NEW YORK STATE ELECTRIC & GAS CORPORATION
(Registrant)
FORM 10-K
---------
ANNUAL REPORT
For Fiscal Year Ended December 31, 1995
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. . . . . . . . . . . . . . . . . . 4
(b) Financial information about industry segments . . . 5
(c) Narrative description of business
Principal business . . . . . . . . . . . . . . . . 5
New product or segment . . . . . . . . . . . . . . 6
Sources and availability of raw materials. . . . . 6
Franchises . . . . . . . . . . . . . . . . . . . . 7
Seasonal business. . . . . . . . . . . . . . . . . 8
Working capital items. . . . . . . . . . . . . . . 8
Single customer. . . . . . . . . . . . . . . . . . 8
Backlog of orders. . . . . . . . . . . . . . . . . 8
Business subject to renegotiation. . . . . . . . . 8
Competitive conditions . . . . . . . . . . . . . . 8
Research and development . . . . . . . . . . . . . 12
Environmental matters. . . . . . . . . . . . . . . 12
Water quality. . . . . . . . . . . . . . . . . . 12
Air quality. . . . . . . . . . . . . . . . . . . 13
Waste disposal . . . . . . . . . . . . . . . . . 14
Number of employees. . . . . . . . . . . . . . . . 15
(d) Financial information about foreign and domestic
operations and export sales. . . . . . . . . . . 15
Item 2. Properties . . . . . . . . . . . . . . . . . . . . . . 16
Item 3. Legal proceedings. . . . . . . . . . . . . . . . . . . 17
Item 4. Submission of matters to a vote of security holders. . 24
Executive officers of the Registrant . . . . . . . . . . . . . . 24
PART II
Item 5. Market for Registrant's common stock and related
stockholder matters. . . . . . . . . . . . . . . . . 25
Item 6. Selected financial data. . . . . . . . . . . . . . . . 26
Principal sources of electric and natural gas revenues . . . . . 26
Item 7. Management's discussion and analysis of financial
condition and results of operations. . . . . . . . . 27
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. . . . . . . . . . . 74
Financial Statement Schedules
II. Consolidated Valuation and Qualifying
Accounts . . . . . . . . . . . . . . . . . . 75
Item 9. Changes in and disagreements with accountants on
accounting and financial disclosure. . . . . . . . . 76
PART III
Item 10. Directors and executive officers of the Registrant . . 76
Item 11. Executive compensation . . . . . . . . . . . . . . . . 76
Item 12. Security ownership of certain beneficial owners
and management . . . . . . . . . . . . . . . . . . . 76
Item 13. Certain relationships and related transactions . . . . 76
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 . . . . . . . . . . . . . . 76
Financial statement schedules. . . . . . . . . . 76
Exhibits
Exhibits delivered with this report. . . . . . 77
Exhibits incorporated herein by reference. . . 77
(b) Reports on Form 8-K. . . . . . . . . . . . . . . . 82
Signatures . . . . . . . . . . . . . . . . . . . . . . . . . . . 83
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, 1995.
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 [ X ].
* * * * * * * * * * *
The aggregate market value as of February 29, 1996 of the
common stock held by non-affiliates of the Registrant was
$1,689,254,288.
Common stock - 71,502,827 shares outstanding as of February
29, 1996.
DOCUMENTS INCORPORATED BY REFERENCE
Document 10-K Part
The company has incorporated by reference
certain portions of its Proxy Statement
dated March 29, 1996 which will be filed
with the Commission prior to April 30, 1996. 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, 1995:
Rates and regulatory matters
(See Item 1(c)(i) - Principal business and Item 1(c)(x) -
Competitive conditions.)
Electric Rate Settlement
On August 1, 1995, the Public Service Commission of the
State of New York (PSC) approved a new three-year electric rate
settlement agreement (electric agreement) for the period August
1, 1995 through July 31, 1998. The first year of the electric
agreement replaces the final year of the electric portion of the
company's previous three-year electric and natural gas rate
settlement agreement. Increases in the company's average
electric prices and the allowed returns on common equity under
the electric agreement for the rate years effective August 1 are:
1995 1996 1997
Price increase (millions) $45.1 $45.3 $45.5
percent 2.9% 2.8% 2.7%
Allowed return on equity 11.1% 11.2% 11.2%
Approximately 65% of the price increase in the electric
agreement is needed to cover the escalating cost of electricity
the company is required to buy from non-utility generators (NUGs)
and payments relating to the termination of several NUG
contracts. The company estimates that NUG power purchases,
excluding termination costs, will total $324 million in 1996,
$333 million in 1997 and $345 million in 1998 (See Note 9 to the
Consolidated Financial Statements).
To assure price predictability and stability, the fuel
adjustment clause, the revenue decoupling mechanism and most
other true-up mechanisms were eliminated in the electric
agreement. The production cost incentive was eliminated,
effective January 1, 1994. Only the service quality incentive
and an earnings performance incentive remain under the electric
agreement. Over the term of the electric agreement, the company
will amortize approximately $150 million of regulatory assets.
The electric agreement is subject to the order that will be
issued by the PSC in the Competitive Opportunities Proceeding.
Natural Gas Rate Settlement
On December 13, 1995, the PSC authorized a new natural gas
rate settlement agreement (gas agreement) that freezes natural
gas prices from December 15, 1995, until July 31, 1998. The
natural gas rates approved in the gas agreement made permanent
until July 31, 1998, a 3.2% increase, less an adjustment of about
$1 million. That increase became effective August 1, 1995, the
final year of the gas portion of the previous three-year electric
and natural gas rate settlement agreement.
An earnings sharing mechanism in the gas agreement provides
that the average of the earned equity returns (exclusive of
service quality awards or penalties) will be determined for the
three years, and half of the three-year average of net earnings
in excess of 14%, if any, will be shared with customers.
The gas agreement eliminates the gas adjustment clause and
the weather normalization clause. Those were used to collect
from or refund to customers amounts resulting from changes in the
cost of natural gas purchased and the effect of unusually warm or
cold weather on natural gas sales.
Diversification
(See Note 11 to the Consolidated Financial Statements)
NGE Enterprises, Inc. (NGE), a wholly owned subsidiary, owns
two unregulated businesses - EnerSoft Corporation (EnerSoft) and
XENERGY, Inc. (XENERGY).
Formed in May 1993, EnerSoft develops and markets computer
software and real-time information and trading systems for
natural gas utilities, marketers and pipeline operators.
EnerSoft, in alliance with the New York Mercantile Exchange, has
developed Channel 4, a natural gas and pipeline capacity trading
and information system for the North American market. The system
was available for use on August 11, 1995.
Electronic trading of natural gas and pipeline capacity is
an emerging market. The electronic trading industry is
continuously developing new products and the nature of the
industry and competition create a risk that certain products may
not recover the cost of their development. Channel 4 is
competing against other electronic gas trading systems, most of
which are owned and operated by natural gas pipeline companies.
The company believes Channel 4 is well positioned in features and
functionality to compete with other trading systems that are
available. However, sales to date have been disappointing.
EnerSoft has been incurring operating losses, and it is
anticipated that this will continue in 1996 and 1997. Market
acceptance of electronic gas trading and of the Channel 4 product
is key to improving EnerSoft's financial performance.
XENERGY, acquired in June 1994, is an energy services,
information systems and energy-consulting company providing
energy services, conservation engineering and professional
services to utilities, governmental agencies and end-use energy
consumers. XENERGY's 1995 revenues were lower than expected due
to a soft utility demand-side management (DSM) consulting market.
Revenues during the first half of 1996 are expected to be
comparable to levels at the end of 1995, but are expected to
improve by the end of 1996.
In order to meet the changing demands of the marketplace,
XENERGY's management undertook a major reorganization in November
1995. This will better position XENERGY to take advantage of the
emerging opportunities in a competitive utility industry. In
addition to focusing on new revenue sources, actions were taken
to reduce corporate overhead costs, including a reduction in
headcount.
NGE is also exploring environmental and operating services
opportunities with both domestic and foreign strategic partners
in the United States and international markets. In addition, NGE
is planning to form a finance subsidiary to support NGE's energy
services business.
For the years ended December 31, 1995, 1994 and 1993, NGE
incurred net losses of $12 million, $6 million and $1 million,
respectively. The company expects that NGE will continue to
incur operating losses at least through 1997. The loss in 1996
is expected to be comparable to 1995 with a slight improvement
expected in 1997. As of December 31, 1995 and 1994, the company
had invested approximately $54 million and $47 million,
respectively, in NGE to finance its diversified investments.
(b) Financial information about industry segments
(See Note 13 to the Consolidated Financial Statements.)
(c) Narrative description of business
(See Item 7 - Financial Review.)
(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 804,000 electric
customers and 235,000 natural gas customers. Its service
territory reflects a diversified economy, including high-tech
firms, light industry, colleges and universities, agriculture and
recreational facilities. No customer accounts for 5% or more of
either electric or natural gas revenues. For the years 1995,
1994, and 1993, 85%, 84% and 85%, respectively, of operating
revenues were derived from electric service and 15%, 16% and 15%,
respectively, were derived from natural gas service.
The 1995-1996 winter peak load of 2,497 megawatts (mw), was
set on December 11, 1995. This is 114 mw less than the all-time
peak of 2,611 mw set on January 19, 1994. Power supply
capability to meet peak loads is currently 3,494 mw. This is
composed of 2,500 mw of generating capacity (89% coal-fired, 8%
nuclear, and 3% hydroelectric) and 1,112 mw of purchases offset
by 118 mw of firm sales. The purchases are composed of 595 mw
from NUGs and 517 mw from the New York Power Authority (NYPA).
Most purchases from NYPA are hydroelectric power.
In February 1995 the company petitioned the Federal Energy
Regulatory Commission (FERC) asking for relief from having to pay
approximately $2 billion more than its avoided costs for power
purchased over the life of two NUG contracts. The company
believes that the overpayments under those two contracts violate
the Public Utility Regulatory Policies Act of 1978.
The FERC denied the petition in April 1995 and denied the
company's May 1995 request for a rehearing. On June 14, 1995,
the company filed a petition with the United States Court of
Appeals for the District of Columbia to review the FERC's
decision.
The company continues to seek cost-effective ways to
terminate or renegotiate existing NUG contracts and thus reduce
the overpayment burdens under those contracts.
On February 5, 1996, the company experienced its 1995-1996
maximum peak daily sendout for natural gas of 395,896 dekatherms.
This is 4,339 dekatherms less than the all-time peak of 400,235
dekatherms set on February 6, 1995.
(ii) New product or segment
(See Item 1(a) - Diversification.)
(iii) Sources and availability of raw materials
Electric
In 1995, approximately 90% of the company's generation was
coal-fired steam electric, 8% nuclear and 2% hydroelectric power.
About 42% of the company's steam electric generation in 1995 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 32% was supplied
from the company's Kintigh Generating Station, and the remaining
26% 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 3.0
million tons of coal purchased for the New York generating
stations in 1995, approximately 87% was purchased under
contract and the balance on the open market. Coal purchased
under contract is expected to be approximately 88% of the
estimated 3.2 million tons to be purchased in 1996.
