuance of 0.9 million shares of common stock through the DRP.
However, beginning in August 1994, the DRP began purchasing
shares on the open market rather than the company issuing new
shares. The company expects that the DRP will continue
purchasing shares on the open market as long as the market price
of the stock, which was below book value during the latter half
of 1994, remains below book value. Issuing new shares below book
value would decrease book value per share and lead to a decrease
in future earnings per share.
The following table indicates the company's financing activities
during 1994:
Interest
Month Description Rate Due Amount
Issuances (Thousands)
February (1) Pollution control note Various* Feb. 1, 2029 $37,500
April (2) Pollution control note 6.05% Apr. 1, 2034 $100,000
June (3) Pollution control note Various* June 1, 2029 $63,500
October (4) Pollution control note Various* Oct. 1, 2029 $74,000
* Multi-mode note, maturity could be extended to 2034 under certain
circumstances.
Redemptions/ Maturities
January Preferred stock-Series A Adj. Rate n/a $45,000
January Preferred stock 8.80% n/a $25,000
February Preferred stock 8.48% n/a $25,000
February First mortgage bond 8 5/8% Nov. 1, 2007 $23,000
August First mortgage bond 8 3/8% Aug. 15, 1994 $100,000
March Pollution control note 2.75% Mar. 1, 2015 $37,500
May Pollution control note 12.0% May 1, 2014 $60,000
July Pollution control note 12.30% July 1, 2014 $40,000
July Pollution control note 2.60% July 15, 2015 $63,500
December Pollution control note 2.80% Dec. 1, 2014 $74,000
May Revolving credit
agreement note 4.06% July 31, 1997 $50,000
(1) Proceeds were used to refund, in March 1994, $37.5 million of one-
year adjustable-rate pollution control revenue bonds, due 2015.
(2) Proceeds were used in connection with the redemption in May 1994 of
$60 million of 12.0% pollution control bonds, due 2014, and the
redemption in July 1994 of $40 million of 12.3% pollution control bonds,
due 2014.
(3) Proceeds were used to refund, in July 1994, $63.5 million of one-
year adjustable-rate pollution control revenue bonds, due 2015.
(4) Proceeds were used to refund, in December 1994, $74 million of one-
year adjustable-rate pollution control revenue bonds, due 2014.
The company reduced its embedded cost of long-term debt to
7.1% at the end of 1994 compared to 9.8% at the end of 1987. The
company has refinanced more than $1.5 billion in long-term debt
since the beginning of 1988 and reduced annual interest expense
by more than $60 million. Unless interest rates fall further it
will be difficult to significantly improve from the 7.1% level.
All opportunities will continue to be pursued aggressively.
The company uses short-term unsecured notes, usually
commercial paper, to finance certain refundings and for other
corporate purposes. There was $151.9 million of commercial paper
outstanding at December 31, 1994, at a weighted average interest
rate of 5.8%.
The company also has a revolving credit agreement with
certain banks that provides for borrowing up to $200 million to
July 31, 1997. The company had an outstanding $50 million loan
under this agreement at December 31, 1993, at an interest rate of
4.06%. This loan was repaid in May 1994.
During 1994 the company had its securities ratings
downgraded by both Standard & Poor's and Moody's Investors
Service. These downgrades reflect the rating agencies' use of
more stringent financial benchmarks in evaluating utilities, in
order to reflect increasing competition and mounting business
risks. More than one-quarter of the electric utility industry
had its securities ratings downgraded in the past 18 months.
The company is committed to its goal of achieving an 'A'
bond rating. The company plans to continue to strengthen its
balance sheet by paying down debt with excess cash.
Regulatory Matters
In September 1993 the company reached a three-year electric
and natural gas rate-settlement agreement with the PSC covering
the period August 1, 1993 through July 31, 1996. Under the
agreement, the allowed return on equity was 10.8% in year one,
11.4% in year two and 11.4% (subject to an indexing mechanism) in
year three. Shareholders were allowed to keep 100% of any
earnings above the allowed return in year one. Shareholders and
customers are to share, on a 50%/50% basis, any earnings over the
allowed return in years two and three. The calculation of
earnings over the allowed return includes regulatory adjustments
(such as the elimination of the impact of incentives and sharing
mechanisms) and certain normalizing adjustments (such as
spreading the 1993 restructuring charge over the term of the
settlement agreement). For year one, the twelve months ended
July 31, 1994, the company's earned return on equity, with
adjustments, as discussed above, was 10.3%. The earned returns
on electric equity and natural gas equity, with adjustments, were
10.1% and 12.7% respectively, for year one.
The agreement also includes a modified revenue decoupling
mechanism (RDM) for electric sales. Rates are based on sales
forecasts. Since actual sales may differ significantly from
forecasted sales because of conservation efforts, unusual weather
or changing economic conditions, revenues collected may be more
or less than forecasted. Subject to the limits described below,
the modified RDM lets the company adjust for most of the
differences between forecasted and actual sales. For example, if
revenues exceed the forecast for a given year, the excess is
passed back to customers in a future year. If revenues are below
the forecast, customers receive a surcharge in a future year.
The company must share revenue excesses or shortfalls from sales
to most large commercial and industrial customers on a 70%/30%
(customer/shareholder) basis. In 1994 the company accrued $22.3
million under the modified RDM compared with $3.9 million in
1993. In 1993 the modified RDM covered only the period August
through December.
Customer savings of $21 million in production and
transmission operating costs are imputed over the three years of
the agreement, at $7 million each year, whether or not such
savings are realized.
The estimated total electric price increases anticipated by
the agreement are $99.6 million, or 7.4%, in year one; $109.5
million, or 7.6% in year two; and $87.8 million, or 5.6% in year
three. These include base rate increases plus estimated price
increases for fuel, purchased power and other costs that are
collected through the fuel adjustment clause (FAC). Actual costs
collected through the FAC could vary from estimates, causing the
total electric price increases to change.
The base rate increases for natural gas allowed by the
agreement are $7.5 million, or 2.9%, in year one; $8.2 million,
or 3.0%, in year two; and $7.2 million, or 2.5%, in year three.
They do not include changes in natural gas costs, which will be
collected through the gas adjustment clause. Natural gas costs
can be expected to rise and fall with overall natural gas market
conditions. Such fluctuations will affect the total natural gas
price increases.
The agreement also provides for the stated base rate
increases for electricity and natural gas to be adjusted up or
down in the second and third years, as well as the year after the
agreement period (year four). Base rates can be adjusted for
several factors, such as electric sales, incentive mechanisms and
other true-ups from the prior year. The electric base rate
increases could be adjusted upward by up to 1.5% in years two and
three and 1.6% in year four. The natural gas base rate increases
could be adjusted upward by up to 1.0% in year two and 1.2% in
year three. The agreement does not specify a limit on the upward
adjustment for natural gas base rates for year four. There is no
limit to any downward adjustment of base rates for electric and
natural gas.
In June 1994 the company finalized its filing of adjustments
to the second-year electric and natural gas rates in accordance
with the terms of the agreement. The company took voluntary
action to lower the estimated total electric price increase to
7.8%. The electric price increase which was primarily due to
increases in mandated purchases of electricity from NUGs,
increases in taxes and sales shortfalls related to mandated
conservation programs and the weak economy in New York State,
would have been substantially greater than 7.8% without the
voluntary action. The filed natural gas base rate increase was
1.9%. On August 15, 1994, the PSC issued an Opinion and Order
that approved the electric price increase of 7.8% and the 1.9%
natural gas base rate increase effective August 1, 1994. In
addition, the PSC directed the company and staff of the PSC to
begin discussions on modifying the agreement to mitigate the
projected third-year electric increase and bring rate
predictability and stability to future years. Those discussions
began in October 1994 and are continuing.
The agreement provides incentives (rewards or penalties) to
the company for controlling production costs (PCI), improving
customer service and implementing DSM programs. Those incentives
could have increased the company's allowed return to 12.3% or
decreased it to 9.95% in year one, increase it to 13.05% or
decrease it to 10.4% in year two, and increase it to 13.25% or
decrease it to 10.2% in year three. In June 1994 the company
calculated and recorded a production-cost penalty for 1993 of
$13.0 million, or 12 cents per share. This was the maximum
permitted by the agreement.
The PCI is based on a comparison of the company with a 19-
company peer group (which includes the company). The production
measure compared is the relative change in production and certain
other costs per megawatt-hour of retail sales occurring between
the applicable calendar year and a base period (1989-1992). The
company calculated the PCI penalty for 1993 using data reported
in the peer group's FERC Form 1 Reports, which the company
received in May 1994. The company's PCI penalty for 1993 was due
primarily to a significantly lower increase in retail sales
(after adjusting for the effect of sales lost due to DSM
programs) for the company than for the peer group. It was also
due to a greater increase in DSM program costs and purchased
power costs for the company than for the peer group.
The company believes that a penalty for its PCI performance
in 1994 is unlikely. This is primarily because of the company's
recent cost-reduction efforts and improved sales compared to the
sales increase of the peer group, which is projected to be less
than the peer group's sales increase in 1993. This estimate
includes the company's actual performance through December 31,
1994. However, it was necessary to make certain assumptions
regarding the peer group's 1994 performance since the actual
information needed for this calculation will not be available
until the peer group's FERC Form 1 Reports become available in
May 1995. As an example, retail sales units and certain
production costs for the peer group were assumed to continue at
the levels achieved through the first nine months of 1994. The
maximum PCI allowed for 1994 by the agreement is a reward or
penalty of $17.5 million, or 16 cents per share.
Conservation Programs
The company has implemented a number of DSM programs. As
part of its three-year rate agreement (see Regulatory Matters),
the rewards the company could earn for conducting efficient DSM
programs were reduced from 15% to 5% of the net resource savings
achieved by these programs. For 1995 the company expects to earn
approximately $1 million in rewards as a result of DSM programs.
In 1994 customers saved approximately 64 million kilowatt-
hours (kwh) on an annualized basis through DSM programs. These
programs cost $14 million in 1994 and will cost approximately $11
million in 1995. The customer savings estimated for 1995 are 54
million kwh on an annualized basis. At both December 31, 1994
and 1993, the company had approximately $73 million of deferred
DSM program costs on its consolidated balance sheets. The two-
year (1993-1994) DSM plan, which received PSC approval, was
modified to improve cost-effectiveness and reduce rate impacts.
In August 1994 the company submitted its 1995 DSM plan to the PSC
proposing DSM goals and budgets for the years 1995 through 2000.
The company expects to change its DSM approach in 1995 to move
toward promoting energy-efficient equipment in the mass market
and phasing out rebates for individual customers.
Environmental Matters
The company continually assesses actions that may need to be
taken to ensure compliance with changing environmental laws and
regulations. Any additional compliance programs will increase
the cost of electric and natural gas service by requiring changes
in the company's operations and facilities. Historically, rate
recovery has been authorized for the cost incurred to comply with
environmental laws and regulations (See Note 9 and Note 10).
Results of Operations
1994 1993
over over
1993 1992
1994 1993 1992 Change Change
(Thousands, except per share amounts)
Operating revenues $1,898,855 $1,800,149 $1,691,689 5% 6%
Earnings available for
common stock $168,698 $145,390 $162,973 16% (11%)
Average shares outstanding 71,254 69,990 67,972 2% 3%
Earnings per share $2.37 $2.08 $2.40 14% (13%)
Dividends per share $2.00 $2.18 $2.14 (8%) 2%
Total operating revenues in 1994 increased $99 million, up
5% over 1993. In 1993, total operating revenues increased $108
million, up 6% from 1992. These results are discussed according
to business segment beginning on page 44.
Earnings per Share
In 1994 earnings per share increased 29 cents, up 14% over
1993, while in 1993 earnings per share decreased 32 cents, down
13% from 1992. Certain nonrecurring items lowered earnings per
share for 1993 and 1992. Earnings in 1993 were reduced 25 cents
per share by the corporate restructuring that reorganized the way
the company delivers services to its electric and natural gas
customers beginning in March 1994 (see Note 6). Earnings in 1992
were 24 cents per share lower than they otherwise would have been
because of a six-month moratorium on electric rate increases that
began in February 1992. Without these nonrecurring items,
earnings per share were up 4 cents in 1994 compared to 1993, and
were down 31 cents in 1993 compared to 1992.
The increase in 1994 earnings per share without the
nonrecurring items was due to a combination of factors. Lower
operation and maintenance expenses that resulted from cost
controls and the workforce reduction helped 1994 earnings by 26
cents per share. Also, on a comparative basis, 1994 earnings
rose because lower electric retail sales in 1993 before the
effective date of the company's modified RDM reduced 1993
earnings 9 cents per share. These increases in earnings per
share were partially offset by the reduction in rewards earned
from the company's DSM programs that lowered earnings by 13 cents
per share; the 1993 production-cost penalty recorded in the
second quarter of 1994 that reduced earnings by 12 cents per
share; and losses incurred by the company's diversified
operations that lowered earnings by 7 cents per share.
The decrease in 1993 earnings per share without the
nonrecurring items was mainly due to lower electric retail sales
before the effective date of the company's modified RDM, and to
lower-than-anticipated natural gas sales. Both of these results
were due to the sluggish economy in the company's service
territory. Also, earnings per share decreased because of
reductions in the company's allowed return on equity, from 11.7%
effective through July 1992, to 11.2% effective through July
1993, and then to 10.8% beginning in August 1993.
Interest Expense
Interest expense (before the reduction for allowance for
borrowed funds used during construction) decreased by $6 million,
or 4% in 1994, and $10 million, or 6% in 1993. Interest on long-
term debt decreased in 1994 and 1993 mainly due to the
refinancing or refunding of certain high-coupon long-term debt.
In 1993 interest expense also decreased due to lower interest
rates on the company's variable rate debt.
Average Shares Outstanding
Average shares outstanding were 71 million in 1994, 70
million in 1993 and 68 million in 1992. The increases in average
shares outstanding, 2% in 1994, and 3% in 1993, were both due to
the issuance of shares of common stock through the DRP. A total
of 0.9 million shares of common stock were issued through the DRP
in 1994, and 1.2 million shares were issued in 1993. The number
of shares issued in 1994 was lower than in 1993 because the DRP
began purchasing shares on the open market as of August 1994
rather than the company issuing new shares. The company expects
that the DRP will continue purchasing shares on the open market
as long as the market price of the stock, which was below book
value during the latter half of 1994, remains below book value.