The annual coal requirement for the Homer City
Generating Station is approximately 4.5 million tons, the
majority of which is obtained under long-term contracts.
During 1995, approximately 51% of Homer City Generating
Station coal was obtained under these contracts. The
company anticipates obtaining approximately 61% of the 1996
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, installed reload No. 4 into the
reactor core at NMP2. This refueling will support NMP2
operations through September 1996. Reload No. 5 is
scheduled for September 1996 and will support operations
through April 1998. Enrichment services are under contract
with the U.S. Enrichment Corporation for 100% of the
enrichment requirements through 1998 and 75% of the
requirements through 2003. Fuel fabrication services are
under contract through 2004. Approximately 70% of the
uranium and conversion requirements are under contract
through 2004.
Natural Gas
(See Item 7 - Competitive Conditions, Operational and Financial
Flexibility - Seneca Lake Storage Facility.)
As a result of FERC Order 636 (See Item 7 - Competitive
Conditions, Regulatory Changes - Natural Gas Industry.), the
company has 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 1995, about 51% of the
company's natural gas supply was purchased from various suppliers
under long-term and short-term sales contracts and 49% was
purchased 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 1996 in a similar proportion as in
1995.
(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 1995, the company obtained PSC authorizations for
natural gas distribution service in the towns of Chazy and
Patterson.
(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 7 - Competitive Conditions - Regulatory
Changes - Natural Gas Industry, Accounting Issues,
Customer Satisfaction and Operational and Financial
Flexibility.)
The electric and natural gas utility landscape is changing
rapidly as energy markets become more competitive, complex and
dynamic. The company is positioning itself to take maximum
advantage of the industry's move to a competitive market.
Regulatory changes, accounting issues, customer satisfaction, the
economic climate and operational and financial flexibility will
affect the company's competitive position. Those matters as well
as diversified opportunities closely related to the company's
core business are receiving focused attention as the company
transforms itself into a successful competitor.
Regulatory Changes
Regulatory issues being addressed by the PSC, regulators in
other states and the FERC will ultimately bring about dramatic
changes in the electric industry. Two significant proceedings in
which orders are expected to be issued before July 1996 are
discussed below: the PSC's Competitive Opportunities Proceeding
and the FERC's proceeding (Mega-NOPR) relating to the development
of competitive wholesale electric markets.
Competitive Opportunities Proceeding: In August 1994 the PSC
instituted an investigation of issues related to a restructuring
of the electric industry in New York. The overall objective of
the proceeding is to identify regulatory and ratemaking practices
that will assist in the transition to a more competitive electric
industry designed to increase efficiency in the provision of
electricity while meeting safety, environmental, affordability
and service quality goals.
In June 1995 the PSC adopted principles to guide the
transition to competition. The principles are designed to
provide a framework for electric competition and address issues
in eight categories related to providing electric service:
resource management, customer service, reliability and safety,
competitive market characteristics, regulatory issues, transition
issues, economic efficiency and economic developments. In
December 1995 a recommended decision (RD) was issued by an
administrative law judge and a senior staff representative
presiding over collaborative discussions that had been conducted
throughout 1995. The RD calls for a transition to wholesale
competition first with a recommendation that retail competition
be added later, once a competitive market is established and
reliability is ensured. The RD also recommends that the
generation function be separated from the transmission and
distribution functions to limit the exercise of market power.
However, the RD does not recommend divestiture of the generation
function. As part of the transition to competition, an
independent system operator (ISO) would be established to help
ensure reliable system operation. The ISO would maintain
responsibility for overall system reliability even beyond the
transition period.
The RD proposed that specific amounts of stranded costs be
determined in individual company proceedings to commence six
months after the PSC issues its order in the proceeding. It also
stated that the definition of stranded costs, the method of
measurement, requirements for mitigation, a preferable recovery
mechanism and a standard for recovery should all be resolved on a
generic basis. The RD suggested that there should be a
rebuttable presumption in favor of an adjustment applied to
stranded costs to account for unidentified potential mitigation
efforts. It also stated that the recovery of stranded costs
should involve a balancing of consumers' and stockholders'
interests.
The RD made the following additional points:
- Retail competition has the potential to benefit all
customers by providing greater choice among their
electricity providers, as well as increased pricing and
reliability options. But retail access brings with it
significant risks and requires considerable caution, and
should be provided only if it is in the best interests of
all consumers.
- Any restructuring model should include a mechanism for
recovering costs required to be spent on environmental and
other public policy considerations.
- To protect all customers, transmission and distribution
companies must remain obligated to serve all would-be
buyers. Consumer protections currently in place for
residential and nonresidential customers should remain.
The company is working closely on this matter with the
Energy Association of New York State (Energy Association), which
includes the company and seven other investor-owned utilities as
members. In January 1996 the Energy Association filed a brief
opposing certain recommendations included in the RD and filed a
reply brief in February 1996. The Energy Association's support
for the RD is subject to certain conditions, which include: a
reasonable opportunity for all utilities to recover all
expenditures and investments made to provide reliable service;
the PSC not mandating retail competition; and utilities being
afforded the option of remaining in the generation business,
subject to the functional separation of their generation
business, with separate accounting, but without mandated
divestiture. The RD is subject to review by the PSC, which will
ultimately accept, modify or reject it. A state-wide public
involvement and information program will be held before the PSC
issues an order. The PSC is expected to issue an order during
the first six months of 1996.
The company's ability to compete in the present wholesale
electric power market is demonstrated by the results it achieved
in 1995 with wholesale electric sales. However, certain above-
market costs that New York utilities bear impair their ability to
compete in the retail market with utilities in other states. The
Energy Association has urged the State of New York to immediately
implement policy changes to reduce electricity prices, changes
that could be accomplished without industry restructuring. For
example, policy changes could reduce costs associated with
purchases from NUGs, eliminate the gross receipts tax and reduce
other state and local taxes.
Mega-NOPR: The FERC's Mega-NOPR has two primary purposes: to
facilitate the development of competitive wholesale electric
markets by opening up transmission services and to address the
resulting stranded costs. The FERC is expected to issue an order
in this proceeding by mid-year 1996.
If the Mega-NOPR is adopted as currently proposed, the
company and other utilities with whom the company engages in
transmission and wholesale power transactions would be:
- required to file open access transmission tariffs under
which they would provide services, including ancillary
services, to third parties on a non-discriminatory basis;
- required to charge themselves, in the context of each
one's wholesale power sales, the same rate for
transmission that it charges its wholesale transmission
customers for the use of its system;
- permitted to recover legitimate and verifiable stranded
costs associated with a municipality establishing its own
electric system and newly created or expanded wholesale
customers;
- required to comply with regulations implementing the
filing of the open access tariffs and the initial rates
under these tariffs; and
- required to establish an electronic bulletin board, called
a real-time information network, which would provide all
transmission users simultaneous access to transmission
data.
Those requirements could affect the revenues received and
payments made by the company in connection with its transmission
and wholesale power transactions.
In July 1995 a coalition of utilities, including the
company, filed joint comments that addressed legal issues raised
by the Mega-NOPR. The coalition's comments support the FERC's
proposal on recovery of stranded costs associated with a
municipality establishing its own electric system and newly
created or expanded wholesale customers. The coalition also
urged the FERC to set a national policy to ensure recovery of
stranded costs associated with retail wheeling, or at a minimum
to accept filings to implement state-authorized stranded cost
charges to reduce the risk associated with challenges to state
authority to establish such charges.
Economic Climate
In addition to the regulatory changes discussed earlier, a
continuing challenge the company faces is New York's sluggish
economy. This limits sales growth opportunities and increases
the difficulty of retaining and expanding the company's
industrial customer base. However, the company believes that the
business outlook is brightening in New York State because of
positive changes in outlook at the state government level with
regard to reducing high taxes, government spending and excessive
regulation.
In the meantime, the company is focusing on maintaining and
improving sales through its marketing efforts. The company has
developed flexible rates that allow it to negotiate long-term
contracts with eligible electric and natural gas customers. The
contracts may cover existing load, new load or both. To date, 22
major electric industrial customers have signed contracts with
terms ranging from three to seven years. The contracts retain
more than $42 million and add another $12 million in annual
revenues. Together the contracts represent about 22% of annual
industrial electric revenues and about 3% of the company's total
annual electric revenues.
In January 1996 the PSC approved the company's proposal to
broaden eligibility for two of its flexible electric rates. Now
more commercial, industrial and public authority customers are
eligible for negotiated rates. Flexible rates help the company to
retain customers and attract new customers to its service
territory.
The company has new contracts with 12 major natural gas
customers for load additions totaling $2 million in annual
revenues. Each month the company develops over 275 natural gas
prices to compete with the alternative fuels available.
Also, the company has redesigned its economic development
program to cultivate opportunities to bring new jobs to New York
and the company's service territory. The program is designed to
effectively assist prospective customers, joint venture partners
and new customers.
(xi) Research and development
Expenditures on research and development in 1995, 1994, and
1993 amounted to $13.1 million, $14.5 million, and $18.9 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 and Notes 8, 9 and 10 to
the Consolidated Financial Statements)
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 comply with changing environmental laws and regulations.
Any additional compliance programs will require changes in the
company's operations and facilities and increase the cost of
electric and natural gas service. Historically, rate recovery
has been authorized for environmental compliance costs.
Capital additions to meet environmental requirements during
the three years ended December 31, 1995 were approximately $101
million and are estimated to be $17 million for 1996, $13 million
for 1997, and $16 million for 1998.
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. The
company's Homer City Generating Station in Pennsylvania has a
NPDES permit. 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. The
remediation work at Jennison Station was completed in 1995 at an
approximate cost of $.8 million. The remedial action, if
required, at Hickling, Milliken, and Greenidge Stations is
estimated to cost $2.9 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. The preliminary studies for Homer
City Station indicate there is no facility induced ground water
contamination. The Homer City Station studies are expected to be
completed in 1996.
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
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.
The Clean Air Act Amendments of 1990 (1990 Amendments)
contain provisions that limit emissions of sulfur dioxide and
nitrogen oxides and require emissions monitoring. Construction
of an innovative flue gas desulferization system and a nitrogen
oxide reduction system at the company's Milliken Generating
Station was completed in 1995 to comply with the sulphur dioxide
and nitrogen oxide emissions limitations. The company plans to
reduce its annual sulphur dioxide emissions by an amount that
will allow it to meet its established sulphur dioxide levels.
The established levels represent a 49% reduction from
approximately 138,000 tons in 1989 to 71,000 tons by the year
2000 and will remain at 71,000 tons thereafter. In addition, the
company anticipates that it will have to significantly reduce its
nitrogen oxide emissions 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 costs
to comply with these regulations cannot be estimated at this
time, since the reduction will be based on additional research
scheduled to be completed later in this decade.