Issuing new shares below book value would decrease book value per
share and lead to a decrease in future earnings per share.
Dividends per Share
Dividends decreased 8% in 1994 because the board of
directors reduced the quarterly common stock dividend from 55
cents per share to 35 cents per share in October 1994 (see Common
Stock Dividend Policy).
Operating Results for the Electric Business Segment
1994 1993
over over
1993 1992
1994 1993 1992 Change Change
(Thousands)
Retail sales - kilowatt -
hours(kwh) 13,147,631 13,088,175 13,294,466 - (2%)
Operating revenues $1,600,075 $1,527,362 $1,451,525 5% 5%
Operating expenses $1,306,871 $1,250,000 $1,146,619 5% 9%
Operating income $293,204 $277,362 $304,906 6% (9%)
Electric retail sales for 1994 were up slightly compared to
1993 sales. In 1993, electric retail sales were down 2% from
1992 (despite a 1% increase in customers) due to the sluggish
economy in the company's service territory.
Operating Revenues
Electric operating revenues increased by $73 million, or 5%,
in 1994, and by $76 million, or 5%, in 1993. The more
significant items contributing to these changes are as follows:
1994 1993
(Millions)
Rate changes $69 $53
RDM 18 4
Recovery of increases in NUG power
through fuel adjustment clause (FAC) 16 28
Interchange profits 16 -
DSM incentives (14) -
DSM lost revenues (15) -
Production-cost penalty (13) -
Other (4) (9)
--- ---
Total increase $73 $76
=== ===
Changes in electric rates effective in September 1993 and August
1994 were the principal reason for higher 1994 revenues. The
rate changes were caused primarily by an increase in mandated
purchases of NUG power and by higher federal taxes. The modified
RDM contributed to revenues since actual electric sales in 1994
were below the levels forecasted in the company's rate agreement.
Higher costs of NUG power, which are billed to customers in part
through the FAC, also boosted 1994 revenues. Interchange profits
helped revenues due to an increase in interchange sales volume
over 1993. These increases were partially offset by a decrease
in rewards earned from DSM programs, a decrease in DSM lost
revenues recorded and the 1993 production-cost penalty recorded
in the second quarter of 1994.
The $76 million, or 5%, increase in electric operating
revenues in 1993 was primarily due to rate changes effective in
August 1992 and September 1993, mainly the result of an increase
in mandated purchases of NUG power and rising taxes. Higher
costs of NUG power (billed to customers in part through the FAC)
also contributed to the growth in revenues.
Operating Expenses
Electric operating expenses in 1994 increased $57 million,
or 5%, over the 1993 level. The principal cause was an increase
of $80 million in electricity purchased, primarily purchases from
NUGs. Federal income taxes grew by $17 million, the result of
higher pretax book income. Gross receipts taxes and school taxes
added another $7 million to expenses. Depreciation expense rose
$12 million compared to 1993. Those increases were partially
offset by decreases of $15 million in operating expenses (mainly
due to cost controls and the workforce reduction) and $14 million
in fuel used in electric generation (due to reduced generation).
Also, expenses were $21 million lower in 1994 because of the
restructuring charge recorded in the fourth quarter of 1993.
In 1993 electric operating expenses were $103 million, or
9%, higher than in 1992. The major contributor to this increase
was electricity purchased from NUGs, which rose by $67 million.
Postretirement-benefit costs other than pensions increased $7
million. Corporate restructuring added another $21 million to
electric operating expenses. These increases were partially
offset by a $17 million decrease in fuel used in electric
generation (the result of reduced generation and a lower price
for coal) and by a $12 million decrease in federal income taxes
(the result of lower pretax book income).
Operating Results for the Natural Gas Business Segment
1994 1993
over over
1993 1992
1994 1993 1992 Change Change
(Thousands)
Deliveries -
dekatherms (dth) 58,624 58,046 56,366 1% 3%
Operating revenues $298,780 $272,787 $240,164 10% 14%
Operating expenses $269,300 $249,493 $221,307 8% 13%
Operating income $29,480 $23,294 $18,857 27% 24%
Natural gas deliveries rose by 1% in 1994 and by 3% in 1993.
The increase in deliveries in 1994 and 1993 was due to the
addition of new customers, including several large volume
customers.
Operating Revenues
Natural gas operating revenues rose by $26 million, or 10%,
in 1994, and by $33 million, or 14%, in 1993. The more
significant items that contributed to these changes are as
follows:
1994 1993
(Millions)
Natural gas price increases $16 $23
Rate changes 7 8
Other 3 2
--- ---
Total increase $26 $33
=== ===
Higher costs of natural gas (billed to customers) were the
primary reason for the rise in 1994 revenues. Rate changes
effective in September 1993 and August 1994 also added to
revenues. However, since the company has a weather normalization
mechanism for natural gas, $0.9 million of revenues attributable
to colder weather was returned to customers in 1994.
In 1993 the leading contributors to the increase in revenues
were higher costs of natural gas and the rate changes that became
effective in August 1992 and September 1993. Revenues of $1.0
million were returned to customers in 1993 through the weather
normalization mechanism.
Operating Expenses
Natural gas operating expenses were up by $20 million, or
8%, in 1994, mainly because of an increase of $20 million in
natural gas purchased that was mostly due to higher prices.
Higher federal income taxes increased operating expenses by $4
million, due to higher pretax book income. Gross receipts taxes
and school taxes added another $1 million to expenses.
Depreciation expense rose $2 million compared to 1993. Those
increases were partially offset by a decrease of $5 million
because of the restructuring charge recorded in 1993 and a $1
million decrease in marketing expenses due to improved
operations.
Operating expenses in 1993 increased $28 million, up 13%
from their 1992 level. Natural gas purchased rose by $12
million, mainly because of higher natural gas prices. Federal
income taxes increased $3 million due to higher pretax book
income. Corporate restructuring added $5 million to natural gas
operating expenses.
Item 8. Financial Statements and Supplementary Data
New York State Electric & Gas Corporation
Consolidated Balance Sheets
December 31 1994 1993
- -------------------------------------------------------------------------------
(Thousands)
Assets
Utility Plant, at Original Cost (Note 1)
Electric (Note 8). . . . . . . . . . . . . . . . . . . $4,916,960 $4,777,368
Natural gas. . . . . . . . . . . . . . . . . . . . . . 414,929 381,389
Common . . . . . . . . . . . . . . . . . . . . . . . . 143,366 158,986
---------- ----------
. . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,475,255 5,317,743
Less accumulated depreciation. . . . . . . . . . . . . 1,642,653 1,535,307
---------- ----------
Net Utility Plant in Service. . . . . . . . . . . 3,832,602 3,782,436
Construction work in progress. . . . . . . . . . . . . 154,723 143,859
---------- ----------
Total Utility Plant . . . . . . . . . . . . . . . 3,987,325 3,926,295
Other Property and Investments, Net (Note 12) . . . . . 103,920 73,537
Current Assets
Cash and cash equivalents (Notes 1 and 13) . . . . . . 22,322 4,264
Special deposits (Note 13) . . . . . . . . . . . . . . 7,591 145,335
Accounts receivable, net (Note 1). . . . . . . . . . . 155,665 181,586
Fuel, at average cost. . . . . . . . . . . . . . . . . 49,934 54,791
Materials and supplies, at average cost. . . . . . . . 47,843 48,910
Prepayments. . . . . . . . . . . . . . . . . . . . . . 30,441 30,092
Accumulated deferred federal income
tax benefits, net (Notes 1 and 2) . . . . . . . . . 11,457 -
---------- ----------
Total Current Assets. . . . . . . . . . . . . . . . 325,253 464,978
Deferred Charges (Note 1)
Unfunded future federal income
taxes (Notes 1 and 2) . . . . . . . . . . . . . . . 363,151 380,056
Unamortized debt expense . . . . . . . . . . . . . . . 114,444 112,059
Demand-side management program costs . . . . . . . . . 72,849 73,113
Other. . . . . . . . . . . . . . . . . . . . . . . . . 255,963 257,920
---------- ----------
Total Deferred Charges. . . . . . . . . . . . . . 806,407 823,148
---------- ----------
Total Assets. . . . . . . . . . . . . . . . . . . $5,222,905 $5,287,958
========== ==========
The notes on pages 53 through 79 are an integral part of the financial
statements.
New York State Electric & Gas Corporation
Consolidated Balance Sheets
December 31 1994 1993
- ------------------------------------------------------------------------------
(Thousands)
Capitalization and Liabilities
Capitalization
Common stock equity
Common stock ($6.66 2/3 par value, 90,000,000
shares authorized and 71,502,827 and 70,595,985
shares issued and outstanding at December 31,
1994 and 1993, respectively) . . . . . . . . . . $476,686 $470,640
Capital in excess of par value. . . . . . . . . . 841,624 824,943
Retained earnings . . . . . . . . . . . . . . . . 346,547 320,114
---------- ----------
Total common stock equity. . . . . . . . . . . . . . . 1,664,857 1,615,697
Preferred stock redeemable solely at the option of
the company (Note 4). . . . . . . . . . . . . . . . 140,500 140,500
Preferred stock subject to mandatory redemption
requirements (Notes 4 and 13) . . . . . . . . . . . 125,000 125,000
Long-term debt (Notes 3 and 13). . . . . . . . . . . . 1,651,081 1,630,629
---------- ----------
Total Capitalization. . . . . . . . . . . . . . . 3,581,438 3,511,826
Current Liabilities
Current portion of long-term debt (Note 3) . . . . . . 36,231 237,709
Current portion of preferred stock (Note 4). . . . . . - 95,000
Notes payable (Notes 5 and 13) . . . . . . . . . . . . 151,900 50,200
Accounts payable and accrued liabilities . . . . . . . 107,356 111,481
Interest accrued (Note 13) . . . . . . . . . . . . . . 25,132 31,348
Accumulated deferred federal income taxes, net
(Notes 1 and 2) . . . . . . . . . . . . . . . . . . - 1,132
Other. . . . . . . . . . . . . . . . . . . . . . . . . 94,961 89,443
---------- ----------
Total Current Liabilities . . . . . . . . . . . . 415,580 616,313
Deferred Credits and Other Liabilities
Accumulated deferred investment tax credit
(Notes 1 and 2) . . . . . . . . . . . . . . . . . . 132,440 138,478
Excess deferred federal income taxes (Notes 1 and 2) . 34,040 36,378
Other postretirement benefits. . . . . . . . . . . . . 55,887 28,074
Liability for environmental restoration (Note 10). . . 33,600 26,800
Other. . . . . . . . . . . . . . . . . . . . . . . . . 131,585 133,488
---------- ----------
Total Deferred Credits and Other Liabilities. . . 387,552 363,218
Accumulated Deferred Federal Income Taxes
(Notes 1 and 2)
Unfunded future federal income taxes . . . . . . . . . 363,151 380,056
Other. . . . . . . . . . . . . . . . . . . . . . . . . 475,184 416,545
---------- ----------
Total Accumulated Deferred Federal
Income Taxes . . . . . . . . . . . . . . . . . . 838,335 796,601
Commitments and Contingencies (Note 9). . . . . . . . . - -
---------- ----------
Total Capitalization and Liabilities. . . . . . . $5,222,905 $5,287,958
========== ==========
The notes on pages 53 through 79 are an integral part of the financial
statements.
New York State Electric & Gas Corporation
Consolidated Statements of Income
Year Ended December 31 1994 1993 1992
- ----------------------------------------------------------------------------
(Thousands, except per share amounts)
Operating Revenues
Electric . . . . . . . . . . . . . . . . $1,600,075 $1,527,362 $1,451,525
Natural gas. . . . . . . . . . . . . . . 298,780 272,787 240,164
---------- ---------- ----------
Total Operating Revenues . . . . . . 1,898,855 1,800,149 1,691,689
---------- ---------- ----------
Operating Expenses
Fuel used in electric generation . . . . 231,648 245,283 262,531
Electricity purchased (Note 9) . . . . . 242,352 161,967 95,026
Natural gas purchased. . . . . . . . . . 161,627 141,635 126,815
Other operating expenses . . . . . . . . 328,961 349,177 318,680
Restructuring expenses (Notes 6 and 7) . - 26,000 -
Maintenance. . . . . . . . . . . . . . . 106,637 111,757 102,500
Depreciation and amortization (Note 1) . 178,326 164,568 158,977
Federal income taxes (Notes 1 and 2) . . 115,891 94,144 102,456
Other taxes . . . . . . . . . . . . . . 210,729 204,962 200,941
---------- ---------- ----------
Total Operating Expenses . . . . . . . 1,576,171 1,499,493 1,367,926
---------- ---------- ----------
Operating Income. . . . . . . . . . . . . 322,684 300,656 323,763
Other Income and Deductions (Note 12) . . 1,053 6,471 12,036
---------- ---------- ----------
Income Before Interest Charges. . . . . . 323,737 307,127 335,799
---------- ---------- ----------
Interest Charges
Interest on long-term debt . . . . . . . 126,083 134,330 145,822
Other interest . . . . . . . . . . . . . 13,642 11,120 9,566
Allowance for borrowed funds
used during construction. . . . . . . . (3,633) (4,351) (3,557)
---------- ---------- ----------
Interest Charges, Net. . . . . . . . . 136,092 141,099 151,831
---------- ---------- ----------
Net Income. . . . . . . . . . . . . . . . 187,645 166,028 183,968
Preferred Stock Dividends . . . . . . . . 18,947 20,638 20,995
---------- ---------- ----------
Earnings Available for Common Stock . . . $168,698 $145,390 $162,973
========== ========== ==========
Earnings Per Share. . . . . . . . . . . . $2.37 $2.08 $2.40
Average Shares Outstanding. . . . . . . . 71,254 69,990 67,972
The notes on pages 53 through 79 are an integral part of the
financial statements.
New York State Electric & Gas Corporation
Consolidated Statements of Cash Flows
Year Ended December 31 1994 1993 1992
- ------------------------------------------------------------------------------
(Thousands)
Operating Activities
Net income . . . . . . . . . . . . . . . . . . . . $187,645 $166,028 $183,968
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization. . . . . . . . . . 178,326 164,568 158,977
Deferred fuel and purchased gas. . . . . . . . . (1,944) (10,671) (14,645)
Federal income taxes and investment tax credits
deferred, net. . . . . . . . . . . . . . . . . 13,670 50,761 52,039
Unbilled revenue amortization (Note 1) . . . . . (3,769) (5,335) (10,451)
Demand-side management program costs . . . . . . 264 (29,064) (22,863)
Restructuring expenses . . . . . . . . . . . . . - 26,000 -
Changes in current operating assets and liabilities:
Special deposits . . . . . . . . . . . . . . . . 42,744 2,438 (1,873)
Accounts receivable excluding accounts
receivable sold. . . . . . . . . . . . . . . . 25,921 (23,703) (38,345)
Accounts receivable sold (Note 1). . . . . . . . - 13,800 -
Prepayments. . . . . . . . . . . . . . . . . . . (349) 7,805 (878)
Inventory. . . . . . . . . . . . . . . . . . . . 5,924 16,013 (1,376)
Accounts payable and accrued liabilities . . . . (4,125) 15,485 (4,851)
Interest accrued . . . . . . . . . . . . . . . . (6,216) (6,342) (5,750)
Other, net . . . . . . . . . . . . . . . . . . . . 12,287 24,407 (7,685)
-------- -------- --------
Net Cash Provided by Operating Activities . . . 450,378 412,190 286,267
-------- -------- --------
Investing Activities
Utility plant capital expenditures, net of
allowance for other funds used during
construction . . . . . . . . . . . . . . . . . . (246,536)(265,109)(243,373)
Proceeds received from governmental and
other sources . . . . . . . . . . . . . . . . . 23,915 22,808 322
Expenditures for other property and investments. . (34,482) (16,975) -
Funds restricted for capital expenditures. . . . . 41,113 (42,437) -
-------- -------- --------
Net Cash Used in Investing Activities . . . . . (215,990)(301,713)(243,051)
-------- -------- --------
Financing Activities
Issuance of pollution control notes and
first mortgage bonds . . . . . . . . . . . . . . 275,000 217,362 247,668
Proceeds from revolving credit agreement note. . . - 50,000 -
Sale of common stock . . . . . . . . . . . . . . . 23,386 38,334 162,965
Sale of preferred stock. . . . . . . . . . . . . . - 97,762 -
Repayments of pollution control notes,
first mortgage bonds and preferred
stock, including premiums. . . . . . . . . . . . (497,450)(326,091)(178,289)
Repayment of revolving credit agreement note . . . (50,000) - -
Changes in funds set aside for preferred stock
and first mortgage bond repayments . . . . . . . 95,000 (8,904) (83,096)
Long-term notes, net . . . . . . . . . . . . . . . (2,290) 8,393 (1,593)
Notes payable, net . . . . . . . . . . . . . . . . 101,700 (13,900) (39,800)
Dividends on common and preferred stock. . . . . . (161,676)(173,137)(165,704)
-------- -------- --------
Net Cash Used in Financing Activities . . . . . (216,330)(110,181) (57,849)
-------- -------- --------
Net Increase (Decrease) in Cash and Cash Equivalents 18,058 296 (14,633)
Cash and Cash Equivalents, Beginning of Year. . . . 4,264 3,968 18,601
-------- -------- --------
Cash and Cash Equivalents, End of Year
(Notes 1 and 13). . . . . . . . . . . . . . . . . $22,322 $4,264 $3,968
======== ======== ========
The notes on pages 53 through 79 are an integral part of the
financial statements.
New York State Electric & Gas Corporation
Consolidated Statements of Changes
in Common Stock Equity
(Thousands, except shares and per share amounts)
Common Stock Capital
$6.66 2/3 Par Value in Excess Retained
Shares Amount of Par Value Earnings Total
Balance, January 1, 1992 63,400,238 $422,668 $673,791 $308,688 $1,405,147
Net income 183,968 183,968
Cash dividends declared:
Preferred stock (at serial rates)
Redeemable - optional (11,164) (11,164)
- mandatory (9,831) (9,831)
Common stock ($2.14 per share) (144,621) (144,621)
Issuance of stock:
Public offering 5,000,000 33,333 99,367 132,700
Dividend reinvestment and
stock purchase plan 1,039,159 6,928 23,347 30,275
Balance, December 31, 1992 69,439,397 462,929 796,505 327,040 1,586,474
Net income 166,028 166,028
Cash dividends declared:
Preferred stock (at serial rates)
Redeemable - optional (11,085) (11,085)
- mandatory (9,553) (9,553)
Common stock ($2.18 per share) (152,316) (152,316)
Issuance of stock:
Dividend reinvestment and
stock purchase plan 1,156,588 7,711 28,438 36,149
Balance, December 31, 1993 70,595,985 470,640 824,943 320,114 1,615,697
Net income 187,645 187,645
Cash dividends declared:
Preferred stock (at serial rates)
Redeemable - optional (8,419) (8,419)
- mandatory (10,528) (10,528)
Common stock ($2.00 per share) (142,265) (142,265)
Issuance of stock:
Dividend reinvestment and
stock purchase plan 906,842 6,046 16,681 22,727
Balance, December 31, 1994 71,502,827 $476,686 $841,624 $346,547 $1,664,857
The notes on pages 53 through 79 are an integral part of the financial statements.
Notes to Consolidated Financial Statements
1 Significant Accounting Policies
Principles of consolidation
The consolidated financial statements include the company's wholly-owned
subsidiaries, Somerset Railroad Corporation (SRC) and NGE Enterprises, Inc.
(NGE). All significant intercompany balances and transactions are eliminated
in consolidation.
Utility plant
The cost of repairs and minor replacements is charged to the appropriate
operating expense accounts. The cost of renewals and betterments, including
indirect costs, is capitalized. The original cost of utility plant retired or
otherwise disposed of and the cost of removal less salvage are charged to
accumulated depreciation.
Depreciation and amortization
Depreciation expense is determined using straight-line rates, based on the
average service lives of groups of depreciable property in service.
Depreciation accruals were equivalent to 3.5%, 3.4% and 3.3%, of average
depreciable property for 1994, 1993 and 1992 respectively. Depreciation
expense includes the amortization of certain deferred charges authorized by the
Public Service Commission of the State of New York (PSC).
Revenue
During 1994, 1993 and 1992 the company recognized on the income statement
approximately $4 million, $5 million and $10 million, respectively, of electric
and natural gas unbilled revenues that had been accrued on its balance sheet
for energy provided but not yet billed to minimize the rate increases for these
years in accordance with various PSC rate decisions. The July 1992 rate
decision allowed the company to recognize on its income statement, beginning in
August 1992, electric and natural gas unbilled revenues on a full accrual
basis.
The company recognizes as revenue, incentives earned as the result of
conducting efficient demand-side management (DSM) programs. The company is
collecting those incentives in rates within approximately one year after they
are recognized. During 1994, 1993 and 1992 incentives earned were $2 million,
$16.4 million and $15.6 million, respectively. At December 31, 1994 and 1993,
approximately $1.2 million and $14.3 million, respectively, of DSM incentives
were accrued and included in accounts receivable.
Accounts receivable
The company has an agreement that expires in November 1996 to sell, with
limited recourse, undivided percentage interests in certain of its accounts
receivable from customers. The agreement allows the company to receive up to
$152 million from the sale of such interests. At December 31, 1994 and 1993,
accounts receivable on the consolidated balance sheets are shown net of
$152 million of interests in accounts receivable sold. All fees associated
with the program are included in other income and deductions on the
consolidated statements of income and amounted to approximately $7.4 million,
$5.7 million and $6.5 million in 1994, 1993 and 1992, respectively. Accounts
receivable on the consolidated balance sheets is also shown net of an allowance
for doubtful accounts of $7.2 million and $4 million at December 31, 1994 and
1993, respectively. Bad debt expense was $19.6 million, $15.3 million and
$11.5 million in 1994, 1993 and 1992, respectively.
Income taxes
The company adopted Statement of Financial Accounting Standards No. 109
(SFAS 109), Accounting for Income Taxes, in January 1993. Since the company
had been accounting for income taxes under Statement of Financial Accounting
Standards No. 96, Accounting for Income Taxes, there was no effect on the
consolidated statements of income as a result of adopting SFAS 109. However,
SFAS 109 did require the company's deferred tax balances to be reclassified on
its consolidated balance sheets.
The company files a consolidated federal income tax return with SRC and
NGE. Deferred income taxes are provided on all temporary differences between
financial statement basis and taxable income. Investment tax credits, which
reduce federal income taxes currently payable, are deferred and amortized over
the estimated lives of the applicable property. The effect of the alternative
minimum tax (AMT), which increases federal income taxes currently payable and
generates a tax credit available for future use, is deferred and amortized at
such times as the tax credit is used on the company's federal income tax
return.
Deferred charges
The company defers certain incurred expenses when authorized by the PSC.
Those expenses will be recovered from customers in the future.
Consolidated Statements of Cash Flows
The company considers all highly liquid investments with a maturity or put
date of three months or less when acquired to be cash equivalents. These
investments are included in cash and
cash equivalents on the consolidated balance sheets.
Total income taxes paid were $69.2 million, $27.0 million and $37.6
million for the years ended December 31, 1994, 1993 and 1992, respectively.
Interest paid, net of amounts capitalized, was $132.0 million, $138.2
million and $149.3 million for the years ended December 31, 1994, 1993 and
1992, respectively.
Reclassifications
Certain amounts have been reclassified on the consolidated financial
statements to conform with the 1994 presentation.
2 Income Taxes
Year ended December 31 1994 1993 1992
(Thousands)
Charged to operations
Current $88,623 $34,989 $37,237
Deferred, net
Accelerated depreciation 51,736 49,580 41,492
Unbilled revenues (3,913) 5,073 160
Revenue decoupling mechanism 6,870 - -
AMT credit (4,744) (3,194) 2,123
Demand-side management (9,048) 13,479 9,324
NUG termination agreement (1,313) 6,208 8,500
Nine Mile No. 2 litigation
proceeds (520) 4,756 (2,047)
Restructuring expenses - (6,965) -
Postretirement benefits (5,079) (3,492) (593)
Transmission facility
agreement (2,719) (7,778) (1,172)
Miscellaneous (3,970) (4,154) (4,598)
Investment tax credit (ITC) (32) 5,642 12,030
-------- ------- -------
115,891 94,144 102,456
Included in other income
Amortization of deferred ITC (6,006) (8,892) (16,927)
Miscellaneous (7,424) 498 3,747
-------- ------- -------
Total $102,461 $85,750 $89,276
======== ======= =======
The company's effective tax rate differed from the statutory rate of 35% in
1994 and 1993 and 34% in 1992 due to the following:
Year ended December 31 1994 1993 1992
(Thousands)
Tax expense at statutory rate $101,537 $88,684 $92,903
Depreciation not normalized 18,552 16,984 16,697
ITC amortization (6,006) (8,892) (16,927)
Revenue Reconciliation Act
of 1993, net (3,736) (631) -
Research & Development (R&D)
credit (1,352) (5,139) -
Cost of removal (5,462) (4,921) (4,079)
Other, net (1,072) (335) 682
-------- ------- -------
Total $102,461 $85,750 $89,276
======== ======= =======
The company's deferred tax assets and liabilities consist of the
following:
December 31 1994 1993
(Thousands)
Current Deferred Taxes
Demand-side management $(548) $(9,897)
Unbilled revenue 4,449 (783)
Pension expense 3,748 5,600
Other 3,808 3,948
------- -------
Total current deferred taxes $11,457 $(1,132)
------- -------
Noncurrent Deferred Taxes
Depreciation $(740,961) $(698,939)
Loss on reacquired debt (26,663) (28,440)
Regulatory asset (SFAS 109) (143,285) (149,636)
Deferred ITC (net of SFAS 109) (86,205) (91,006)
Demand-side management (25,785) (25,484)
NUG contract settlement costs (13,850) (15,163)
AMT credit 16,716 19,953
Excess tax reserve 11,788 12,603
Nine Mile No. 2 disallowed plant 13,519 19,347
Contributions in aid of
construction 20,050 20,913
Capitalized interest 10,280 8,690
Other (4,168) (7,255)
--------- ---------
Total noncurrent deferred taxes $(968,564) $(934,417)
--------- ---------
Total deferred taxes $(957,107) $(935,549)
Valuation allowance (2,211) (662)
--------- ---------
Net deferred taxes $(959,318) $(936,211)
========= =========
The Revenue Reconciliation Act of 1993 (RRA 1993), enacted on August 10,
1993, provided among other things, for an increase of 1% in the statutory
corporate income tax rate and an extension of the R&D credit until June 30,
1995.
In September 1993 the company reached a three-year rate settlement
agreement with the PSC which included a provision for the company to petition
to defer the effect of RRA 1993 until it is reflected in rates. The changes
related to RRA 1993 were reflected in rates beginning August 1, 1994.
The company has recorded unfunded future federal income taxes and a
corresponding receivable from customers of approximately $363 million and
$381 million as of December 31, 1994 and 1993, respectively, primarily
representing the cumulative amount of federal income taxes on temporary
depreciation differences, which were previously flowed through to customers.
Those amounts, including the tax effect of the future revenue requirements, are
being amortized over the life of the related depreciable assets concurrent with
their recovery in rates.
The company has approximately $16.7 million of AMT credits that do not
expire.