The costs 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 several studies currently being performed by the
EPA. 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 recovered through rates
based on previous rate recovery of required environmental costs.
The EPA allocates 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 sulphur dioxide. During Phase I (which began January
1, 1995), 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 the
allowances for use in later years. By using a banking strategy,
it is estimated that Phase II (which begins January 1, 2000)
allowance requirements will be met through the year 2004 by
utilizing the allowances banked during Phase I, together with the
company's Phase II annual emissions allowances. That 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 all of its
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 those extension reserve allowances.
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.
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
2006.
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 costs 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 will be 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 4,117 employees as of December 31, 1995.
(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
Coal-fired capability (mw)
Goudey (Binghamton, N.Y.) 84 *
Greenidge (Dresden, N.Y.) 108 *
Hickling (East Corning, N.Y.) 44 *
Jennison (Bainbridge, N.Y.) 71
Milliken (Lansing, N.Y.) 300
Kintigh (Somerset, N.Y.) 675
Homer City (Homer City, Pa.) 944**
-----
Total coal-fired 2,226
Nuclear
NMP2 (Oswego, N.Y.) 206***
Hydroelectric (Various - 9 locations) 61
Internal combustion (Various - 2 locations) 7
-----
Total - all stations 2,500
=====
* The company placed one unit on long-term cold standby at
Goudey and Greenidge in 1994, and Hickling in 1995. These units
can be brought on-line in three to fourteen days and have a
combined capability of 132 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 13,425,000 kilovolt-amperes. The
transmission system consists of 4,852 circuit miles of line. The
distribution system consists of 33,606 pole miles of overhead
lines and 1,900 miles of underground lines.
The company's natural gas system consists of the
distribution of natural gas through 506 miles of transmission
pipelines (over 3-inch equivalent) and 5,928 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 and to transport coal to Milliken
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, Item 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), (e), (f), (h), (i),
(j) and the first paragraphs in (d) and (g). However, since the
PSC has allowed the company to recover in rates remediation costs
for certain of the sites referred to in the preceding sentence,
there is a reasonable basis to conclude that the company will be
permitted to recover in rates any remediation costs that it may
incur for all of the sites referred to in the preceding sentence.
Therefore, the company believes that the ultimate disposition of
the matters referred to below in (b), (c), (e), (f), (h), (i),
(j) and the first paragraphs in (d) and (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 New York State
Department of Environmental Conservation (NYSDEC) notified the
company that it had been identified as a potentially responsible
party (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 of Inactive Hazardous Waste Disposal Sites (New York
State Registry). Five other PRPs have been identified in the
NYSDEC letter. The company believes that remediation costs at
the Lockport Site might rise to $4 million. The Lockport Site
has been 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 as a result of hazardous
waste disposal 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 was 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. NYSDEC completed the
soil remediation at the Schreck's Site in February 1994 at a cost
of $2.6 million. Monitoring for ground water contamination
continues at the site. 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
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. The
company believes the PRPs currently involved in conducting
remediation at the Pfohl Site were much larger contributors.
In May 1995 the company agreed to participate in a process
for allocating remedial costs at the Pfohl Site with the other
PRPs. The company contributed $20,000 toward past costs, which
sum is subject to that allocation process.
Three actions were commenced against the company and
approximately 19 other defendants in the New York State Supreme
Court, Erie County (on January 17, 1995, April 7, 1995, and June
14, 1995, respectively), by plaintiffs who allegedly resided near
or recreated at the Pfohl Site in Cheektowaga, New York, claiming
damages for personal injuries, wrongful death, and loss of
consortium allegedly caused by exposure to hazardous chemicals
from the Pfohl Site. The plaintiffs allege that the defendants
are strictly liable, and were negligent or grossly negligent, for
disposing of hazardous and toxic materials at the Pfohl Site, and
they seek compensatory and punitive damages that total $71.5
million in the aggregate. The company believes that the actions
against it are without merit and will defend them vigorously.
In 1995 four actions were commenced against approximately 11
defendants by plaintiffs who allegedly resided near or recreated
at the Pfohl Site for personal injuries, wrongful death, and loss
of consortium allegedly caused by exposure to hazardous chemicals
from the Pfohl Site. The company was not named as a defendant in
these actions. Third-party actions were commenced in these four
actions against the company and ten other third-party defendants
in the U. S. District Court for the Western District of New York
(two on April 27, 1995, one on June 9, 1995, and one on November
7, 1995), by third-party plaintiffs who were named as defendants
in the main actions. The third-party plaintiffs allege that the
company and the ten other third-party defendants are liable for
all or part of any damages recovered by the plaintiffs. Recovery
in these third-party actions depends on the plaintiffs recovering
money damages against the third-party plaintiffs in the main
actions. The company believes that the actions against it are
without merit and will defend them vigorously.
(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 had 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. In September 1995 the company and the EPA reached
agreement on a consent order under which the company will pay the
sum of $10,000 in return for a covenant by the EPA not to sue the
company for the EPA's response costs to date, and to protect the
company from claims of contribution by other PRPs for costs
incurred to date. The order is awaiting final government
approval. 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 were contaminated with lead, allegedly due to
run-off from the adjacent Bern Metals Site. The EPA ordered the
company to perform the necessary removal work at the Clinton-
Bender Site and the company is remediating the site 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. The remediation is substantially
complete, except for the cleaning of the interior of the homes.
In addition, the company has already funded a per capita share of
the costs.
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 (Supreme Court, Erie County). The action was removed
to the U.S. District Court for the Western District of New York
(Western 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. By order dated September 1, 1995, the Western
District Court dismissed the plaintiffs claims made under 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, and remanded the action to the Supreme Court, Erie
County. 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 were identified in the
NYSDEC letter. 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. The company estimates that the present value of
costs for remedial alternatives range from $7.2 million to $21.7
million. The PRPs have presented an alternate concept for
remediation of the site and are engaged in discussions on the
merits of this alternative concept with 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 of transformers which may have
contained polychlorinated biphenyls (PCBs). Liability under
CERCLA may be joint and several.
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 and requested that the company participate
in the RI/FS then 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. While the study has been
completed, the EPA has not yet selected a remedy for the site,
and therefore, the total amount of remedial costs is currently
unknown.
(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. One hundred and
forty 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.
On September 27, 1995 the company joined with several other
PRPs in a settlement of the EPA's demand for reimbursement of
response costs incurred to date. Under this settlement, which
became final on January 30, 1996, the company will pay
approximately $8,000. Future response or remedial costs which the
EPA may incur at the Quanta Resources Site are not covered by
this settlement and the EPA has reserved its rights relating to
any such costs.
(k) The company responded on October 3, 1995, to a request for
information by the EPA concerning alleged disposal of PCBs at
facilities owned or operated by PCB Treatment, Inc. in Kansas
City, Kansas and Kansas City, Missouri. The company is currently
unable to determine its share, if any, relative to that of the
other parties who received such requests, of the costs to
remediate the sites. 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.
(l)On October 4, 1995 the company entered into an Order on
Consent with NYSDEC requiring the company to conduct an interim
remedial measure program under NYSDEC's oversight at a former
company maintenance facility in Chatham, New York. The interim
remedial measure program at the site, which is not listed in the
New York State Registry, was completed in November 1995 at a cost
of approximately $700,000. The company is awaiting confirmation
from NYSDEC that it has fulfilled its obligation under the Order
on Consent.
(m) 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 U. S. District Court
for the Eastern District of New York (Eastern District Court).
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.
On November 23, 1994, the Defendants made a motion to
dismiss. On August 21, 1995 the Eastern District Court issued a
decision which granted the motion to dismiss and dismissed the
action in its entirety. Plaintiffs appealed that decision to the
U.S. Court of Appeals for the Second Circuit. The Defendants are
defending 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 1991 to date
James A. Carrigg 62 Chairman, President and Chief Execu-
tive Officer, January 1991 to date.
Jack H. Roskoz 57 Executive Vice President, January 1995
to date; Senior Vice President-Electric
Business Unit, to January 1995.
Michael I. German 45 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 45 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.
Sherwood J. Rafferty 48 Senior Vice President and Chief
Financial Officer, February 1996 to
date; Vice President and Treasurer, to
February 1996.
Daniel W. Farley 40 Vice President and Secretary, May 1991
to date; Secretary, to May 1991.
Jeffrey K. Smith 47 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.
Ralph R. Tedesco 42 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.
Executive officers of the Registrant (Cont'd)
Positions, offices and
business experience -
Name Age January 1991 to date
Gary J. Turton 48 Vice President and Controller, February
1996 to date; Controller, December 1994
to February 1996; Assistant Controller,
to December 1994.
Denis E. Wickham 47 Vice President-Electric Resource
Planning, January 1991 to date.
Robert D. Kump 34 Treasurer, February 1996 to date;
Director of Financial Services,
February 1995 to February 1996;
Manager-Investor Relations, October
1993 to February 1995; Specialist-
Investor Relations, to October 1993.
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, 1997, 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 is
elected or appointed, and until his 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 4 and Note 14 to the Consolidated Financial
Statements.
Item 6. Selected financial data
(Thousands-except per share amounts) 1995 1994 1993 1992 1991
- ------------------------------------------------------------------------------------------------------
Operating revenues $2,009,541 $1,898,855 $1,800,149 $1,691,689 $1,555,815
Net income $196,690 $187,645* $166,028** $183,968 $168,643
Earnings per share $2.49 $2.37* $2.08** $2.40 $2.36
Dividends paid per share $1.40 $2.00 $2.18 $2.14 $2.10
Average shares outstanding 71,503 71,254 69,990 67,972 62,906
Book value per share of common stock(year end) $24.38 $23.28 $22.89 $22.85 $22.16
Interest charges $130,919 $139,725 $145,450 $155,388 $163,526
AFDC and non-cash return $4,821 $7,974 $8,003 $6,482 $7,541
Depreciation and amortization $184,770 $178,326 $164,568 $158,977 $152,380
Other taxes $210,910 $210,729 $204,962 $200,941 $178,185
Capital expenditures $158,681 $224,306 $245,029 $245,618 $245,883
Total assets $5,114,331 $5,222,905 $5,287,958 $5,077,916 $4,924,836
Long-term obligations,capital leases and
redeemable preferred stock $1,606,448 $1,776,081 $1,755,629 $1,883,927 $1,897,465
* Reflects the effect of the 1993 production-cost penalty that decreased net income by $8 million and
decreased earnings per share by 12 cents.
**Refelcts the effect of restructuring expenses that decreased net income by $17.2 million and
decreased earnings per share by 25 cents.