3 Long-Term Debt
At December 31, 1994 and 1993, long-term debt was (Thousands):
First mortgage bonds
Amount
Series Due 1994 1993
8 3/8% Aug. 15, 1994 $ - $100,000
5 5/8% Jan. 1, 1997 25,000 25,000
6 1/4% Sept. 1, 1997 25,000 25,000
6 1/2% Sept. 1, 1998 30,000 30,000
7 5/8% Nov. 1, 2001 50,000 50,000
6 3/4% Oct. 15, 2002 150,000 150,000
7 1/4% June 1, 2006 12,000 12,000
6 7/8% Dec. 1, 2006 25,000 25,250
8 5/8% Nov. 1, 2007 37,000 60,000
9 7/8% Feb. 1, 2020 100,000 100,000
9 7/8% May 1, 2020 100,000 100,000
9 7/8% Nov. 1, 2020 100,000 100,000
8 7/8% Nov. 1, 2021 150,000 150,000
8.30% Dec. 15, 2022 100,000 100,000
7.55% Apr. 1, 2023 50,000 50,000
7.45% July 15, 2023 100,000 100,000
--------- ---------
Total first mortgage bonds 1,054,000 1,177,250
========= =========
Pollution control notes
Interest Maturity Interest Rate Letter of Credit Amount
Rate Date Adjustment Date Expiration Date 1994 1993
12% May 1, 2014 - - - 60,000
12.30% July 1, 2014 - - - 40,000
2.80% Dec. 1, 2014 - - - 74,000
2.75% Mar. 1, 2015 - - - 37,500
3.25%(1) Mar. 15, 2015 Mar. 15, 1995 Mar. 31, 1996 60,000 60,000
2.60% July 15, 2015 - - - 63,500
4.10%(1) Oct. 15, 2015 Oct. 15, 1995 Oct. 31, 1996 30,000 30,000
4.60%(1) Dec. 1, 2015 Dec. 1, 1995 Dec. 15, 1996 42,000 42,000
4.10%(1) July 1, 2026 July 1, 1996 July 15, 1996 65,000 65,000
5.95% Dec. 1, 2027 - - 34,000 34,000
5.70% Dec. 1, 2028 - - 70,000 70,000
Var.%(2) Feb. 1, 2029 Various Feb. 23, 1996 37,500 -
Var.%(2) June 1, 2029 Various June 15, 1996 63,500 -
Var.%(2) Oct. 1, 2029 Various Oct. 25, 1996 74,000 -
6.05% Apr. 1, 2034 - - 100,000 -
---------- ---------
Total pollution control notes 576,000 576,000
========== =========
Revolving credit agreement note - 50,000
Long-term notes due December 31, 1997 34,000 36,100
Various long-term notes 5,726 -
CNG Transmission Corp. notes due November 10, 1996
and July 11, 1997 6,080 8,862
Obligations under capital leases 21,423 30,902
Unamortized premium and discount on debt, net (9,917) (10,776)
---------- ----------
1,687,312 1,868,338
Less: debt due within one year-included
in current liabilities 36,231 237,709
---------- ----------
Total $1,651,081 $1,630,629
========== ==========
At December 31, 1994, long-term debt and capital lease
payments that will become due during the next five years are:
1995 1996 1997 1998 1999
(Thousands)
$36,231 $16,138 $86,850 $31,414 $1,274
The company's mortgage provides for a sinking and
improvement fund. This provision requires the company to make
annual cash deposits with the Trustee equivalent to 1% of the
principal amount of all bonds delivered and authenticated by the
Trustee prior to January 1 of that year (excluding any bonds
issued on the basis of the retirement of bonds). The company
satisfied this requirement in 1994 by depositing $23 million in
cash that was used to redeem in February 1994 $23 million of
8 5/8% Series first mortgage bonds, due 2007. The company
satisfied this requirement in 1995 by depositing $23 million in
cash that was used to redeem in February 1995 $23 million of
9 7/8% Series first mortgage bonds, due February 2020.
Mandatory annual cash sinking fund requirements are $600,000
beginning June 1, 2001, for the 7 1/4% Series and $250,000 on
December 1 in each year 1995 to 1996, for the 6 7/8% Series. The
amount increases to $500,000 and $750,000 on December 1, 1997 and
December 1, 2002, respectively, for the 6 7/8% Series.
The company's first mortgage bond indenture constitutes a
direct first mortgage lien on substantially all utility plant.
(1) Adjustable rate pollution control notes were issued to
secure like amounts of tax-exempt adjustable rate pollution
control revenue bonds (Adjustable Rate Revenue Bonds) issued by a
governmental authority. The Adjustable Rate Revenue Bonds bear
interest at the rate indicated through the date preceding the
interest rate adjustment date. The adjustable rate pollution
control notes bear interest at the same rate as the Adjustable
Rate Revenue Bonds. On the interest rate adjustment date and
annually thereafter (every three years thereafter in the case of
the Adjustable Rate Revenue Bonds due July 1, 2026), the interest
rate will be adjusted, not to exceed a rate of 15%, or at the
option of the company, subject to certain conditions, a fixed
rate of interest, not to exceed 18%, may become effective. In
the case of the Adjustable Rate Revenue Bonds due July 1, 2026,
at the option of the company, subject to certain conditions, a
fixed rate of interest may become effective prior to the interest
rate adjustment date or each third year thereafter. Bond owners
may elect, subject to certain conditions, to have their
Adjustable Rate Revenue Bonds purchased by the Trustee.
(2) Multi-mode pollution control notes were issued to secure
like amounts of tax-exempt multi-mode pollution control refunding
revenue bonds (Multi-mode Revenue Bonds) issued by a governmental
authority. These Multi-mode Revenue Bonds have a structure that
enables the company to optimize the use of short-term rates by
allowing for the interest rates to be based on a commercial paper
rate, a daily rate, a weekly rate or an auction rate. The
structure also provides flexibility to convert the interest rates
to term rates or fixed rates, in the event that it is in the
company's best interest to do so. The multi-mode pollution
control notes bear interest at the same rates as the Multi-mode
Revenue Bonds. Bond owners may elect, while the Multi-mode
Revenue Bonds bear interest at a daily rate or a weekly rate, to
have their Multi-mode Revenue Bonds purchased by the Registrar
and Paying Agent. The maturity date of the Multi-mode Revenue
Bonds due February 1, 2029, June 1, 2029, and October 1, 2029,
can be extended, subject to certain conditions, to a date not
later than February 1, 2034, June 1, 2034, and April 1, 2034,
respectively. The weighted average interest rate for all three
series (totaling $175 million principal amount) was 3.9%,
excluding letter of credit fees, at December 31, 1994.
The company has irrevocable letters of credit that expire on
the letter of credit expiration dates and that the company
anticipates being able to extend if the interest rate on the
related Adjustable Rate Revenue Bonds and Multi-mode Revenue
Bonds is not converted to a fixed interest rate. Those letters
of credit support certain payments required to be made on the
Adjustable Rate Revenue Bonds and Multi-mode Revenue Bonds. If
the company is unable to extend the letter of credit that is
related to a particular series of Adjustable Rate Revenue Bonds,
that series will have to be redeemed unless a fixed rate of
interest becomes effective. Multi-mode Revenue Bonds are subject
to mandatory purchase upon any change in the interest rate mode
and in certain other circumstances. Payments made under the
letters of credit in connection with purchases of Adjustable Rate
Revenue Bonds and Multi-mode Revenue Bonds are repaid with the
proceeds from the remarketing of such Bonds. To the extent the
proceeds are not sufficient, the company is required to reimburse
the bank that issued the letter of credit.
4 Preferred Stock
At December 31, 1994 and 1993, serial cumulative preferred stock was:
Shares
Par Value Authorized
Per Redeemable and Amount
Series Share Prior to Per Share Outstanding(1) 1994 1993
(Thousands)
Redeemable solely at the option of the company:
3.75% $100 $104.00 150,000 $15,000 $15,000
4 1/2%(1949) 100 103.75 40,000 4,000 4,000
4.15% 100 101.00 40,000 4,000 4,000
4.40% 100 102.00 75,000 7,500 7,500
4.15% (1954) 100 102.00 50,000 5,000 5,000
6.48% 100 102.00 300,000 30,000 30,000
8.80% 100 - - 25,000
8.48% 25 - - 25,000
7.40% (2) 25 12/1/98 26.85 1,000,000 25,000 25,000
Thereafter 25.00
Adjustable
Rate 25 - - 45,000
Adjustable
Rate (3) 25 12/1/98 27.50 2,000,000 50,000 50,000
Thereafter 25.00
-------- --------
140,500 235,500
Less: preferred stock redemptions within one year
- included in current liabilities - 95,000
-------- --------
Total $140,500 $140,500
======== ========
Subject to mandatory redemption requirements:
6.30% (4) 100 1/1/96 105.04 250,000 $25,000 $25,000
8.95% (5) 25 1/1/96 26.64 4,000,000 100,000 100,000
-------- --------
Total $125,000 $125,000
======== ========
At December 31, 1994, preferred stock redemptions and annual
redeemable preferred stock sinking fund requirements for the next
five years were:
1995 1996 1997 1998 1999
(Thousands)
$ - $ - $5,000 $5,000 $5,000
(1) At December 31, 1994, there were 1,550,000 shares of $100
par value preferred stock, 3,800,000 shares of $25 par value
preferred stock and 1,000,000 shares of $100 par value preference
stock authorized but unissued.
(2) The company is restricted in its ability to redeem this
Series prior to December 1, 1998.
(3) The payment on the Adjustable Rate Serial Preferred Stock,
Series B, for April 1, 1995, is at an annual rate of 6.54% and
subsequent payments can vary from an annual rate of 4% to 10%,
based on a formula included in the company's Certificate of
Incorporation. The company is restricted in its ability to
redeem this Series prior to December 1, 1998.
(4) On January 1 in each year 2004 through 2008, the company
must redeem 12,500 shares at par, and on January 1, 2009, the
company must redeem the balance of the shares at par. This
Series is redeemable at the option of the company at $105.04 per
share prior to January 1, 1996. The $105.04 price will be
reduced annually by 63 cents for the years ending 1996 through
2002; thereafter, the redemption price is $100.00. The company
is restricted in its ability to redeem this Series prior to
January 1, 2004.
(5) On January 1 in each year 1997 through 2016, the company
must redeem 200,000 shares at par. This Series is redeemable at
the option of the company at $26.64 per share prior to January 1,
1996. The $26.64 price will be reduced annually by 15 cents for
the years ending 1996 through 1999; by 14 cents for the year
ending 2000; and by 15 cents for the years ending 2001 through
2005. The company is restricted in its ability to redeem this
Series prior to January 1, 1996.
5 Bank Loans and Other Borrowings
The company has a revolving credit agreement with certain
banks that provides for borrowing up to $200 million to July 31,
1997. At the option of the company, the interest rate on
borrowings is related to the prime rate, the London Interbank
Offered Rate (LIBOR) or the interest rate applicable to certain
certificates of deposit. The agreement also provides for the
payment of a commitment fee that can fluctuate from .15% to .375%
depending upon the ratings of the company's first mortgage bonds.
The commitment fee was .1875% at December 31, 1994 and 1993, and
was .22% at December 31, 1992.
The company did not have any outstanding loans under the
revolving credit agreement at December 31, 1994. At December 31,
1993, the company had an outstanding loan of $50 million under
the revolving credit agreement at an interest rate of 4.06% under
the LIBOR option. This loan was repaid in May 1994. The
revolving credit agreement does not require compensating
balances.
The company uses short-term unsecured notes, usually
commercial paper, to finance certain refundings and for other
corporate purposes. The weighted average interest rates on notes
payable balances at December 31, 1994, 1993 and 1992 were 5.8%,
3.5% and 4.0%, respectively. At each year end, notes payable
consisted of commercial paper with maturity dates of less than
one year.
6 Restructuring
In the fourth quarter of 1993 the company recorded a $26
million restructuring charge. The corporate restructuring
reorganized the way the company delivers services to its electric
and natural gas customers beginning in March 1994. The
restructuring reduced 1993 earnings available for common stock by
approximately $17.2 million or 25 cents per share.
During the first quarter of 1994 the restructuring resulted
in a workforce reduction totaling 642 persons throughout the
organization, the elimination of customer walk-in services at 28
locations, and the closing of seven electric and natural gas
operations facilities. The closing of additional electric and
natural gas operations facilities will continue to be evaluated.
The workforce reduction of 642 employees, which was greater
than the company's target of 600, was accomplished through a
voluntary early retirement program (See Note 7) and an
involuntary severance program. Of the 642 employees, 384
employees accepted the early retirement program and 258 employees
were involuntarily severed. The company estimated the savings,
excluding fringe benefits, related to the workforce reduction to
be approximately $31.5 million, on an annual basis. As the
workforce decreased, the company experienced savings in line with
this estimate for 1994. The majority of these savings were used
to minimize the company's electric and natural gas price
increases in the second and third years of the rate settlement
agreement.
7 Retirement Benefits
Pensions
The company has a noncontributory retirement annuity plan
that covers substantially all employees. Benefits are based
principally on the employee's length of service and compensation
for the five highest paid consecutive years out of the last 10
years of service. It is the company's policy to fund pension
costs accrued each year to the extent deductible for federal
income tax purposes.
Effective January 1, 1993, the retirement benefit plans for
hourly and salaried employees were combined into one plan.
Combining the two plans did not affect benefit levels.
Net pension benefit for 1994, 1993 and 1992 included the
following components:
1994 1993 1992
(Thousands)
Service cost: Benefits
earned during the year $17,637 $17,688 $15,387
Interest cost on projected
benefit obligation 43,328 40,710 35,253
Actual return on plan assets (17,409) (77,129) (60,020)
Net amortization and deferral (48,824) 12,989 7,844
-------- -------- --------
Net pension (benefit) $(5,268) $(5,742) $(1,536)
======== ======== ========
The funded status of the plan at December 31, 1994 and 1993 was:
1994 1993
(Thousands)
Actuarial present value of accumulated
benefit obligation:
Vested $410,732 $390,716
Nonvested 38,176 55,476
-------- --------
Total 448,908 446,192
======== ========
Fair value of plan assets $733,661 $753,292
Actuarial present value of
projected benefit obligation (597,398) (608,216)
-------- --------
Plan assets in excess of projected
benefit obligation 136,263 145,076
Unrecognized net transition asset (66,374) (73,612)
Unrecognized net gain (92,851) (83,709)
Unrecognized prior service cost 9,066 4,182
--------- --------
Net pension (liability) $(13,896) $(8,063)
========= ========
Plan assets primarily consist of equity securities;
U.S. agency, corporate and Treasury bonds; and cash equivalents.
The projected benefit obligation was measured using an
assumed discount rate of 7.75% for 1994, 7% for 1993 and 7.75%
for 1992, and a long-term rate of increase in future compensation
levels of 5.5% for 1994, 5% for 1993 and 6% for 1992. The net
pension benefit was measured using an expected long-term rate of
return on plan assets of 8% in 1994 and 1993, and 7.5% in 1992.
Early retirement
As part of the corporate restructuring that was announced in
the fourth quarter of 1993 (See Note 6), the company offered a
voluntary early retirement program from December 1, 1993, through
January 21, 1994, to employees who were 55 years and older and
who had at least 10 years of service with the company. The
program included two provisions: an unreduced pension benefit for
those eligible employees who were under 60 years old, and a
monthly supplemental payment to "bridge" employees to age 62 when
they can begin collecting Social Security benefits. 384
employees accepted the early retirement opportunity. In 1993 the
company recorded a $19.9 million expense for the early retirement
program. This was included in the total $26 million
restructuring charge.
Postretirement benefits other than pensions
The company has postretirement benefit plans, such as a
comprehensive health insurance plan and a prescription drug plan,
that provide certain benefits for retired employees and their
dependents. Substantially all of the company's employees who
retire under the company's pension plan may become eligible for
those benefits at retirement. At December 31, 1994, 1993 and
1992, 2,331, 1,996 and 1,905 retirees and their dependents,
respectively, were covered under these plans. The postretirement
benefit plans are unfunded as of December 31, 1994.
In January 1993 the company adopted Statement of Financial
Accounting Standards No. 106 (SFAS 106), Employers' Accounting
for Postretirement Benefits Other Than Pensions, which requires
the company to accrue a liability for estimated future
postretirement benefits during an employee's working career
rather than recognize an expense when benefits are paid. At the
time of adoption, the actuarially determined accumulated
postretirement benefit obligation (APBO) was $206.6 million. The
company elected to recognize the APBO over 20 years.
In September 1993 the PSC issued a Statement of Policy
concerning the accounting and ratemaking treatment for pensions
and postretirement benefits other than pensions (PSC Policy).
The PSC Policy was effective January 1993, adopted SFAS 106 for
accounting and ratemaking purposes, and complies with generally
accepted accounting principles.
The postretirement benefits cost other than pensions
recognized on the income statement for the twelve months ended
December 31, 1994, 1993 and 1992, was $14.5 million, $11.4
million and $5 million, respectively. The amounts for 1994 and
1993 represent the portion of SFAS 106 costs that the company has
been allowed to collect from its customers. The amount for the
twelve months ended December 31, 1992 represents the
postretirement benefits cost as determined prior to the adoption
of SFAS 106, when the cost was not recognized as an expense until
the benefits were paid. The company has deferred $10.4 million
and $10.1 million of SFAS 106 costs as of December 31, 1994 and
1993, respectively. The company expects to recover any deferred
SFAS 106 amounts in accordance with the PSC Policy.
The PSC Policy allows various rate mechanisms, including the
use of excess pension fund assets, such as Internal Revenue
Service Code of 1986 Section 420 transfers, to temper the effect
of SFAS 106 on rates. In 1994 and 1993 the company transferred
$6.1 million and $5 million, respectively, of its excess pension
plan assets to cover most of the cost of retirees' health care
for those years. As a result of these transfers, the company
recognized a decrease in its deferred SFAS 106 asset.
The estimated net postretirement benefits cost other than
pensions for the 12 months ended December 31, 1994 and 1993,
included the following components:
1994 1993
(Thousands)
Service cost: Benefits accumulated
during the year $7,050 $6,888
Interest cost on accumulated postretirement
benefit obligation 15,903 16,304
Amortization of transition obligation over
20 years 10,330 10,330
Amortization of loss 2 -
Deferral for future recovery (18,757) (22,095)
------- -------
Net periodic postretirement
benefits cost $14,528 $11,427
======= =======
The status of the plans for postretirement benefits other
than pensions, as reflected in the company's consolidated balance
sheets at December 31, 1994 and 1993, are as follows:
1994 1993
(Thousands)
Accumulated postretirement benefit
obligation (APBO):
Retired employees $112,311 $69,947
Fully eligible active plan
participants 7,774 36,454
Other active plan employees 92,464 107,708
-------- --------
Total APBO 212,549 214,109
Less unrecognized transition
obligation 185,937 196,268
Less unrecognized net gain (28,382) (10,233)
-------- --------
Accrued postretirement liability $54,994 $28,074
======== ========
An 11% annual rate of increase in the per capita costs of
covered health care benefits was assumed for 1995, gradually
decreasing to 5% by the year 2003. Increasing the assumed health
care cost trend rates by 1% in each year would increase the APBO
as of January 1, 1995, by $44.4 million and increase the
aggregate of the service cost and interest cost components of the
net postretirement benefits cost for 1994 by $5.0 million. A
discount rate of 7.75% was used to determine the APBO.
8 Jointly-Owned Generating Stations
Nine Mile Point Unit 2
The company has an undivided 18% interest in the output and
costs of the Nine Mile Point nuclear generating unit No. 2 (NMP2)
which is operated by Niagara Mohawk Power Corporation (Niagara
Mohawk). Ownership of NMP2 is shared with Niagara Mohawk 41%,
Long Island Lighting Company 18%, Rochester Gas and Electric
Corporation 14%, and Central Hudson Gas & Electric Corporation
9%. The company's share of the rated capability is 189,000
kilowatts. The company's net utility plant investment, excluding
nuclear fuel, was approximately $638 million and $652 million, at
December 31, 1994 and 1993, respectively. The accumulated
provision for depreciation was approximately $120 million and
$103 million, at December 31, 1994 and 1993, respectively. The
company's share of operating expenses is included in the
consolidated statements of income.
A low level radioactive waste management and contingency
plan for NMP2 provides assurance that NMP2 is properly prepared
to handle interim storage of low level radioactive waste until
1998.
Niagara Mohawk has contracted with the U.S. Department of
Energy (DOE) for disposal of high level radioactive waste (spent
fuel) from NMP2. The company is reimbursing Niagara Mohawk for
its 18% share of the cost under the contract (currently
approximately $1 per megawatt hour of net generation). The DOE's
schedule for start of operations of their high level radioactive
waste repository has slipped from 2003 to no sooner than 2010.
The company has been advised by Niagara Mohawk that the NMP2
Spent Fuel Storage Pool has a capacity for spent fuel that is
adequate until 2014. If further DOE schedule slippage should
occur, construction of pre-licensed dry storage facilities would
extend the on-site storage capability for spent fuel at NMP2
beyond 2014.
Nuclear insurance
Niagara Mohawk maintains public liability and property
insurance for NMP2. The company reimburses Niagara Mohawk for
its 18% share of those costs.
The public liability limit for a nuclear incident is
approximately $8.3 billion. Should losses stemming from a
nuclear incident exceed the commercially available public
liability insurance, each licensee of a nuclear facility would be
liable for up to a maximum of $75.5 million per incident, payable
at a rate not to exceed $10 million per year. The company's
maximum liability for its 18% interest in NMP2 would be
approximately $13.6 million per incident. The $75.5 million
assessment is subject to periodic inflation indexing and a 5%
surcharge should funds prove insufficient to pay claims
associated with a nuclear incident. The Price-Anderson Act also
requires indemnification for precautionary evacuations whether or
not a nuclear incident actually occurs.
Niagara Mohawk maintains nuclear property insurance for NMP2
and is reimbursed by the company for its 18% interest. Niagara
Mohawk has procured property insurance aggregating approximately
$2.8 billion through the Nuclear Insurance Pools and the Nuclear
Electric Insurance Limited (NEIL). In addition, the company has
purchased NEIL insurance coverage for the extra expense incurred
in purchasing replacement power during prolonged accidental
outages. Under NEIL programs, should losses resulting from an
incident at a member facility exceed the accumulated reserves of
NEIL, each member, including the company, would be liable for its
share of the deficiency. The company's maximum liability per
incident under the property damage and replacement power
coverages is approximately $2.5 million.
Nuclear plant decommissioning costs
In May 1993 the Nuclear Regulatory Commission (NRC) updated
labor, energy and burial cost factors for determining the minimum
funding requirement for nuclear decommissioning. As a result,
the company's 18% share of the cost to decommission NMP2 is
estimated to be $234 million in 2027, when decommissioning is
expected to commence ($76 million in 1994 dollars). A
preliminary estimate from Niagara Mohawk indicates that the cost
to decommission NMP2 is greater than this amount. Niagara Mohawk
has advised the company that in 1995 it expects to perform a
detailed study to update the cost to decommission NMP2. The
company plans to revise its estimate of the cost to decommission
NMP2 after Niagara Mohawk completes its study.
The company's annual decommissioning allowance currently
included in electric rates is approximately $1.6 million and is
sufficient to recover the NRC's minimum funding requirement.
These costs are charged to depreciation and amortization expense
and are recovered over the expected life of the plant. The
company believes that any increase in decommissioning costs will
ultimately be recovered in rates.
The company has established a Qualified Fund under
applicable provisions of the federal tax law. The fund also
complies with the NRC regulations that require the use of an
external trust fund to provide funds to decommission the
contaminated portion of NMP2. The balance in this fund,
including reinvested earnings, was approximately $7.4 million and
$5.7 million at December 31, 1994 and 1993, respectively. These
amounts are included on the consolidated balance sheets in other
property and investments, net. The related liability for
decommissioning is included in deferred credits and other
liabilities - other. At December 31, 1994, the external trust
fund investments were primarily debt securities, classified as
available-for-sale, and their carrying value approximated fair
value.
The Financial Accounting Standards Board is currently
reviewing the accounting for obligations for decommissioning of
nuclear power plants, including the balance sheet presentation of
estimated decommissioning costs.
Homer City
The company has an undivided 50% interest in the output and
costs of the Homer City Generating Station, which is comprised of
three generating units. The station is owned with Pennsylvania
Electric Company, which operates the facility. The company's
share of the rated capability is 950,000 kilowatts and its net
utility plant investment was approximately $265 million and $258
million at December 31, 1994 and 1993, respectively. The
accumulated provision for depreciation was approximately
$153 million and $159 million, at December 31, 1994 and 1993,
respectively. The company's share of operating expenses is
included in the consolidated statements of income.
9 Commitments and Contingencies
Capital expenditures
The company has substantial commitments in connection with
its capital expenditure program and estimates that expenditures
for 1995, 1996 and 1997 will approximate $188 million, $264
million and $184 million, respectively. The program is subject
to periodic review and revision. Actual capital expenditures may
change to reflect the imposition of additional regulatory
requirements and the company's continued focus on optimizing
capital expenditures. Capital expenditures will be primarily for
extension of service, necessary improvements at existing
facilities, the natural gas storage project, compliance with the
Clean Air Act Amendments of 1990 (1990 Amendments) and other
environmental requirements.
The 1990 Amendments will result in expenditures of
approximately $174 million, on a present value basis, over a 25-
year period, for all capital and operating and maintenance
expenses related to the reduction of sulfur dioxide and nitrogen
oxides at several of the company's coal-fired generating
stations, of which $106.5 million had been incurred as of
December 31, 1994. The cost to comply with the sulfur dioxide
and nitrogen oxide limitations includes the construction of an
innovative flue gas desulfurization (FGD) system and a nitrogen
oxide reduction system that was recently completed at the
company's Milliken Generating Station. The company estimates
that approximately a 1% electric rate increase will be required
for the cost of reducing sulfur dioxide and nitrogen oxide
emissions in both Phase I (which began on January 1, 1995) and
Phase II (begins January 1, 2000), as discussed below. In
addition, the company anticipates that it will have to
significantly reduce its nitrogen oxide emissions even further by
the year 2003, which includes an interim reduction in the year
1999, as a result of proposed U.S. Environmental Protection
Agency (EPA) regulations. The cost to comply with these proposed
regulations cannot be estimated at this time, since the reduction
will be based on additional research scheduled to be completed
later in the decade. As a result of the 1990 Amendments, the
company plans to reduce its annual sulfur dioxide emissions by an
amount that will allow the company to meet the sulfur dioxide
levels established for the company, which are approximately a 49%
reduction from approximately 138,000 tons in 1989 to 71,000 tons
by the year 2000.
The cost of controlling toxic emissions under the 1990
Amendments, if required, cannot be estimated at this time, since
the type and level of reductions that may be required is
dependent on a study currently being performed by the EPA, which
is scheduled to be completed by the end of 1995. Regulations may
be adopted at the state level that would limit toxic emissions
even further, at an additional cost to the company. The company
anticipates that the costs incurred to comply with the 1990
Amendments will be recoverable through rates based on previous
rate recovery of required environmental costs.
The 1990 Amendments require the EPA to allocate annual
emissions allowances to each of the company's coal-fired
generating stations based on statutory emissions limits. An
emissions allowance represents an authorization to emit, during
or after a specified calendar year, one ton of sulfur dioxide.
During Phase I, the company estimates that it will have
allowances in excess of the affected coal-fired generating
stations' actual emissions. The company's present strategy is to
bank these allowances for use in later years. By using a banking
strategy, it is estimated that Phase II allowance requirements
will be met through the year 2005 by utilizing the allowances
banked during Phase I, which includes the extension reserve
allowances discussed below, together with the company's Phase II
annual emissions allowances. This strategy could be modified
should market or business conditions change. In addition to the
annual emissions allowances allocated to the company by the EPA,
the company has received a portion of the extension reserve
allowances issued by the EPA to utilities electing to build
scrubbers in Phase I, as a result of a pooling agreement that it
entered into with other utilities who were also eligible to
receive some of these extension reserve allowances.
As a result of existing and new solid waste disposal
legislation and regulations in Pennsylvania, the company will
incur approximately $28 million, on a present value basis, of
additional costs over the next 30 years at the Homer City
Generating Station. The majority of these costs will be incurred
over the next 10 years to install new equipment, modify or
replace existing equipment, and improve the design of a proposed
expansion of disposal facilities. The company expects to recover
these expenditures in rates, since the company has been allowed
by the PSC to recover similar costs in rates, such as groundwater
protection costs to meet permit conditions and regulatory
requirements.
Long-term power purchase contracts
The company is currently required to purchase 594 megawatts
(mw) of NUG power. The company is required to make payments
under these contracts only for the power it receives or when the
company directs the NUG to reduce its output under the terms of
the contract. Two contracts the company has with NUGs each
provide more than 5% of current system capability. One contract
provides for 177 mw or 5.4%, and the other provides for 240 mw or
7.3%. During 1994, 1993 and 1992 the company purchased
approximately $214 million, $138 million and $71 million,
respectively, of NUG power, including termination costs. The
company estimates that NUG power purchases, excluding termination
costs, over the next five years will be as follows:
1995 1996 1997 1998 1999
(Millions)
$274 $312 $322 $333 $344
Increases in the cost of NUG power purchases will contribute
significantly to expected electric price increases in August
1995.
Coal purchasing contracts
The company has long-term contracts with nonaffiliated
mining companies for the purchase of coal for the jointly-owned
Homer City Generating Station. The contracts, which expire
between 1995 and the end of the expected service life of the
generating station, require the purchase of either fixed or
minimum amounts of the station's coal requirements. The
contracts are based on fixed price plus escalation provisions.