Principal Sources of Electric and Natural Gas Revenues
ELECTRIC 1995 % of Total 1994 % of Total 1993 % of Total
-------------------------------------------------------------------------
Kwh Sales (Millions):
Residential 5,286 25.5 % 5,399 27.0 % 5,423 28.0 %
Commercial 3,405 16.4 3,315 16.6 3,298 17.1
Industrial 3,010 14.5 2,997 15.0 2,950 15.3
Other 1,392 6.7 1,437 7.2 1,417 7.3
----------- ------- ----------- ------- ----------- -------
Total Retail 13,093 63.1 13,148 65.8 13,088 67.7
Other electric utilities 7,636 36.9 6,827 34.2 6,233 32.3
----------- ------- ----------- ------- ----------- -------
Total 20,729 100.0 % 19,975 100.0 % 19,321 100.0 %
=========== ======= =========== ======= =========== =======
Operating Revenues (Thousands):
Residential $725,299 42.5 % $679,124 42.4 % $635,155 41.6 %
Commercial 395,076 23.1 366,854 22.9 333,674 21.8
Industrial 247,576 14.5 245,218 15.3 228,215 14.9
Other 158,568 9.3 153,888 9.7 138,320 9.1
----------- ------- ----------- ------- ----------- -------
Total Retail 1,526,519 89.4 1,445,084 90.3 1,335,364 87.4
Other electric utilities 150,444 8.8 141,902 8.9 147,175 9.6
Other operating revenues 31,334 1.8 13,089 .8 44,823 3.0
----------- ------- ----------- ------- ----------- -------
Total Operating Revenues $1,708,297 100.0 $1,600,075 100.0 % $1,527,362 100.0 %
=========== ======= =========== ======= =========== =======
NATURAL GAS
Dekatherm(Thousands):
Residential 23,512 40.2 % 24,662 42.1 % 25,080 43.2 %
Commercial 10,540 18.0 10,611 18.1 10,640 18.3
Industrial 2,587 4.4 2,180 3.7 1,820 3.2
Other 2,463 4.2 2,038 3.5 1,805 3.1
----------- ------- ----------- ------- ----------- -------
Total Retail 39,102 66.8 39,491 67.4 39,345 67.8
Transportation of customer-owned
natural gas 19,433 33.2 19,133 32.6 18,701 32.2
----------- ------- ----------- ------- ----------- -------
Total 58,535 100.0 % 58,624 100.0 % 58,046 100.0 %
=========== ======= =========== ======= =========== =======
Operating Revenues(Thousands):
Residential $181,697 60.3 $185,073 61.9 % $170,734 62.6 %
Commercial 75,178 25.0 72,360 24.2 66,648 24.5
Industrial 11,310 3.8 11,542 3.9 9,602 3.5
Other 14,584 4.8 12,997 4.4 10,943 4.0
----------- ------- ----------- ------- ----------- -------
Total Retail 282,769 93.9 281,972 94.4 257,927 94.6
Transportation of customer-owned
natural gas 13,718 4.5 12,791 4.3 12,091 4.4
Unbilled revenue recognition-net 1,700 .6 3,768 1.3 2,686 1.0
Other natural gas revenue 3,057 1.0 249 - 83 -
----------- ------- ----------- ------- ----------- -------
Total Operating Revenues $301,244 100.0 % $298,780 100.0 % $272,787 100.0 %
=========== ======= =========== ======= =========== =======
Item 7. Management's discussion and analysis of financial
condition and results of operations
Liquidity and Capital Resources
Competitive Conditions
The electric and natural gas utility landscape is changing
rapidly as energy markets become more competitive, complex and
dynamic. The company is positioning itself to take maximum
advantage of the industry's move to a competitive market.
Regulatory changes, accounting issues, customer satisfaction, the
economic climate and operational and financial flexibility will
affect the company's competitive position. Those matters as well
as diversified opportunities closely related to the company's
core business are receiving focused attention as the company
transforms itself into a successful competitor.
Regulatory Changes
Regulatory issues being addressed by the Public Service
Commission of the State of New York (PSC), regulators in other
states and the Federal Energy Regulatory Commission (FERC) will
ultimately bring about dramatic changes in the electric industry.
Two significant proceedings in which orders are expected to be
issued before July 1996 are discussed below: the PSC's
Competitive Opportunities Proceeding and the FERC's proceeding
(Mega-NOPR) relating to the development of competitive wholesale
electric markets.
Competitive Opportunities Proceeding: In August 1994 the PSC
instituted an investigation of issues related to a restructuring
of the electric industry in New York. The overall objective of
the proceeding is to identify regulatory and ratemaking practices
that will assist in the transition to a more competitive electric
industry designed to increase efficiency in the provision of
electricity while meeting safety, environmental, affordability
and service quality goals.
In June 1995 the PSC adopted principles to guide the
transition to competition. The principles are designed to
provide a framework for electric competition and address issues
in eight categories related to providing electric service:
resource management, customer service, reliability and safety,
competitive market characteristics, regulatory issues, transition
issues, economic efficiency and economic developments. In
December 1995 a recommended decision (RD) was issued by an
administrative law judge and a senior staff representative
presiding over collaborative discussions that had been conducted
throughout 1995. The RD calls for a transition to wholesale
competition first with a recommendation that retail competition
be added later, once a competitive market is established and
reliability is ensured. The RD also recommends that the
generation function be separated from the transmission and
distribution functions to limit the exercise of market power.
However, the RD does not recommend divestiture of the generation
function. As part of the transition to competition, an
independent system operator (ISO) would be established to help
ensure reliable system operation. The ISO would maintain
responsibility for overall system reliability even beyond the
transition period.
The RD proposed that specific amounts of stranded costs be
determined in individual company proceedings to commence six
months after the PSC issues its order in the proceeding. It also
stated that the definition of stranded costs, the method of
measurement, requirements for mitigation, a preferable recovery
mechanism and a standard for recovery should all be resolved on a
generic basis. The RD suggested that there should be a
rebuttable presumption in favor of an adjustment applied to
stranded costs to account for unidentified potential mitigation
efforts. It also stated that the recovery of stranded costs
should involve a balancing of consumers' and stockholders'
interests.
The RD made the following additional points:
- Retail competition has the potential to benefit all
customers by providing greater choice among their
electricity providers, as well as increased pricing and
reliability options. But retail access brings with it
significant risks and requires considerable caution, and
should be provided only if it is in the best interests of
all consumers.
- Any restructuring model should include a mechanism for
recovering costs required to be spent on environmental and
other public policy considerations.
- To protect all customers, transmission and distribution
companies must remain obligated to serve all would-be
buyers. Consumer protections currently in place for
residential and nonresidential customers should remain.
The company is working closely on this matter with the
Energy Association of New York State (Energy Association), which
includes the company and seven other investor-owned utilities as
members. In January 1996 the Energy Association filed a brief
opposing certain recommendations included in the RD and filed a
reply brief in February 1996. The Energy Association's support
for the RD is subject to certain conditions, which include: a
reasonable opportunity for all utilities to recover all
expenditures and investments made to provide reliable service;
the PSC not mandating retail competition; and utilities being
afforded the option of remaining in the generation business,
subject to the functional separation of their generation
business, with separate accounting, but without mandated
divestiture. The RD is subject to review by the PSC, which will
ultimately accept, modify or reject it. A state-wide public
involvement and information program will be held before the PSC
issues an order. The PSC is expected to issue an order during
the first six months of 1996.
The company's ability to compete in the present wholesale
electric power market is demonstrated by the results it achieved
in 1995 with wholesale electric sales. However, certain above-
market costs that New York utilities bear impair their ability to
compete in the retail market with utilities in other states. The
Energy Association has urged the State of New York to immediately
implement policy changes to reduce electricity prices, changes
that could be accomplished without industry restructuring. For
example, policy changes could reduce costs associated with
purchases from non-utility generators (NUGs), eliminate the gross
receipts tax and reduce other state and local taxes.
Mega-NOPR: The FERC's Mega-NOPR has two primary purposes: to
facilitate the development of competitive wholesale electric
markets by opening up transmission services and to address the
resulting stranded costs. The FERC is expected to issue an order
in this proceeding by mid-year 1996.
If the Mega-NOPR is adopted as currently proposed, the
company and other utilities with whom the company engages in
transmission and wholesale power transactions would be:
- required to file open access transmission tariffs under
which they would provide services, including ancillary
services, to third parties on a non-discriminatory basis;
- required to charge themselves, in the context of each
one's wholesale power sales, the same rate for
transmission that it charges its wholesale transmission
customers for the use of its system;
- permitted to recover legitimate and verifiable stranded
costs associated with a municipality establishing its own
electric system and newly created or expanded wholesale
customers;
- required to comply with regulations implementing the
filing of the open access tariffs and the initial rates
under these tariffs; and
- required to establish an electronic bulletin board, called
a real-time information network, which would provide all
transmission users simultaneous access to transmission
data.
Those requirements could affect the revenues received and
payments made by the company in connection with its transmission
and wholesale power transactions.
In July 1995 a coalition of utilities, including the
company, filed joint comments that addressed legal issues raised
by the Mega-NOPR. The coalition's comments support the FERC's
proposal on recovery of stranded costs associated with a
municipality establishing its own electric system and newly
created or expanded wholesale customers. The coalition also
urged the FERC to set a national policy to ensure recovery of
stranded costs associated with retail wheeling, or at a minimum
to accept filings to implement state-authorized stranded cost
charges to reduce the risk associated with challenges to state
authority to establish such charges.
Natural Gas Industry: The natural gas business has operated for
two years under FERC Order 636, which requires interstate natural
gas pipeline companies to offer customers unbundled, or separate,
services equivalent to their former sales service. FERC Order
636 provides customers greater opportunities to obtain natural
gas supply, transportation and storage. Increased choices should
result in lower natural gas costs. The company has already taken
advantage of several new opportunities under FERC Order 636,
including flexible purchasing and delivery points, off-system
sales and access to the secondary market for selling pipeline
capacity when it is not needed by retail customers.
The restructuring of services required by FERC Order 636
imposed transition costs on pipelines. Those transition costs
include the costs of revising natural gas supply contracts,
unrecovered costs that would otherwise have been billed to
pipeline customers 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' related filings with the FERC to recover such costs.
The company has reached final resolution with all but one of its
pipeline suppliers regarding transition costs and is negotiating
with the one remaining pipeline supplier. The company's
estimated remaining liability for transition costs was $12
million and $21 million at December 31, 1995 and 1994,
respectively. A corresponding regulatory asset has been recorded
by the company since the PSC has ruled that transition costs are
fully recoverable from the company's customers and the costs are
now included in rates.
The PSC issued an Opinion and Order in December 1994 that
set forth the policy framework to guide the transition and
movement of New York's gas distribution industry to a more
competitive marketplace in the post-FERC Order 636 environment.
The PSC subsequently issued an Order on Reconsideration in August
1995 addressing petitions for rehearing or clarification of this
Opinion. The company, and other utilities, recently filed
restructuring tariffs in compliance with the PSC's Opinion and
Order on Reconsideration. Under the company's proposed tariffs
residential and small commercial customers will be eligible for
transportation service through small customer aggregation
programs. Consistent with the PSC's Opinion and Order on
Reconsideration, the company proposed new services that allow the
company to more effectively compete for sales to larger, more
sophisticated transportation customers. The company is awaiting
approval of these tariff revisions.