The company's share of the cost of coal purchased under these
agreements is expected to aggregate $52 million, $53 million and
$55 million for the years 1995, 1996 and 1997, respectively.
In addition, the company has a long-term contract for the
purchase of coal for the Kintigh and Milliken Generating
Stations. The contract, which expires in 2003, supplies the
annual coal requirements of the Kintigh station. One-third of
the tonnage price is renegotiated annually to reflect market
conditions. The contract also supplies the requirements of the
Milliken station for the years 1995-1997. The delivered cost of
coal purchased under this agreement is expected to be $76
million, $78 million, and $81 million for the years 1995, 1996
and 1997, respectively.
10 Environmental Liability
The company continually assesses actions that may need to be
taken to ensure compliance with changing environmental laws and
regulations. Any additional compliance programs will increase
the cost of electric and natural gas service by requiring changes
in the company's operations and facilities. Historically, rate
recovery has been authorized for the cost incurred to comply with
environmental laws and regulations.
Due to existing and proposed legislation and regulations,
and legal proceedings commenced by governmental bodies and
others, the company may also incur costs from the past disposal
of hazardous substances produced during the company's operations
or those of its predecessors. The company has been notified by
the EPA and the New York State Department of Environmental
Conservation (NYSDEC), as appropriate, that it is among the
potentially responsible parties (PRPs) who may be liable to pay
for costs incurred to remediate certain hazardous substances at
eight waste sites, not including the company's inactive gas
manufacturing sites, which are discussed below. With respect to
the eight sites, six sites are included in the New York State
Registry of Inactive Hazardous Waste Sites (New York State
Registry) and two of those sites are also included on the
National Priorities list.
Any liability may be joint and several for certain of these
sites. The company has recorded a liability related to four of
these eight sites, which is reflected in the company's
consolidated balance sheets at December 31, 1994, in the amount
of $1.1 million. The ultimate cost to remediate these sites may
be significantly more than this amount and will be dependent on
such factors as the remedial action plan selected, the extent of
site contamination, and the portion attributed to the company.
The company has notified the EPA and the NYSDEC, as appropriate,
that it believes it has no responsibility at three sites and has
already incurred expenditures related to the remediation at the
remaining site. A deferred asset has also been recorded in the
amount of $2.1 million, of which $1.0 million relates to costs
that have already been incurred. The company believes it will
recover these costs, since the PSC has allowed other utilities to
recover these types of remediation costs and has allowed the
company to recover similar costs in rates, such as investigation
and cleanup costs relating to inactive gas manufacturing sites.
The estimated liability of $1.1 million was derived by
multiplying the total estimated cost to clean up a particular
site by the related company contribution factor. Estimates of
the total cleanup costs were determined by using information
related to a particular site, such as investigations performed to
date at a site or from the data released by a regulatory agency.
In addition, this estimate was based upon currently available
facts, existing technology, and presently enacted laws and
regulations. The contribution factor is calculated using either
the company's percentage share of the total PRPs named, which
assumes all PRPs will contribute equally, or the company's
estimated percentage share of the total hazardous wastes disposed
of at a particular site, or by using a 1% contribution factor for
those sites at which it believes that it has contributed a
minimal amount of hazardous wastes. The company has notified its
former and current insurance carriers that it seeks to recover
from them certain of these cleanup costs. However, the company
is unable to predict the amount of insurance recoveries, if any,
that it may obtain.
A number of the company's inactive gas manufacturing sites
have been listed in the New York State Registry. In late March
1994 the company entered into an Order on Consent with the NYSDEC
requiring the company to investigate and, where necessary,
remediate 33 of the company's 38 known inactive gas manufacturing
sites. The schedule for investigating and remediating these 33
sites will be determined through further negotiations with the
NYSDEC. The company has a program to investigate and initiate
necessary remediation at its 38 known inactive gas manufacturing
sites. Expenditures through the year 2009 are estimated at
$32.5 million, including the impact of the Order on Consent.
This estimate was determined by using the company's experience
and knowledge related to these sites as a result of the
investigation and remediation that the company has performed to
date. It is based upon currently available facts, existing
technology, and presently enacted laws and regulations. This
liability to investigate and initiate remediation, as necessary,
at the known inactive gas manufacturing sites, is reflected in
the company's consolidated balance sheets at December 31, 1994
and 1993 in the amount of $32.5 million and $25 million,
respectively. The company also has recorded a corresponding
deferred asset, since it expects to recover such expenditures in
rates, as the company has previously been allowed by the PSC to
recover such costs in rates. The PSC has asked its staff to
prepare a recommendation on a generic policy for these types of
expenditures by the spring of 1995. The company has notified its
former and current insurance carriers that it seeks to recover
from them certain of these cleanup costs. However, the company
is unable to predict the amount of insurance recoveries, if any,
that it may obtain.
11 Federal Energy Regulatory Commission (FERC) Order 636
FERC Order 636 became effective in November 1993 and
requires interstate natural gas pipeline companies to offer
customers unbundled, or separate, services equivalent to their
former sales service. 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. FERC Order 636 has substantially
restructured the interstate natural gas market.
As a result of the restructuring of services required by
FERC Order 636, pipelines have incurred and will continue to
incur transition costs. These include the costs of restructuring
existing natural gas supply contracts, unrecovered costs that
would otherwise have been billable to pipeline customers under
previously existing rules and costs of assets needed to implement
the order. FERC Order 636 allows pipelines to recover all
prudently incurred costs from their customers.
The company's liability for transition costs is based on the
pipelines' filings with the FERC to recover such costs. The
company has reached a final resolution with one of its pipeline
suppliers regarding transition costs and is currently negotiating
with its other pipeline suppliers. Final resolution of the issue
may not occur for several years. The company's estimated
liability for transition costs was $21 million and $29 million at
December 31, 1994 and 1993, respectively. The company has
recorded a corresponding deferred asset, since it has been
recovering transition costs from its customers through its gas
adjustment clause and believes that such costs will continue to
be recoverable from its customers.
12 Diversified Operations
In April 1992 the PSC issued an order allowing the company
to invest up to 5% of its consolidated capitalization
(approximately $180 million at December 31, 1994) in one or more
subsidiaries that may engage or invest in energy-related or
environmental-services businesses and provide related services.
The company has been making investments in unregulated
companies through its wholly owned subsidiary, NGE Enterprises,
Inc. (NGE). NGE owns two unregulated businesses - EnerSoft
Corporation (EnerSoft) and XENERGY, Inc. (XENERGY).
EnerSoft, a computer software company, was formed in May
1993 to produce and market software for natural gas utilities,
marketers and pipeline operators. Through an alliance with the
New York Mercantile Exchange, EnerSoft is developing Channel 4, a
natural gas and pipeline capacity trading and information system
for the North American market. While development of the system
has taken longer than anticipated, Channel 4 is expected to be
commercially available in the spring of 1995. Like most other
start-up companies, EnerSoft has been incurring operating losses.
The company expects that EnerSoft will continue to incur
operating losses in the near term.
In June 1994 NGE acquired all of the outstanding stock of
XENERGY, an energy services, information systems and energy-
consulting company that specializes in energy management,
conservation engineering and demand-side management. XENERGY
currently provides a broad range of services to utilities
throughout the United States, Canada, Spain and France. It also
provides energy services, conservation engineering and DSM
services to governmental agencies at both the state and federal
levels, and to a large number of end users.
As of December 31, 1994 and 1993, the company had invested
approximately $47 million and $3 million, respectively, in NGE to
finance its diversified investments. The majority of this
investment is included in other property and investments, net on
the consolidated balance sheets. NGE's total liabilities and
capitalization at December 31, 1994 and 1993 was approximately
$52 million and $7 million, respectively. For the years ended
December 31, 1994 and 1993, NGE incurred net losses of $6.0
million and $1.4 million, respectively, which are included in
other income and deductions on the consolidated statements of
income.
13 Fair Value of Financial Instruments
The estimated fair values of the company's financial instruments at
December 31, 1994 and 1993, were as follows:
Carrying Amount Fair Value
1994 1993 1994 1993
(Thousands)
First mortgage bonds $1,044,083 $1,166,779 $1,010,239 $1,274,883
Pollution control notes $576,000 $575,695 $484,005 $581,928
Preferred stock subject
to mandatory redemption
requirements $125,000 $125,000 $127,875 $134,000
The fair value of the company's first mortgage bonds,
pollution control notes and preferred stock is estimated based on
the quoted market prices for the same or similar issues of the
same remaining maturities.
The carrying amount for the following items approximates
estimated fair value because of the short maturity (within one
year) of those instruments: cash and cash equivalents, notes
payable, and interest accrued.
Special deposits include restricted funds that are set aside
for preferred stock and long-term debt redemptions. Special
deposits also include restricted funds that are used to finance a
portion of the costs incurred in the construction of certain
solid waste disposal and other related facilities. The carrying
amount approximates fair value because the special deposits have
been invested in securities with a short-term maturity (within
one year).
The carrying amount of the revolving credit agreement note
outstanding at December 31, 1993 approximated fair value because
its pricing was based on short-term interest rates.
14 Industry Segment Information
Certain information pertaining to the electric and natural gas operations of
the company follows:
1994 1993 1992
Natural Natural Natural
Electric Gas Electric Gas Electric Gas
(Thousands)
Operating
Revenues $1,600,075 $298,780 $1,527,362 $272,787 $1,451,525 $240,164
Expenses $1,306,871 $269,300 $1,250,000 $249,493 $1,146,619 $221,307
Income $293,204 $29,480 $277,362 $23,294 $304,906 $18,857
Depreciation and
amortization* $167,484 $10,842 $155,231 $9,337 $150,549 $8,428
Capital
expenditures $183,910 $40,396 $208,576 $36,453 $210,185 $35,433
Identifiable
assets** $4,623,731 $486,075 $4,627,905 $458,596 $4,540,724 $377,424
* Included in operating expenses.
** Assets used in both electric and natural gas operations not included
above were $113,099, $201,457 and $159,768 at December 31, 1994, 1993 and
1992, respectively. They consist primarily of cash and cash equivalents,
special deposits and prepayments.
15 Quarterly Financial Information (Unaudited)
Quarter ended March 31 June 30 Sept. 30 Dec. 31
(Thousands, except per share amounts)
1994
Operating revenues $565,167 $388,639(1) $432,451 $512,598
Operating income $119,990 $47,784 $63,351 $91,559
Net income $84,693 $12,395(1) $30,953 $59,604
Earnings available
for common stock $79,834 $7,745 $26,251 $54,868
Earnings per share $1.13 $.11(1) $.37 $.77
Dividends per share $.55 $.55 $.55 $.35
Average shares outstanding 70,801 71,214 71,490 71,503
Common stock price*
High $30.50 $27.88 $25.88 $19.75
Low $26.50 $23.25 $18.38 $17.75
1993
Operating revenues $522,383 $388,601 $396,410 $492,755
Operating income $109,893 $56,649 $66,108 $68,006
Net income $74,039 $21,500 $32,541 $37,948(2)
Earnings available
for common stock $68,838 $16,299 $27,340 $32,913
Earnings per share $.99 $.23 $.39 $.47(2)
Dividends per share $.54 $.54 $.55 $.55
Average shares outstanding 69,561 69,836 70,119 70,431
Common stock price*
High $35.13 $36.50 $36.25 $35.50
Low $31.63 $32.13 $34.63 $28.75
(1) Second quarter 1994 results include the company's change in estimate for
the 1993 production cost penalty of $13 million or 12 cents per share.
(2) Fourth quarter 1993 results reflect the effects of restructuring expenses,
which decreased net income and earnings for common stock by $17.2 million
and decreased earnings per share by 24 cents.
* The company's common stock is listed on the New York Stock Exchange. The
number of shareholders of record at December 31, 1994, was 56,279.
Dividend Limitations: After dividends on all outstanding preferred stock have
been paid, or declared, and funds set apart for their payment, the common
stock is entitled to cash dividends as may be declared by the board of
directors out of retained earnings accumulated since December 31, 1946.
Common Stock dividends are limited if common stock equity (46% at December 31,
1994) falls below 25% of total capitalization, as defined in the company's
Certificate of Incorporation. Dividends on common stock cannot be paid unless
sinking fund requirements of the preferred stock are met. The company has not
been restricted in the payment of dividends on common stock by these
provisions. Retained earnings accumulated since December 31, 1946, were
approximately $347 million and $320 million as of December 31, 1994 and 1993,
respectively.
REPORT OF INDEPENDENT ACCOUNTANTS
To the Stockholders and Board of Directors
New York State Electric & Gas Corporation and Subsidiaries
Ithaca, New York
We have audited the consolidated financial statements and the financial
statement schedule of New York State Electric & Gas Corporation and
Subsidiaries listed in Item 14(a) of this Form
10-K. These financial statements and financial statement schedule are the
responsibility of the Company's management. Our responsibility is to express
an opinion on these financial statements and the financial statement schedule
based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards 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. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the consolidated financial position of New York State
Electric & Gas Corporation and Subsidiaries as of December 31, 1994 and 1993,
and the consolidated 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. In addition, in our opinion, the
financial statement schedule referred to above, when considered in relation to
the basic financial statements taken as a whole, present fairly, in all
material respects, the information required to be included therein.
As discussed in Note 7 to the consolidated financial statements, the Company
and Subsidiaries changed its method of accounting for postretirement benefits
other than pensions in 1993.
COOPERS & LYBRAND L.L.P.
New York, New York
January 27, 1995
NEW YORK STATE ELECTRIC & GAS CORPORATION
SCHEDULE II - ALLOWANCE FOR DOUBTFUL ACCOUNTS - ACCOUNTS RECEIVABLE
(Thousands of Dollars)
Beginning End
Year of Year Additions Write-offs (a) Adjustments of Year (b)
1994 $4,000 $19,594 $(16,894) 498 (c) $7,198
1993 1,900 15,306 (13,206) 4,000
1992 700 11,518 (10,318) 1,900
(a) Uncollectible accounts charged against the allowance, net of recoveries.
(b) Represents an estimate of the write-offs that will not be recovered in rates.
(c) Due to acquisition of XENERGY, Inc. in June 1994.
Item 9. Changes in and disagreements with accountants on accounting and
financial disclosure - None
PART III
Item 10. Directors and executive officers of the Registrant
Incorporated herein by reference to the information under the caption
"Election of Directors" and "Secton 16 Compliance" in the Company's Proxy
Statement dated March 31, 1995. The information regarding executive officers
is on pages 26-27 of this report.
Item 11. Executive compensation
Incorporated herein by reference to the information under the captions
"Executive Compensation," "Employment and Change in Control Arrangements,"
"Directors' Compensation," "Report of Executive Compensation and Succession
Committee on Executive Compensation" and "Stock Performance Graph" in the
Company's Proxy Statement dated March 31, 1995.
Item 12. Security ownership of certain beneficial owners and management
Incorporated herein by reference to the information under the caption
"Security Ownership of Certain Beneficial Owners and Management" in the
Company's Proxy Statement dated March 31, 1995.
Item 13. Certain relationships and related transactions
Incorporated herein by reference to the information under the caption
"Election of Directors" in the Company's Proxy Statement dated March 31, 1995.
PART IV
Item 14. Exhibits, financial statement schedules, and reports on Form 8-K
(a) The following documents are filed as part of this report:
1. Financial statements
Included in Part II of this report:
a) Consolidated Balance Sheets as of December 31, 1994 and 1993
b) For the three years ended December 31, 1994:
Consolidated Statements of Income
Consolidated Statements of Cash Flows
Consolidated Statements of Changes in Common Stock Equity
c) Notes to Consolidated Financial Statements
d) Report of Independent Accountants
2. Financial statement schedules
Included in Part II of this report:
For the three years ended December 31, 1994:
II. Allowance for Doubtful Accounts - Accounts Receivable
Schedules other than those listed above have been omitted since they are
not required, are inapplicable or the required information is presented in the
Consolidated Financial Statements or notes thereto.
3. Exhibits
(a)(1) The following exhibits are delivered with this report:
Exhibit No.
(A) 10-18 - Supplemental Executive Retirement Plan Amendment No. 1.
(A) 10-31 - Annual Executive Incentive Compensation Plan Amendment No. 3.
(A) 10-32 - Annual Executive Incentive Compensation Plan Amendment No. 4.
(A) 10-41 - Agreement with M. I. German.
12 - Computation of Ratio of Earnings to Fixed Charges.
21 - Subsidiaries.
23 - Consent of Coopers & Lybrand to incorporation by reference into
certain registration statements.
27 - Financial Data Schedule.
99-1 - Form 11-K for New York State Electric & Gas Corporation Tax
Deferred Savings Plan for Salaried Employees.
99-2 - Form 11-K for New York State Electric & Gas Corporation Tax
Deferred Savings Plan for Hourly Paid Employees.
(a)(2) The following exhibits are incorporated herein by reference:
Exhibit No. Filed in As Exhibit No.
3-1 - Restated Certificate of Incorporation of the
Company pursuant to Section 807 of the Business
Corporation Law filed in the Office of the
Secretary of State of the State of New York on
October 25, 1988 - Registration No. 33-50719 . . . 4-11
3-2 - Certificate of Amendment of the Certificate of
Incorporation filed in the Office of the
Secretary of State of the State of New York
on October 17, 1989 - Registration No. 33-50719 . . 4-12
3-3 - Certificate of Amendment of the Certificate of
Incorporation filed in the Office of the Secretary
of State of the State of New York on May 22, 1990 -
Registration No. 33-50719 . . . . . . . . . . . . . 4-13
3-4 - Certificate of Amendment of the Certificate of
Incorporation filed in the Office of the
Secretary of State of the State of New York
on October 31, 1990 - Registration No. 33-50719 . . 4-14
3-5 - Certificate of Amendment of the Certificate of
Incorporation filed in the Office of the
Secretary of State of the State of New York
on February 6, 1991 - Registration No. 33-50719 . . 4-15
3-6 - Certificate of Amendment of the Certificate of
Incorporation filed in the Office of the
Secretary of State of the State of New York
on October 15, 1991 - Registration No. 33-50719 . . 4-16
3-7 - Certificate of Merger of Columbia Gas of
New York, Inc. into the Company filed in the
Office of the Secretary of State of the State
of New York on April 8, 1991 - Registration
No. 33-50719 . . . . . . . . . . . . . . . . . . . 4-20
3-8 - Certificate of Amendment of the Certificate of
Incorporation filed in the Office of the Secretary
of State of the State of New York
on May 28, 1992 - Registration No. 33-50719 . . . . 4-17
______________________________
(A) Management contract or compensatory plan or arrangement.
Exhibit No. Filed in As Exhibit No.
3-9 - Certificate of Amendment of the Certificate of
Incorporation filed in the Office of the Secretary
of State of the State of New York
on October 20, 1992 - Registration No. 33-50719 . . . 4-18
3-10 - Certificate of Amendment of the Certificate of
Incorporation filed in the Office of the Secretary
of State of the State of New York on October 14, 1993
Registration No. 33-50719 . . . . . . . . . . . . . . 4-19
3-11 - Certificate of Amendment of the Certificate of Incor-
poration filed in the Office of the Secretary of State
of the State of New York on December 10, 1993 -
Company's 10-K for year ended December 31, 1993 -
File No. 1-3103-2 . . . . . . . . . . . . . . . . . . 3-11
3-12 - Certificate of Amendment of the Certificate of Incor-
poration filed in the Office of the Secretary of State
of the State of New York on December 20, 1993 -
Company's 10-K for year ended December 31, 1993 -
File No. 1-3103-2 . . . . . . . . . . . . . . . . . . 3-12
3-13 - Certificate of Amendment of the Certificate of Incor-
poration filed in the Office of the Secretary of State
of the State of New York on December 20, 1993 -
Company's 10-K for year ended December 31, 1993 -
File No. 1-3103-2 . . . . . . . . . . . . . . . . . . 3-13
3-14 - Certificates of the Secretary of the Company concern-
ing consents dated March 20, 1957 and May 9, 1975 of
holders of Serial Preferred Stock with respect to
issuance of certain unsecured indebtedness -
Registration No. 2-69988. . . . . . . . . . . . . . 4-7
3-15 - By-Laws of the Company as amended February 25, 1994 -
Company's 10-K for year ended December 31, 1993 -
File No. 1-3103-2 . . . . . . . . . . . . . . . . . . 3-15
4-1 - First Mortgage dated as of July 1, 1921 executed by
the Company under its then name of "New York State
Gas and Electric Corporation" to The Equitable Trust
Company of New York, as Trustee (Chemical Bank is
Successor Trustee) - Registration No. 33-4186 . . . 4-1
Supplemental Indentures to First Mortgage dated as of July 1, 1921:
4-2 - No. 37 - Registration No. 33-31297. . . . . . . . . 4-2
4-3 - No. 39 - Registration No. 33-31297. . . . . . . . . 4-3
4-4 - No. 43 - Registration No. 33-31297. . . . . . . . . 4-4
4-5 - No. 51 - Registration No. 2-59840 . . . . . . . . . 2-B(46)
4-6 - No. 68 - Registration No. 2-59840 . . . . . . . . . 2-B(63)
4-7 - No. 69 - Registration No. 2-59840 . . . . . . . . . 2-B(64)
4-8 - No. 71 - Registration No. 2-59840 . . . . . . . . . 2-B(66)
4-9 - No. 74 - Registration No. 2-59840 . . . . . . . . . 2-B(69)
4-10 - No. 75 - Registration No. 2-59840 . . . . . . . . . 2-B(70)
4-11 - No. 80 - Registration No. 2-59840 . . . . . . . . . 2-B(75)
4-12 - No. 81 - Registration No. 2-59840 . . . . . . . . . 2-B(76)
4-13 - No. 83 - Registration No. 2-65948 . . . . . . . . . 2-B(78)
4-14 - No. 102- Registration No. 33-33838. . . . . . . . . 4-8
4-15 - No. 103- Registration No. 33-43458. . . . . . . . . 4-8
4-16 - No. 104- Registration No. 33-43458. . . . . . . . . 4-9
4-17 - No. 105- Registration No. 33-52040. . . . . . . . . 4-8
4-18 - No. 106- Company's 10-K for year ended
December 31, 1992 - File No. 1-3103-2. . . 4-23
4-19 - No. 107- Company's 10-K for year ended
December 31, 1992 - File No. 1-3103-2. . . 4-24
4-20 - No. 108- Registration No. 33-50719. . . . . . . . . 4-8
4-21 - No. 109- Registration No. 33-50719. . . . . . . . . 4-9
Agreements and amendments with the Power Authority of the State of New York:
Exhibit No. Filed in As Exhibit No.
10-1 - Letter Agreement dated February 3, 1982 relating to
transmission services - Registration No. 2-82192. . 10-1
10-2 - Amendment dated December 21, 1989 to the Letter
Agreement dated February 3, 1982 relating to trans-
mission services - Company's 10-K for year ended
December 31, 1989 - File No. 1-3103-2 . . . . . . 10-4
10-3 - Transmission Agreement dated December 12, 1983,
with respect to connection of the Company's Kintigh
(Somerset) Generating Station to the Niagara-Edic
345 kv transmission system - Company's 10-K for year
ended December 31, 1988 - File No. 1-3103-2 . . . . 10-6
10-4 - Amendment dated December 21, 1989 to the Transmission
Agreement dated December 12, 1983 with respect to
connection of the Company's Kintigh (Somerset) Gener-
ating Station to the Niagara-Edic 345 kv transmission
system - Company's 10-K for the year ended December
31, 1989 File No. 1-3103-2. . . . . . . . . . . . . 10-7
* * * * * * * * * *
10-5 - New York Power Pool Agreement dated July 11, 1985 -
Company's 10-K for year ended December 31, 1988 -
File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-7
10-6 - Transmission Agreement dated January 10, 1990 between
New York State Electric & Gas Corporation and Niagara
Mohawk Power Corporation, with respect to remote load
and generation wheeling service for the Company -
Company's 10-K for year ended December 31, 1990 -
File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-17
10-7 - Coal Sales Agreement dated December 21, 1983 between
the Company and Consolidation Coal Company - Company's
10-K for year ended December 31, 1993 -
File No. 1-3103-2 . . . . . . . . . . . . . . . . . . 10-14
Exhibit No. Filed in As Exhibit No.
10-8 - Amendment No. 1 dated as of October 1, 1985 to the
Coal Sales Agreement dated December 21, 1983 between
the Company and Consolidation Coal Company -
Company's 10-K for year ended December 31, 1986 -
File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-11
10-9 - Amendment No. 2 dated as of August 28, 1986 to the
Coal Sales Agreement dated December 21, 1983 between
the Company and Consolidation Coal Company -
Company's 10-K for year ended December 31, 1986 -
File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-12
10-10 - Basic Agreement dated as of September 22, 1975
between New York State Electric & Gas Corporation
and others concerning Nine Mile Point Nuclear
Station, Unit No. 2 - Registration No. 2-54903. . . 5-0
10-11 - Nine Mile Point Nuclear Station Unit 2 Operating
Agreement effective as of January 1, 1993 among
New York State Electric & Gas Corporation and
others - Company's 10-K for the year ended
December 31, 1992 - File No. 1-3103-2 . . . . . . . 10-18
10-12 - Coal Hauling Agreement dated as of March 9, 1983
between Somerset Railroad Corporation and New
York State Electric & Gas Corporation -
Registration No. 2-82352. . . . . . . . . . . . . . 10
(A)10-13 - Retirement Plan for Directors - Company's 10-K
for the year ended December 31, 1991 -
File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-26
(A)10-14 - Retirement Plan for Directors Amendment No. 1 -
Company's 10-K for year ended December 31, 1993 -
File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-21
(A)10-15 - Form of Deferred Compensation Plan for Directors -
Company's 10-K for year ended December 31, 1989 -
File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-22
(A)10-16 - Deferred Compensation Plan for Directors Amendment
No. 1 - Company's 10-K for year ended December
31, 1993 - File No. 1-3103-2. . . . . . . . . . . . . 10-23
(A)10-17 - Supplemental Executive Retirement Plan - Company's
10-Q for quarter ended March 31, 1994 -
File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-49
______________________________
(A) Management contract or compensatory plan or arrangement.
Exhibit No. Filed in As Exhibit No.
(A)10-19 - Supplemental Executive Retirement Plan Amendment
No. 2 - Company's 10-K for year ended December
31, 1987 - File No. 1-3103-2. . . . . . . . . . . . 10-19
(A)10-20 - Supplemental Executive Retirement Plan Amendment
No. 3 - Company's 10-K for year ended December 31,
1988 - File No. 1-3103-2. . . . . . . . . . . . . . 10-24
(A)10-21 - Supplemental Executive Retirement Plan Amendment
No. 4 - Company's 10-K for year ended December 31,
1990 - File No. 1-3103-2. . . . . . . . . . . . . . 10-30
(A)10-22 - Supplemental Executive Retirement Plan Amendment
No. 5 - Company's 10-K for year ended December 31,
1990 - File No. 1-3103-2. . . . . . . . . . . . . . 10-31
(A)10-23 - Supplemental Executive Retirement Plan Amendment
No. 6 - Company's 10-Q for quarter ended March 31,
1991 - File No. 1-3103-2. . . . . . . . . . . . . . 10-37
(A)10-24 - Supplemental Executive Retirement Plan Amendment
No. 7 - Company's 10-Q for quarter ended June 30,
1992 - File No. 1-3103-2. . . . . . . . . . . . . . 10-44
(A)10-25 - Supplemental Executive Retirement Plan Amendment
No. 8 - Company's 10-K for year ended December 31,
1993 - File No. 1-3103-2. . . . . . . . . . . . . . . 10-32
(A)10-26 - Supplemental Executive Retirement Plan Amendment
No. 9 - Company's 10-K for year ended December 31,
1993 - File No. 1-3103-2. . . . . . . . . . . . . . . 10-33
(A)10-27 - Supplemental Executive Retirement Plan Amendment
No. 10 - Company's 10-Q for quarter ended June 30,
1994 - File No. 1-3103-2. . . . . . . . . . . . . . . 10-50
(A)10-28 - Annual Executive Incentive Compensation Plan.