In a separate Order, the PSC instituted a proceeding
(currently in the settlement phase) to investigate gas cost
incentive mechanisms and affordability guidelines. In addition,
the company and other utilities have filed comments concerning
key characteristics for a gas cost incentive mechanism and
proposed guidelines for adoption of any such mechanisms.
Accounting Issues
Effects of Regulation: The PSC's Competitive Opportunities
Proceeding could affect the eligibility of the company to
continue applying Statement of Financial Accounting Standards No.
71 (Statement 71), Accounting for the Effects of Certain Types of
Regulation. Continued accounting under Statement 71 requires
that the company's regulated operations meet all of the following
three criteria:
- rates for regulated services or products provided to
customers are subject to approval by an independent,
third party regulator,
- the regulated rates are designed to recover the company's
costs of providing regulated services or products, and
- it is reasonable to assume that rates set at levels that
will recover the company's costs can be charged to and
collected from customers.
If the company could no longer meet the Statement 71
criteria for all or a part of its business, the company would
have to record as expense or revenue certain previously deferred
items that had been recognized as assets and liabilities
according to Statement 71, but that would not have been
recognized as such by enterprises in general. At December 31,
1995 and 1994, the company had $690 million and $779 million,
respectively, of regulatory assets, and $294 million and $337
million, respectively, of regulatory liabilities on its balance
sheets (See Note 1). Although the company believes it will
continue to meet the Statement 71 criteria in the near future, it
cannot predict what effect a competitive marketplace or future
PSC actions will have on its ability to continue to do so.
The company has other costs that are currently being
recovered through rates that may not be fully recoverable in a
competitive marketplace. Those costs include mandated purchases
of NUG power at above-market prices and average costs for certain
generating plants that may be above the market price for
electricity. The inability to recover those costs may have an
adverse effect on the company.
Impairment of Long-Lived Assets: In March 1995 the Financial
Accounting Standards Board issued Statement of Financial
Accounting Standards No. 121 (Statement 121), Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be
Disposed Of, effective for fiscal years beginning after December
15, 1995. Statement 121 requires that long-lived assets be
reviewed for impairment whenever events or changes in
circumstances indicate that the carrying amount may not be
recoverable. An impairment would be recognized if the sum of the
estimated future undiscounted cash flows to be generated by an
asset is less than its carrying value. The amount of the
impairment would be based on a comparison of book value to fair
value.
Statement 121 also amends Statement 71 to require the write-
off of a regulatory asset if it is no longer probable that future
revenues will recover the cost of the asset. The adoption of
Statement 121 will not have a material effect on the company's
financial position or results of operations. However, the
company cannot predict what effect a competitive marketplace or
future PSC actions will have on the effect of the application of
Statement 121.
Customer Satisfaction
The company is continuing its efforts to deliver high-
quality customer service and become a more efficient provider of
electric and gas retail service in order to build customer
loyalty. The Customer Service Business Unit (CSBU) was created
by the company at the end of 1994 to accomplish those objectives
and bring together all aspects of customer service - including
the customer call center, transmission and distribution
operations, electric marketing and sales and all division
operations. Concentrating customer service in one business unit
is improving that service and cutting costs. During 1995 the
customer call center handled more calls more quickly than in the
prior year. The number of customer representatives has
increased, and improvements have also been made in training and
support.
To build stronger customer relationships, the CSBU is
initially concentrating on four business processes: customer
billing, service connections, developing new products and
collection efforts. Progress is being made toward achieving
established goals.
Another way to improve customer satisfaction is by providing
price stability. Electric price increases have been minimized
under the company's new three-year electric rate settlement
agreement at rates close to expected inflation, and gas prices
were frozen under the new natural gas rate settlement agreement
(See Rate Matters). The company continues to focus on improving
the cost and delivery of power and natural gas to its customers
while maintaining a high level of service.
Economic Climate
In addition to the regulatory changes discussed earlier, a
continuing challenge the company faces is New York's sluggish
economy. This limits sales growth opportunities and increases
the difficulty of retaining and expanding the company's
industrial customer base. However, the company believes that the
business outlook is brightening in New York State because of
positive changes in outlook at the state government level with
regard to reducing high taxes, government spending and excessive
regulation.
In the meantime, the company is focusing on maintaining and
improving sales through its marketing efforts. The company has
developed flexible rates that allow it to negotiate long-term
contracts with eligible electric and natural gas customers. The
contracts may cover existing load, new load or both. To date, 22
major electric industrial customers have signed contracts with
terms ranging from three to seven years. The contracts retain
more than $42 million and add another $12 million in annual
revenues. Together the contracts represent about 22% of annual
industrial electric revenues and about 3% of the company's total
annual electric revenues.
In January 1996 the PSC approved the company's proposal to
broaden eligibility for two of its flexible electric rates. Now
more commercial, industrial and public authority customers are
eligible for negotiated rates. Flexible rates help the company to
retain customers and attract new customers to its service
territory.
The company has new contracts with 12 major natural gas
customers for load additions totaling $2 million in annual
revenues. Each month the company develops over 275 natural gas
prices to compete with the alternative fuels available.
Also, the company has redesigned its economic development
program to cultivate opportunities to bring new jobs to New York
and the company's service territory. The program is designed to
effectively assist prospective customers, joint venture partners
and new customers.
Operational and Financial Flexibility
The company continually reviews its strategic plans to
address the challenges of competition, including ways to improve
operational and financial flexibility.
Seneca Lake Storage Facility: Construction began on the
company's $57 million Seneca Lake storage project in September
1995. The project consists of a natural gas storage cavern
located north of Watkins Glen on the west side of Seneca Lake, a
compressor station and two gas transmission pipelines. The
project's primary purpose is to ensure adequate natural gas
supply to customers. In addition, the project will increase
supply flexibility, allow the company to retire two propane
plants and reduce pipeline demand charges. The PSC issued a
certificate of environmental compatibility and public need and
approved construction plans for the compressor station and most
of the western pipeline. The PSC is expected to issue a
certificate for the eastern pipeline by mid-year 1996. The New
York State Department of Environmental Conservation granted the
company a conditional permit to store natural gas in the cavern.
The project is scheduled to be in service for the 1996-1997
heating season.
Generation Department and Generating Unit Performance: The
company's generation department is preparing for competition by
developing its ability to operate as an independent business.
The target date for that capability is January 1, 1997. In order
to prepare for it, several tasks are being undertaken such as:
assessing the requirements and abilities needed to operate in a
competitive generation market; minimizing above-market
investments; reducing the average costs of generation;
strengthening sales and marketing capabilities; transforming to
competitive business processes, technology and practices; and
improving strategic business planning.
In June 1995 the company placed a 35 megawatt (MW)
generating unit at its Hickling Generating Station on long-term
cold standby. Two other generating units (97 MW) were placed on
long-term cold standby during 1994. A generating unit on long-
term cold standby at Greenidge Generating Station was operated
intermittently during 1995 to take advantage of wholesale sales
opportunities. The company continues to closely evaluate the
performance of five other units (308 MW) to ensure that their
output remains marketable and their operation economical.
Financial Strategies: The company believes that maintaining
financial integrity and flexibility is critical to success in a
competitive environment. In addition to overall expense
controls, the company has taken action in the past two years to
maximize cash flow and improve financial flexibility, including
significant cuts in capital spending and a common stock dividend
reduction in October 1994. As a result, the company expects to
have cash in excess of its operating and capital needs over the
next several years. How this cash is utilized will depend on
industry and market conditions and could include continued debt
and preferred stock redemptions, additional investments in
unregulated businesses or the repurchase of common stock. In
September 1995 the company received PSC approval to repurchase
not to exceed 4 million shares of its common stock. The company
may use risk management techniques to manage commodity prices and
interest rate risk.
Petition to FERC on NUGs: In February 1995 the company
petitioned the FERC asking for relief from having to pay
approximately $2 billion more than its avoided costs for power
purchased over the life of two NUG contracts. The company
believes that the overpayments under those two contracts violate
the Public Utility Regulatory Policies Act of 1978.
The FERC denied the petition in April 1995 and denied the
company's May 1995 request for a rehearing. On June 14, 1995,
the company filed a petition with the United States Court of
Appeals for the District of Columbia to review the FERC's
decision.
The company continues to seek cost-effective ways to
terminate or renegotiate existing NUG contracts and thus reduce
the overpayment burdens under those contracts.
Diversification (See Note 11.)
NGE Enterprises, Inc. (NGE), a wholly owned subsidiary, owns
two unregulated businesses - EnerSoft Corporation (EnerSoft) and
XENERGY, Inc. (XENERGY).
Formed in May 1993, EnerSoft develops and markets computer
software and real-time information and trading systems for
natural gas utilities, marketers and pipeline operators.
EnerSoft, in alliance with the New York Mercantile Exchange, has
developed Channel 4, a natural gas and pipeline capacity trading
and information system for the North American market. The system
was available for use on August 11, 1995.
Electronic trading of natural gas and pipeline capacity is
an emerging market. The electronic trading industry is
continuously developing new products and the nature of the
industry and competition create a risk that certain products may
not recover the cost of their development. Channel 4 is
competing against other electronic gas trading systems, most of
which are owned and operated by natural gas pipeline companies.
The company believes Channel 4 is well positioned in features and
functionality to compete with other trading systems that are
available. However, sales to date have been disappointing.
EnerSoft has been incurring operating losses, and it is
anticipated that this will continue in 1996 and 1997. Market
acceptance of electronic gas trading and of the Channel 4 product
is key to improving EnerSoft's financial performance.
XENERGY, acquired in June 1994, is an energy services,
information systems and energy-consulting company providing
energy services, conservation engineering and professional
services to utilities, governmental agencies and end-use energy
consumers. XENERGY's 1995 revenues were lower than expected due
to a soft utility demand-side management (DSM) consulting market.
Revenues during the first half of 1996 are expected to be
comparable to levels at the end of 1995, but are expected to
improve by the end of 1996.
In order to meet the changing demands of the marketplace,
XENERGY's management undertook a major reorganization in November
1995. This will better position XENERGY to take advantage of the
emerging opportunities in a competitive utility industry. In
addition to focusing on new revenue sources, actions were taken
to reduce corporate overhead costs, including a reduction in
headcount.
NGE is also exploring environmental and operating services
opportunities with both domestic and foreign strategic partners
in the United States and international markets. In addition, NGE
is planning to form a finance subsidiary to support NGE's energy
services business.
For the years ended December 31, 1995, 1994 and 1993, NGE
incurred net losses of $12 million, $6 million and $1 million,
respectively. The company expects that NGE will continue to
incur operating losses at least through 1997. The loss in 1996
is expected to be comparable to 1995 with a slight improvement
expected in 1997. As of December 31, 1995 and 1994, the company
had invested approximately $54 million and $47 million,
respectively, in NGE to finance its diversified investments.
Rate Matters
Electric Rate Settlement
On August 1, 1995, the PSC approved a new three-year
electric rate settlement agreement (electric agreement) for the
period August 1, 1995 through July 31, 1998. The first year of
the electric agreement replaces the final year of the electric
portion of the company's previous three-year electric and natural
gas rate settlement agreement. Increases in the company's
average electric prices and the allowed returns on common equity
under the electric agreement for the rate years effective August
1 are:
1995 1996 1997
Price increase (millions) $45.1 $45.3 $45.5
percent 2.9% 2.8% 2.7%
Allowed return on equity 11.1% 11.2% 11.2%
Approximately 65% of the price increase in the electric
agreement is needed to cover the escalating cost of electricity
the company is required to buy from NUGs and payments relating to
the termination of several NUG contracts. The company estimates
that NUG power purchases, excluding termination costs, will total
$324 million in 1996, $333 million in 1997 and $345 million in
1998 (See Note 9).
To assure price predictability and stability, the fuel
adjustment clause, the revenue decoupling mechanism and most
other true-up mechanisms were eliminated in the electric
agreement. The production cost incentive was eliminated,
effective January 1, 1994. Only the service quality incentive
and an earnings performance incentive remain under the electric
agreement. Over the term of the electric agreement, the company
will amortize approximately $150 million of regulatory assets.
The electric agreement is subject to the order that will be
issued by the PSC in the Competitive Opportunities Proceeding.
Natural Gas Rate Settlement
On December 13, 1995, the PSC authorized a new natural gas
rate settlement agreement (gas agreement) that freezes natural
gas prices from December 15, 1995, until July 31, 1998. The
natural gas rates approved in the gas agreement made permanent
until July 31, 1998, a 3.2% increase, less an adjustment of about
$1 million. That increase became effective August 1, 1995, the
final year of the gas portion of the previous three-year electric
and natural gas rate settlement agreement.
An earnings sharing mechanism in the gas agreement provides
that the average of the earned equity returns (exclusive of
service quality awards or penalties) will be determined for the
three years, and half of the three-year average of net earnings
in excess of 14%, if any, will be shared with customers.
The gas agreement eliminates the gas adjustment clause and
the weather normalization clause. Those were used to collect
from or refund to customers amounts resulting from changes in the
cost of natural gas purchased and the effect of unusually warm or
cold weather on natural gas sales.
Environmental Matters (See Notes 9 and 10.)
The company continually assesses actions that may need to be
taken to comply with changing environmental laws and regulations.
Any additional compliance programs will require changes in the
company's operations and facilities and increase the cost of
electric and natural gas service. Historically, rate recovery
has been authorized for environmental compliance costs.
The Clean Air Act Amendments of 1990 (1990 Amendments)
contain provisions that limit emissions of sulfur dioxide and
nitrogen oxides and require emissions monitoring. Construction
of an innovative flue gas desulfurization system and a nitrogen
oxide reduction system at the company's Milliken Generating
Station was completed in 1995 to comply with the sulfur dioxide
and nitrogen oxide emissions limitations. The company plans to
reduce its annual sulfur dioxide emissions by an amount that will
allow it to meet its established sulfur dioxide levels. The
established levels represent a 49% reduction from approximately
138,000 tons in 1989 to 71,000 tons by the year 2000, and will
remain at 71,000 tons thereafter.
The U.S. Environmental Protection Agency (EPA) allocates
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 (which began on January 1, 1995), 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 the allowances for use in later
years. By using a banking strategy, it is estimated that Phase
II (begins January 1, 2000) allowance requirements will be met
through the year 2004 by utilizing the allowances banked during
Phase I, together with the company's Phase II annual emissions
allowances. That 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 all of its
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 those extension reserve allowances.
Financial Review
Net Cash Provided by Operating Activities
In 1995 cash provided by operating activities increased by
$1 million, up less than 1% from 1994. Cash provided by net
income in 1995 was $9 million higher than in 1994, but this
increase was nearly offset by cash used for working capital
items.
Cash provided by operating activities in 1994 increased $38
million, up 9% from 1993. Higher net income in 1994 added $22
million and a reduction in cash used for working capital items
added $16 million to cash provided by operating activities.
Net Cash Used in Investing Activities
Cash used in investing activities decreased $56 million, or
26%, in 1995 and decreased $86 million, or 28%, in 1994. The
changes were primarily due to reductions in utility plant capital
expenditures.
Capital expenditures for the company's core electric and
natural gas businesses, including nuclear fuel and the allowance
for funds used during construction (AFDC), totaled $164 million
in 1995, $248 million in 1994 and $268 million in 1993. For 1995
and 1994 those expenditures were primarily for the extension of
service, necessary facility improvements and compliance with the
1990 Amendments and other environmental requirements. Most of
the expenditures in 1993 were for the extension of service and
for improvements at existing facilities. The company received $6
million, $24 million and $23 million from governmental and other
sources in 1995, 1994 and 1993 respectively, to partially offset
expenditures for compliance with the 1990 Amendments.
Approximately $5 million is expected to be received from
governmental and other sources in 1996 to partially offset such
expenditures.
Capital expenditures projected for 1996, 1997 and 1998 total
$215 million, $200 million and $168 million, respectively (see
Note 9). Those expenditures are expected to be financed entirely
with internally generated funds. The company forecasts that its
current reserve margin, coupled with more efficient use of energy
and purchases of NUG power, eliminates the need for additional
generating capacity until after the year 2007.
Information on the company's estimated sources and uses of
funds for the years 1996 through 1998 follows. The estimates are
subject to periodic review and revision. Actual capital
expenditures may change to accommodate additional regulatory
requirements and the company's continued focus on minimizing
capital expenditures.
1996 1997 1998 Total
(Millions)
Sources of funds
Internal funds $288 $295 $306 $889
Long-term financing - - - -
---- ---- ---- ----
Total $288 $295 $306 $889
==== ==== ==== ====
Uses of funds
Capital expenditures
Cash $211 $195 $163 $569
AFDC* 4 5 5 14
---- ---- ---- ----
Total capital
expenditures 215 200 168 583
Retirement of securities and
sinking fund obligations 129 73 53 255
Reduction of short-term debt (12) 40 120 148
Working capital, deferrals
and other (44) (18) (35) (97)
---- ---- ---- ----
Total $288 $295 $306 $889
==== ==== ==== ====
Percentage of capital
expenditures funded
from operations 154% 157% 203% 169%
*Allowance for funds used during construction.
Net Cash Used in Financing Activities
In 1995 cash used in financing activities increased $87
million, up 40% compared to 1994. The company issued
significantly less debt in 1995 than in 1994, since the amount of
refundings and redemptions was higher in 1994. Although the
amounts of debt redeemed and dividends paid were lower in 1995
than in 1994, more cash provided by operating activities was used
for those items in 1995.
Cash used in financing activities in 1994 increased $106
million, up 96% from 1993. That change 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's long-term goal is to maintain a common stock
dividend payout ratio of 60% to 65%. The current dividend is
slightly under that range. Future dividends will depend on many
factors, including the earnings impact of industry restructuring.
The company can give no assurance as to future dividend levels.
Since 1987 the company has reduced its debt from 62% to 45%
of total capital and has raised its common stock equity from 33%
to 48%, at December 31, 1995. The common stock equity ratio
improved in 1995 primarily as a result of retained earnings and
the redemption and repurchase of $54 million of first mortgage
bonds. In February 1996 the common stock equity ratio rose to
50% as a result of a preferred stock redemption and a first
mortgage bond redemption. The company is committed to improving
its financial strength and achieving an 'A' bond rating.
The company's financing activities during 1995 consisted of
two issuances of tax-exempt pollution control revenue bonds
totaling $37 million. The proceeds were used to redeem $37
million of higher coupon tax-exempt pollution control revenue
bonds. The company also redeemed $23 million and repurchased $31
million of 9 7/8% Series first mortgage bonds due February 2020.
The company reduced its embedded cost of long-term debt to
7% at the end of 1995, and has refinanced more than $1.6 billion
in long-term debt since the beginning of 1988. On January 1,
1996, the company redeemed, at a premium, $100 million of 8.95%
preferred stock through the issuance of commercial paper. The
embedded cost of preferred stock was reduced to 5.6% primarily as
a result of the redemption. As a result of those efforts, annual
interest expense and preferred stock dividends have been reduced
by over $70 million since the beginning of 1988. Unless interest
rates fall further it will be difficult to improve from those
levels; however, all opportunities will be pursued aggressively.
The company uses short-term, unsecured notes, usually
commercial paper, to finance certain refundings and for other
corporate purposes. There was $29 million and $152 million of
commercial paper outstanding at December 31, 1995 and 1994,
respectively, at weighted average interest rates of 6.1% and
5.8%, respectively.
The company also has a revolving credit agreement with
certain banks that provides for borrowing up to $200 million
until July 31, 1997. There were no amounts outstanding under
this agreement at December 31, 1995 and 1994.
Results of Operations
1995 1994
over over
1994 1993
1995 1994 1993 Change Change
(Thousands, except per share amounts)
Operating revenues $2,009,541 $1,898,855 $1,800,149 6% 5%
Operating income $337,363 $322,684 $300,656 5% 7%
Earnings available for
common stock $177,969 $168,698 $145,390 5% 16%
Average shares outstanding 71,503 71,254 69,990 -% 2%
Earnings per share $2.49 $2.37 $2.08 5% 14%
Earnings per share excluding
one-time charges $2.49 $2.49 $2.33 -% 7%
Dividends per share $1.40 $2.00 $2.18 (30%) (8%)
Earnings per Share
Earnings per share for 1995 were 12 cents higher than in
1994, an increase of 5%. In 1994, earnings per share increased
29 cents, 14% higher than 1993's earnings. However, certain one-
time charges that were recorded in 1994 and 1993 should be
excluded to better compare earnings per share. Those charges are
the 1993 production-cost penalty that lowered 1994 earnings by 12
cents per share and the corporate restructuring that reduced 1993
earnings by 25 cents per share (see Note 6). Without the one-
time charges there was no change in earnings per share comparing
1995 and 1994 and there was a 16 cent increase comparing 1994 and
1993. The earnings per share explanations that follow exclude
those one-time charges.
Higher operating income added six cents to earnings per
share in 1995. Higher electric and natural gas prices
contributed eight cents to this increase and higher profits on
wholesale electric sales added five cents. In addition, the
company's efforts to control operating costs helped increase
earnings by two cents per share. Those increases were partly
offset by a nine cent decrease in earnings per share because of
higher maintenance expenses, which includes storm-related costs.
In addition to that six cent increase, lower interest
charges in 1995, primarily due to the refinancing and retirement
of debt, contributed six cents to earnings per share. Those
increases were offset by an 11 cent charge to earnings per share
resulting from a decrease in other income and deductions, mostly
due to higher losses incurred by the company's diversified
operations.
In 1994 higher operating income increased earnings per share
by 18 cents. That increase resulted from a combination of
factors. Lower operating and maintenance expenses due to cost
controls and a reduction in the workforce increased earnings by
26 cents per share. Earnings per share also rose in 1994 because
lower electric retail sales in 1993, before the effective date of
the modified revenue decoupling mechanism (RDM), reduced 1993
earnings by nine cents per share. Those increases were partially
offset by a reduction in DSM rewards that lowered earnings per
share by 13 cents.