Company's 10-K for year ended December 31, 1992 -
File No. 1-3103-2 . . . . . . . . . . . . . . . . . . 10-30
(A)10-29 - Annual Executive Incentive Compensation Plan
Amendment No. 1 - Company's 10-K for year ended
December 31, 1993 - File No. 1-3103-2 . . . . . . . . 10-35
(A)10-30 - Annual Executive Incentive Compensation Plan
Amendment No. 2 - Company's 10-K for year ended
December 31, 1993 - File No. 1-3103-2 . . . . . . . . 10-36
(A)10-33 - Performance Share Plan - Company's 10-K for year
ended December 31, 1990 - File No. 1-3103-2 . . . . 10-36
(A)10-34 - Performance Share Plan Amendment No. 1 - Company's
10-Q for quarter ended March 31, 1991 -
File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-38
(A)10-35 - Performance Share Plan Amendment No. 2 - Company's
10-Q for quarter ended June 30, 1991 -
File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-39
(A)10-36 - Performance Share Plan Amendment No. 3 - Company's
10-K for year ended December 31, 1992 - File No.
1-3103-2. . . . . . . . . . . . . . . . . . . . . . 10-34
(A)10-37 - Performance Share Plan Amendment No. 4 - Company's
10-K for year ended December 31, 1993 - File No.
1-3103-2. . . . . . . . . . . . . . . . . . . . . . 10-41
(A)10-38 - Performance Share Deferred Compensation Plan -
Company's 10-K for year ended December 31, 1991
File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-40
______________________________
(A) Management contract or compensatory plan or arrangement.
(A)10-39 - Performance Share Deferred Compensation Plan -
Amendment No. 1 - Company's 10-K for year ended
December 31, 1993 - File No. 1-3103-2 . . . . . . . 10-43
(A)10-40 - Employment Contract for A. E. Kintigh - Company's
10-K for year ended December 31, 1988 - File
No. 1-3103-2. . . . . . . . . . . . . . . . . . . . 10-26
(A)10-42 - Employment Agreement for J. A. Carrigg - Company's
10-K for year ended December 31, 1993 - File No.
1-3103-2. . . . . . . . . . . . . . . . . . . . . . . 10-46
(A)10-43 - Form of Severance Agreement for Senior Vice
Presidents - Company's 10-K for year ended December
31, 1993 - File No. 1-3103-2. . . . . . . . . . . . . 10-47
(A)10-44 - Form of Severance Agreement for Vice Presidents -
Company's 10-K for year ended December 31, 1993 -
File No. 1-3103-2 . . . . . . . . . . . . . . . . . . 10-48
The Company agrees to furnish to the Commission, upon request, a copy of
the Revolving Credit Agreement dated as of July 31, 1992, between the Company,
Chemical Bank, as Agent, and certain banks; a copy of the Participation
Agreements dated as of June 1, 1987 and December 1, 1988 between the Company
and New York State Energy Research and Development Authority (NYSERDA) relating
to Adjustable Rate Pollution Control Revenue Bonds (1987 Series A), and (1988
Series A), respectively; a copy of the Participation Agreements dated as of
March 1, 1985, October 15, 1985, and December 1, 1985 between the Company and
NYSERDA relating to Annual Tender Pollution Control Revenue Bonds (1985 Series
A), (1985 Series B), and (1985 Series D), respectively; a copy of the
Participation Agreements dated as of February 1, 1993, February 1, 1994, June
1, 1994, October 1, 1994 and December 1, 1994 between the Company and NYSERDA
relating to Pollution Control Refunding Revenue Bonds (1994 Series A), (1994
Series B), (1994 Series C), (1994 Series D), and (1994 Series E), respectively;
a copy of the Participation Agreement dated as of December 1, 1993 between the
Company and NYSERDA relating to Solid Waste Disposal Revenue Bonds (1993 Series
A); a copy of the participation agreement dated as of December 1, 1994 between
the company and the Indiana County Industrial Development Authority relating to
Pollution Control Refunding Revenue Bonds (1994 Series A); a copy of the Credit
Agreement dated as of March 9, 1983, as amended, between Somerset Railroad
Corporation and Chemical Bank, and a copy of the Revolving Credit Agreement
dated as of June 30, 1994, as amended, between Xenergy Inc. and The First
National Bank of Boston. The total amount of securities authorized under each
of such agreements does not exceed 10% of the total assets of the Company and
its subsidiaries on a consolidated basis.
(b) Reports on Form 8-K
A report on Form 8-K, dated October 11, 1994, was filed during the
fourth quarter of 1994 to report certain information under Item 5, "Other
Events."
______________________________
(A) Management contract or compensatory plan or arrangement.
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.
NEW YORK STATE ELECTRIC & GAS CORPORATION
Date: March 10, 1995 By Gary J. Turton
Gary J. Turton
Controller
(Chief Accounting Officer)
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 and in the capacities and on the dates indicated.
PRINCIPAL EXECUTIVE OFFICER
Date: March 10, 1995 By James A. Carrigg
James A. Carrigg
Chairman, President,
Chief Executive Officer and
Director
PRINCIPAL FINANCIAL OFFICER
Date: March 10, 1995 By Sherwood J. Rafferty
Sherwood J. Rafferty
Vice President and Treasurer
PRINCIPAL ACCOUNTING OFFICER
Date: March 10, 1995 By Gary J. Turton
Gary J. Turton
Controller
Signatures (Cont'd)
Date: March 10, 1995 By Alison P. Casarett
Alison P. Casarett
Director
Date: March 10, 1995 By Everett A. Gilmour
Everett A. Gilmour
Director
Date: March 10, 1995 By Paul L. Gioia
Paul L. Gioia
Director
Date: March 10, 1995 By John M. Keeler
John M. Keeler
Director
Date: March 10, 1995 By Allen E. Kintigh
Allen E. Kintigh
Director
Date: March 10, 1995 By Ben E. Lynch
Ben E. Lynch
Director
Date: March 10, 1995 By Alton G. Marshall
Alton G. Marshall
Director
Date: March 10, 1995 By David R. Newcomb
David R. Newcomb
Director
Date: March 10, 1995 By Robert A. Plane
Robert A. Plane
Director
Date: March 10, 1995 By Charles W. Stuart
Charles W. Stuart
Director
EXHIBIT INDEX
* 3-1 -- Restated Certificate of Incorporation of the
Company pursuant to Section 807 of the Business
Corporation Law filed in the Office of the
Secretary of State of the State of New York on
October 25, 1988.
* 3-2 -- Certificate of Amendment of the Certificate of
Incorporation filed in the Office of the
Secretary of State of the State of New York on
October 17, 1989.
* 3-3 -- Certificate of Amendment of the Certificate of
Incorporation filed in the Office of the
Secretary of State of the State of New York on
May 22, 1990.
* 3-4 -- Certificate of Amendment of the Certificate of
Incorporation filed in the Office of the
Secretary of State of the State of New York on
October 31, 1990.
* 3-5 -- Certificate of Amendment of the Certificate of
Incorporation filed in the Office of the
Secretary of State of the State of New York on
February 6, 1991.
* 3-6 -- Certificate of Amendment of the Certificate of
Incorporation filed in the Office of the
Secretary of State of the State of New York on
October 15, 1991.
* 3-7 -- Certificate of Merger of Columbia Gas of New
York, Inc. into the Company filed in the Office
of the Secretary of State of the State of New
York on April 8, 1991.
* 3-8 -- Certificate of Amendment of the Certificate of
Incorporation filed in the Office of the
Secretary of State of the State of New York on
May 28, 1992.
* 3-9 -- Certificate of Amendment of the Certificate of
Incorporation filed in the Office of the
Secretary of State of the State of New York on
October 20, 1992.
* 3-10 -- Certificate of Amendment of the Certificate of
Incorporation filed in the Office of the
Secretary of State of the State of New York on
October 14, 1993.
* 3-11 -- Certificate of Amendment of the Certificate of
Incorporation filed in the Office of the
Secretary of State of the State of New York on
December 10, 1993.
* 3-12 -- Certificate of Amendment of the Certificate of
Incorporation filed in the Office of the
Secretary of State of the State of New York on
December 20, 1993.
___________________________________
* Incorporated by reference.
EXHIBIT INDEX (Cont'd)
* 3-13 -- Certificate of Amendment of the Certificate
of Incorporation filed in the Office of the
Secretary of State of the State of New York on
December 20, 1993.
* 3-14 -- Certificates of the Secretary of the Company
concerning consents dated March 20, 1957 and May
9, 1975 of holders of Serial Preferred Stock with
respect to issuance of certain unsecured
indebtedness.
* 3-15 -- By-Laws of the Company as amended February 25,
1994.
* 4-1 -- First Mortgage dated as of July 1, 1921 executed
by the Company under its then name of "New York
State Gas and Electric Corporation" to The
Equitable Trust Company of New York, as Trustee
(Chemical Bank is Successor Trustee).
Supplemental Indentures to First Mortgage dated as of July 1, 1921:
* 4-2 -- No. 37 * 4-9 -- No. 74 * 4-15 -- No. 103
* 4-3 -- No. 39 * 4-10 -- No. 75 * 4-16 -- No. 104
* 4-4 -- No. 43 * 4-11 -- No. 80 * 4-17 -- No. 105
* 4-5 -- No. 51 * 4-12 -- No. 81 * 4-18 -- No. 106
* 4-6 -- No. 68 * 4-13 -- No. 83 * 4-19 -- No. 107
* 4-7 -- No. 69 * 4-14 -- No. 102 * 4-20 -- No. 108
* 4-8 -- No. 71 * 4-21 -- No. 109
Agreements and Amendments with the Power Authority of the State of New York:
* 10-1 -- Letter Agreement dated February 3, 1982 relating
to transmission services.
* 10-2 -- Amendment dated December 21, 1989 to the Letter
Agreement dated February 3, 1982 relating to
transmission services.
* 10-3 -- Transmission Agreement dated December 12, 1983,
with respect to connection of the Company's
Kintigh (Somerset) Generating Station to the
Niagara-Edic 345 kv transmission system.
___________________________________
* Incorporated by reference.
EXHIBIT INDEX (Cont'd)
* 10-4 -- Amendment dated December 21, 1989 to the
Transmission Agreement dated December 12, 1983
with respect to connection of the Company's
Kintigh (Somerset) Generating Station to the
Niagara-Edic 345 kv transmission system.
* * * * * * * * * *
* 10-5 -- New York Power Pool Agreement dated July 11,
1985.
* 10-6 -- Transmission Agreement dated January 10, 1990
between New York State Electric & Gas Corporation
and Niagara Mohawk Power Corporation, with
respect to remote load and generation wheeling
service for the Company.
* * * * * * * * * *
Coal Sales Agreement and Amendments between New York State Electric & Gas
Corporation and Consolidation Coal Company:
* 10-7 -- Agreement dated December 21, 1983.
* 10-8 -- Amendment No. 1 dated as of October 1, 1985.
* 10-9 -- Amendment No. 2 dated as of August 28, 1986.
* * * * * * * * * *
* 10-10 -- Basic Agreement dated as of September 22, 1975
between New York State Electric & Gas Corporation
and others concerning Nine Mile Point Nuclear
Station, Unit No. 2.
* 10-11 -- Nine Mile Point Nuclear Station Unit 2 Operating
Agreement effective as of January 1, 1993 among
New York State Electric & Gas Corporation and
others.
___________________________________
* Incorporated by reference.
EXHIBIT INDEX (Cont'd)
* 10-12 -- Coal Hauling Agreement dated as of March 9, 1983
between Somerset Railroad Corporation and New
York State Electric & Gas Corporation.
(A)* 10-13 -- Retirement Plan for Directors.
(A)* 10-14 -- Retirement Plan for Directors Amendment No. 1
(A)* 10-15 -- Form of Deferred Compensation Plan for Directors.
(A)* 10-16 -- Deferred Compensation Plan for Directors
Amendment No. 1.
(A)* 10-17 -- Supplemental Executive Retirement Plan
(A) 10-18 -- Supplemental Executive Retirement Plan Amendment
No. 1.
(A)* 10-19 -- Supplemental Executive Retirement Plan Amendment
No. 2.
(A)* 10-20 -- Supplemental Executive Retirement Plan Amendment
No. 3.
(A)* 10-21 -- Supplemental Executive Retirement Plan Amendment
No. 4.
(A)* 10-22 -- Supplemental Executive Retirement Plan Amendment
No. 5.
(A)* 10-23 -- Supplemental Executive Retirement Plan Amendment
No. 6.
(A)* 10-24 -- Supplemental Executive Retirement Plan Amendment
No. 7.
(A)* 10-25 -- Supplemental Executive Retirement Plan Amendment
No. 8.
(A)* 10-26 -- Supplemental Executive Retirement Plan Amendment
No. 9.
(A)* 10-27 -- Supplemental Executive Retirement Plan Amendment
No. 10.
(A)* 10-28 -- Annual Executive Incentive Compensation Plan.
(A)* 10-29 -- Annual Executive Incentive Compensation Plan
Amendment No. 1.
(A)* 10-30 -- Annual Executive Incentive Compensation Plan
Amendment No. 2.
(A) 10-31 -- Annual Executive Incentive Compensation Plan Amendment
No. 3.
(A) 10-32 -- Annual Executive Incentive Compensation Plan Amendment
No. 4.
(A)* 10-33 -- Performance Share Plan.
(A)* 10-34 -- Performance Share Plan Amendment No. 1.
(A)* 10-35 -- Performance Share Plan Amendment No. 2.
(A)* 10-36 -- Performance Share Plan Amendment No. 3.
(A)* 10-37 -- Performance Share Plan Amendment No. 4.
(A)* 10-38 -- Performance Share Deferred Compensation Plan.
(A)* 10-39 -- Performance Share Deferred Compensation Plan Amendment No. 1.
(A)* 10-40 -- Employment Contract for A. E. Kintigh.
(A) 10-41 -- Agreement with M. I. German.
(A)* 10-42 -- Employment Agreement for J. A. Carrigg.
(A)* 10-43 -- Form of Severance Agreement for Senior Vice
Presidents.
(A)* 10-44 -- Form of Severance Agreement for Vice Presidents.
___________________________________
(A) Management contract or compenstory plan or arrangement.
* Incorporated by reference.
EXHIBIT INDEX (Cont'd)
12 -- Computation of Ratio of Earnings to Fixed Charges.
21 -- Subsidiaries.
23 -- Consent of Coopers & Lybrand to incorporation by
reference into certain registration statements.
27 -- Financial Data Schedule.
99-1 -- Form 11-K for New York State Electric & Gas
Corporation Tax Deferred Savings Plan for
Salaried Employees.
99-2 -- Form 11-K for New York State Electric & Gas
Corporation Tax Deferred Savings Plan for Hourly
Paid Employees.