A decrease in other income and deductions, primarily due
to losses incurred by the company's diversified operations,
reduced 1994 earnings by five cents per share. Lower interest
charges in 1994, primarily due to the refinancing and retirement
of debt, added five cents to earnings per share, offsetting the
decrease.
Interest Expense
Interest expense (before the reduction for allowance for
borrowed funds used during construction) decreased $9 million in
1995 and decreased $6 million in 1994. The decreases in both
years were primarily due to the refinancing and retirement of
certain issues of long-term debt.
Dividends per Share
Dividends per share decreased 30% in 1995 compared to 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 and dividends remained at 35 cents per share throughout
1995. Dividends per share decreased 8% in 1994 compared to 1993,
because of the October 1994 dividend reduction.
Operating Results for the Electric Business Segment
1995 1994
over over
1994 1993
1995 1994 1993 Change Change
(Thousands)
Retail sales - kilowatt-
hours(kwh) 13,092,563 13,147,631 13,088,175 -% -%
Operating revenues $1,708,297 $1,600,075 $1,527,362 7% 5%
Operating expenses $1,407,686 $1,306,871 $1,250,000 8% 5%
Operating income $300,611 $293,204 $277,362 3% 6%
In 1995 electric retail sales decreased slightly compared to
1994 sales as a result of the sluggish economy in the company's
service territory. Although there were significant differences
in the weather during 1995 compared to 1994, the overall impact
on sales was minimal. Electric retail sales for 1994 were flat
compared to 1993 sales.
Operating Revenues: Electric operating revenues for 1995 were
$108 million higher than 1994 revenues. Revenues rose $87
million because of increases in electric prices, due to changes
in rates effective in August 1995 and 1994, primarily to
accommodate increased mandated purchases of NUG power. An
increase in sales of electricity to others added $9 million to
revenues. Electric revenues for 1994 were reduced by $13 million
because of the 1993 production-cost penalty that was recorded in
the second quarter of 1994.
The principal reason for the $73 million increase in 1994
electric operating revenues was the increases in electric prices
effective in September 1993 and August 1994 that added $69
million to revenues. The price increases were caused primarily
by an increase in mandated purchases of NUG power and by higher
federal taxes. The modified RDM increased revenues by $18
million since actual electric sales in 1994 were below the levels
forecasted in the company's rate agreement. Higher costs of NUG
power, which were billed to customers in part through the fuel
adjustment clause, boosted 1994 revenues by $16 million. An
increase in sales of electricity to others added $16 million to
1994 revenues due to an increase in interchange sales volume.
Those increases were partially offset by a $14 million decrease
in DSM rewards, a $15 million decrease in DSM lost revenues
recorded and the $13 million reduction in revenues from the 1993
production-cost penalty.
Operating Expenses: The $101 million increase in electric
operating expenses in 1995 is primarily attributable to an
increase of $76 million in electricity purchased, mostly due to
NUG purchases. Higher federal taxes, the result of higher pretax
book income, added $16 million to expenses. In addition,
maintenance expenses rose $10 million and include storm-related
costs.
Electric operating expenses increased by $57 million in 1994
principally because of an $80 million increase in electricity
purchased, primarily for NUG purchases. Federal income taxes
rose $17 million in 1994, the result of higher pretax book
income. Increased gross receipts 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 that were 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.
Operating Results for the Natural Gas Business Segment
1995 1994
over over
1994 1993
1995 1994 1993 Change Change
(Thousands)
Deliveries -
dekatherms (dth) 58,535 58,624 58,046 -% 1%
Operating revenues $301,244 $298,780 $272,787 1% 10%
Operating expenses $264,492 $269,300 $249,493 (2%) 8%
Operating income $36,752 $29,480 $23,294 25% 27%
Natural gas deliveries for 1995 were almost equal to 1994
deliveries. The sluggish economy in the company's service
territory continues to impact sales, which were below
expectations. There were significant differences in the weather
during 1995 compared to 1994, but the overall impact on sales for
the year was minimal. Natural gas deliveries for 1994 were 1%
higher than 1993 deliveries due to the addition of new customers,
including several large-volume customers.
Operating Revenues: In 1995 natural gas operating revenues
increased $2 million, compared to 1994 revenues, primarily as a
result of higher natural gas prices that added $3 million to
revenues. Changes in rates effective in August 1995 and 1994
were the primary reason for the higher natural gas prices.
The leading cause for the $26 million increase in 1994
natural gas operating revenues was higher costs of natural gas
(billed to customers) that added $16 million to revenues. In
addition, rate changes effective in September 1993 and August
1994 added $7 million to revenues. However, since the company
had a weather normalization mechanism, $1 million of revenues
attributable to colder weather was returned to customers in 1994.
Operating Expenses: The $5 million reduction in natural gas
operating expenses in 1995 is due to a combination of factors.
Natural gas purchased decreased $12 million mainly because of
lower commodity prices. That decrease was partially offset by
higher federal income taxes, primarily due to higher pretax book
income that added $3 million, and higher depreciation and
distribution operation expenses that each added $1 million to
operating expenses.
Natural gas operating expenses rose $20 million in 1994,
mainly due to a $20 million increase in natural gas purchased,
mostly because of higher commodity prices. Higher federal income
taxes, due to higher pretax book income, added $4 million to
operating expenses. Increased gross receipts and school taxes
added another $1 million to expenses. Depreciation expense rose
$2 million compared to 1993. Those increases were partially
offset by a $5 million decrease because of the restructuring
charge recorded in 1993 and a $1 million decrease in marketing
expenses due to improved operations.
Item 8. Financial statements and supplementary data
New York State Electric & Gas Corporation
Consolidated Balance Sheets
December 31 1995 1994
- -------------------------------------------------------------------------------
(Thousands)
Assets
Utility Plant, at Original Cost
Electric . . . . . . . . . . . . . . . . . . . . . . . $5,090,044 $4,916,960
Natural gas. . . . . . . . . . . . . . . . . . . . . . 445,256 414,929
Common . . . . . . . . . . . . . . . . . . . . . . . . 140,686 143,366
---------- ----------
. . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,675,986 5,475,255
Less accumulated depreciation. . . . . . . . . . . . . 1,791,625 1,642,653
---------- ----------
Net Utility Plant in Service. . . . . . . . . . . 3,884,361 3,832,602
Construction work in progress. . . . . . . . . . . . . 79,229 154,723
---------- ----------
Total Utility Plant . . . . . . . . . . . . . . . 3,963,590 3,987,325
Other Property and Investments, Net . . . . . . . . . . 99,633 103,920
Current Assets
Cash and cash equivalents. . . . . . . . . . . . . . . 11,433 22,322
Special deposits . . . . . . . . . . . . . . . . . . . 5,785 7,591
Accounts receivable, net . . . . . . . . . . . . . . . 195,834 155,665
Fuel, at average cost. . . . . . . . . . . . . . . . . 33,682 49,934
Materials and supplies, at average cost. . . . . . . . 44,809 47,843
Prepayments. . . . . . . . . . . . . . . . . . . . . . 31,371 30,441
Accumulated deferred federal income
tax benefits, net . . . . . . . . . . . . . . . . . 7,594 11,457
---------- ----------
Total Current Assets. . . . . . . . . . . . . . . 330,508 325,253
Regulatory and Other Assets
Regulatory assets
Unfunded future federal income taxes. . . . . . . . 323,446 363,151
Unamortized debt expense. . . . . . . . . . . . . . 85,023 88,559
Demand-side management program costs. . . . . . . . 74,824 72,849
Other regulatory assets . . . . . . . . . . . . . . 206,736 254,446
---------- ---------
Total regulatory assets. . . . . . . . . . . . . . . . 690,029 779,005
Other assets . . . . . . . . . . . . . . . . . . . . . 30,571 35,182
---------- ----------
Total Regulatory and Other Assets . . . . . . . . 720,600 814,187
---------- ----------
Total Assets. . . . . . . . . . . . . . . . . . . $5,114,331 $5,230,685
========== ==========
The notes on pages 53 through 73 are an integral part of the financial
statements.
New York State Electric & Gas Corporation
Consolidated Balance Sheets
December 31 1995 1994
- ------------------------------------------------------------------------------
(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 shares issued and
outstanding at December 31, 1995 and 1994) . . . $476,686 $476,686
Capital in excess of par value. . . . . . . . . . 842,442 841,624
Retained earnings . . . . . . . . . . . . . . . . 424,412 346,547
---------- ----------
Total common stock equity. . . . . . . . . . . . . . . 1,743,540 1,664,857
Preferred stock redeemable solely at the option of
the company . . . . . . . . . . . . . . . . . . . . 140,500 140,500
Preferred stock subject to mandatory redemption
requirements. . . . . . . . . . . . . . . . . . . . 25,000 125,000
Long-term debt . . . . . . . . . . . . . . . . . . . . 1,581,448 1,651,081
---------- ----------
Total Capitalization. . . . . . . . . . . . . . . 3,490,488 3,581,438
Current Liabilities
Current portion of long-term debt. . . . . . . . . . . 37,003 36,231
Current portion of preferred stock . . . . . . . . . . 100,000 -
Commercial paper . . . . . . . . . . . . . . . . . . . 28,620 151,900
Accounts payable and accrued liabilities . . . . . . . 117,637 107,356
Interest accrued . . . . . . . . . . . . . . . . . . . 24,093 25,132
Taxes accrued. . . . . . . . . . . . . . . . . . . . . 22,231 12,414
Other. . . . . . . . . . . . . . . . . . . . . . . . . 68,027 82,547
---------- ----------
Total Current Liabilities . . . . . . . . . . . . 397,611 415,580
Regulatory and Other Liabilities
Regulatory liabilities:
Deferred income taxes - unfunded future federal
income taxes. . . . . . . . . . . . . . . . . . . . 128,643 143,285
Deferred income taxes . . . . . . . . . . . . . . . . 108,605 114,111
Other regulatory liabilities. . . . . . . . . . . . . 56,729 79,479
---------- ----------
Total regulatory liabilities . . . . . . . . . . . . . 293,977 336,875
Other liabilities:
Accumulated deferred investment tax credit. . . . . . 126,032 132,440
Deferred income taxes - other . . . . . . . . . . . . 617,452 580,939
Other postretirement benefits . . . . . . . . . . . . 75,683 54,994
Liability for environmental restoration . . . . . . . 31,800 33,600
Other . . . . . . . . . . . . . . . . . . . . . . . . 81,288 94,819
---------- ----------
Total other liabilities . . . . . . . . . . . . . . . 932,255 896,792
Total Regulatory and Other Liabilities. . . . . . 1,226,232 1,233,667
Commitments and Contingencies . . . . . . . . . . . . . - -
---------- ----------
Total Capitalization and Liabilities. . . . . . . $5,114,331 $5,230,685
========== ==========
The notes on pages 53 through 73 are an integral part of the financial
statements.
New York State Electric & Gas Corporation
Consolidated Statements of Income
Year Ended December 31 1995 1994 1993
- ----------------------------------------------------------------------------
(Thousands, except per share amounts)
Operating Revenues
Electric . . . . . . . . . . . . . . . . $1,708,297 $1,600,075 $1,527,362
Natural gas. . . . . . . . . . . . . . . 301,244 298,780 272,787
---------- ---------- ----------
Total Operating Revenues . . . . . . . 2,009,541 1,898,855 1,800,149
---------- ---------- ----------
Operating Expenses
Fuel used in electric generation . . . . 229,759 231,648 245,283
Electricity purchased. . . . . . . . . . 318,440 242,352 161,967
Natural gas purchased. . . . . . . . . . 149,789 161,627 141,635
Other operating expenses . . . . . . . . 326,922 328,961 349,177
Restructuring expenses . . . . . . . . . - - 26,000
Maintenance. . . . . . . . . . . . . . . 116,807 106,637 111,757
Depreciation and amortization. . . . . . 184,770 178,326 164,568
Federal income taxes . . . . . . . . . . 134,781 115,891 94,144
Other taxes . . . . . . . . . . . . . . 210,910 210,729 204,962
---------- ---------- ----------
Total Operating Expenses. . . . . . . . . 1,672,178 1,576,171 1,499,493
---------- ---------- ----------
Operating Income. . . . . . . . . . . . . 337,363 322,684 300,656
Other Income and Deductions . . . . . . . (11,106) 1,053 6,471
---------- ---------- ----------
Income Before Interest Charges. . . . . . 326,257 323,737 307,127
---------- ---------- ----------
Interest Charges
Interest on long-term debt . . . . . . . 115,687 126,083 134,330
Other interest . . . . . . . . . . . . . 15,232 13,642 11,120
Allowance for borrowed funds
used during construction. . . . . . . . (1,352) (3,633) (4,351)
---------- ---------- ----------
Interest Charges, Net. . . . . . . . . 129,567 136,092 141,099
---------- ---------- ----------
Net Income. . . . . . . . . . . . . . . . 196,690 187,645 166,028
Preferred Stock Dividends . . . . . . . . 18,721 18,947 20,638
---------- ---------- ----------
Earnings Available for Common Stock . . . $177,969 $168,698 $145,390
========== ========== ==========
Earnings Per Share. . . . . . . . . . . . $2.49 $2.37 $2.08
Average Shares Outstanding. . . . . . . . 71,503 71,254 69,990
The notes on pages 53 through 73 are an integral part of the
financial statements.
New York State Electric & Gas Corporation
Consolidated Statements of Cash Flows
Year Ended December 31 1995 1994 1993
- ------------------------------------------------------------------------------
(Thousands)
Operating Activities
Net income . . . . . . . . . . . . . . . . . . . . $196,690 $187,645 $166,028
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization. . . . . . . . . . 184,770 178,326 164,568
Deferred fuel and purchased gas. . . . . . . . . 15,022 (1,944) (10,671)
Federal income taxes and investment tax credits
deferred, net. . . . . . . . . . . . . . . . . 52,362 37,910 51,098
Restructuring expenses . . . . . . . . . . . . . - - 26,000
Changes in current operating assets and liabilities:
Accounts receivable excluding accounts
receivable sold. . . . . . . . . . . . . . . . (40,169) 25,921 (23,703)
Accounts receivable sold . . . . . . . . . . . . - - 13,800
Prepayments. . . . . . . . . . . . . . . . . . . (930) (349) 7,805
Inventory. . . . . . . . . . . . . . . . . . . . 19,286 5,924 16,013
Accounts payable and accrued liabilities . . . . 10,281 (4,125) 15,485
Taxes accrued. . . . . . . . . . . . . . . . . . 9,817 (6,377) 4,671
Interest accrued . . . . . . . . . . . . . . . . (1,039) (6,216) (6,342)
Other, net . . . . . . . . . . . . . . . . . . . . 5,741 33,663 (12,562)
-------- -------- --------
Net Cash Provided by Operating Activities. . . . 451,831 450,378 412,190
-------- -------- --------
Investing Activities
Utility plant capital expenditures . . . . . . . . (163,401)(246,536)(265,109)
Proceeds received from governmental and
other sources. . . . . . . . . . . . . . . . . . 5,621 23,915 22,808
Expenditures for other property and investments. . (3,145) (34,482) (16,975)
Funds restricted for capital expenditures. . . . . 1,324 41,113 (42,437)
-------- -------- --------
Net Cash Used in Investing Activities. . . . . . (159,601)(215,990)(301,713)
-------- -------- --------
Financing Activities
Issuance of pollution control notes and
first mortgage bonds . . . . . . . . . . . . . . 37,000 275,000 217,362
Revolving credit agreement, net. . . . . . . . . . - (50,000) 50,000
Sale of common stock . . . . . . . . . . . . . . . - 23,386 38,334
Sale of preferred stock. . . . . . . . . . . . . . - - 97,762
Repayment of pollution control notes,
first mortgage bonds and preferred
stock, including premiums. . . . . . . . . . . . (92,395)(497,450)(326,091)
Changes in funds set aside for preferred stock
and first mortgage bond repayments . . . . . . . - 95,000 (8,904)
Long-term notes, net . . . . . . . . . . . . . . . (5,504) (2,290) 8,393
Commercial paper, net. . . . . . . . . . . . . . . (123,280) 101,700 (13,900)
Dividends on common and preferred stock. . . . . . (118,940)(161,676)(173,137)
-------- -------- --------
Net Cash Used in Financing Activities. . . . . . (303,119)(216,330)(110,181)
-------- -------- --------
Net(Decrease)Increase in Cash and Cash Equivalents. (10,889) 18,058 296
Cash and Cash Equivalents, Beginning of Year. . . . 22,322 4,264 3,968
-------- -------- --------
Cash and Cash Equivalents, End of Year. . . . . . . $11,433 $22,322 $4,264
======== ======== ========
The notes on pages 53 through 73 are an integral part of the
financial statements.
New York State Electric & Gas Corporat ion
Consolidated Statements of Change in C ommon Stock Equity
(Thousands, except shares and per shar e amounts)
Common Stock Capital
$6.66 2/3 Par Value in Excess Retained
Shares Amount of Par Value Earnings Total
Balance, January 1, 1993 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 30,699 38,410
Amortization of capital stock
issue expense (2,261) (2,261)
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 17,450 23,496
Amortization of capital stock
issue expense (769) (769)
Balance, December 31, 1994 71,502,827 476,686 841,624 346,547 1,664,857
Net income 196,690 196,690
Cash dividends declared:
Preferred stock (at serial rates)
Redeemable - optional (8,196) (8,196)
- mandatory (10,525) (10,525)
Common stock ($1.40 per share) (100,104) (100,104)
Amortization of capital stock
issue expense 818 818
Balance, December 31, 1995 71,502,827 $476,686 $842,442 $424,412 $1,743,540
The notes on pages 53 through 73 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).
Estimates
Preparation of the consolidated financial statements in
conformity with generally accepted accounting principles requires
management to make estimates and assumptions that affect the
reported amounts of assets and liabilities at the date of the
financial statements and the reported amounts of revenues and
expenses during the reporting period. Actual results could
differ from those estimates.
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%, 3.5% and 3.4%, of average depreciable
property for 1995, 1994 and 1993, respectively. Amortization
expense includes the amortization of certain deferred charges
authorized by the Public Service Commission of the State of New
York (PSC).
Accounts receivable
The company has an agreement that expires in November 2000
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, 1995 and 1994, 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 $10 million, $7 million and $6 million in 1995,
1994 and 1993, respectively. Accounts receivable on the
consolidated balance sheets is also shown net of an allowance for
doubtful accounts of $7 million at December 31, 1995 and 1994.
Bad debt expense was $18 million, $20 million and $15 million in
1995, 1994 and 1993, respectively.
Income taxes
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 in accordance with Statement of Financial
Accounting Standards No. 109 (Statement 109), Accounting for
Income Taxes. Investment tax credits, which reduce federal
income taxes currently payable, are deferred and amortized over
the estimated lives of the applicable property.
Regulatory assets and liabilities
Pursuant to Statement of Financial Accounting Standards No.
71 (Statement 71), Accounting for the Effects of Certain Types of
Regulation, the company capitalizes, as regulatory assets,
incurred costs that are expected to be recovered in future
electric and natural gas rates. The company also records as
regulatory liabilities, obligations to customers to refund
previously collected revenue or to spend revenue collected from
customers on future costs.
Unfunded future federal income taxes and deferred income
taxes are amortized as the related temporary differences reverse.
Unamortized debt expense is amortized over the lives of the
related debt issues. The other regulatory assets and other
regulatory liabilities are amortized over various periods as
provided by the company's rate settlement agreements. The
company is earning a return on all regulatory assets for which
the company has spent funds.
The company's regulatory assets and liabilities consisted of
the following:
December 31 1995 1995 1994 1994
Liabil- Liabil-
Assets ities Assets ities
(Thousands)
Unfunded future federal
income taxes $323,446 $128,643 $363,151 $143,285
Deferred income taxes - 108,605 - 114,111
Unamortized debt expense 85,023 - 88,559 -
Demand-side management
program costs 74,824 - 72,849 -
Non-utility generator (NUG)
termination agreements 43,847 - 44,079 -
Environmental remediation costs 31,763 - 32,801 -
Other postretirement benefits 21,179 - 10,383 -
Other 109,947 56,729 167,183 79,479
-------- -------- -------- --------
Total $690,029 $293,977 $779,005 $336,875
======== ======== ======== ========
If the company could no longer meet the criteria of
Statement 71 for all or a part of its business, the company would
have to record as expense or revenue all or a portion of its
regulatory assets and liabilities.
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. Those investments are included in cash and
cash equivalents on the consolidated balance sheets.
Total income taxes paid were $55 million, $69 million and
$27 million for the years ended December 31, 1995, 1994 and 1993,
respectively.
Interest paid, net of amounts capitalized, was $118 million,
$132 million and $138 million for the years ended December 31,
1995, 1994 and 1993, respectively.
Reclassifications
Certain amounts have been reclassified on the consolidated
financial statements to conform with the 1995 presentation.
2 Income Taxes
Year ended December 31 1995 1994 1993
(Thousands)
Charged to operations
Current $94,896 $88,623 $34,989
Deferred, net
Accelerated depreciation 49,133 51,736 49,580
Unbilled revenues 4,192 (3,913) 5,073
Revenue decoupling mechanism (4,608) 6,870 -
Alternative minimum tax
(AMT) credit 3,479 (4,744) (3,194)
Demand-side management 21 (9,048) 13,479
NUG termination agreement (330) (1,313) 6,208
Nine Mile No. 2 litigation
proceeds 1,269 (520) 4,756
Restructuring expenses - - (6,965)
Transmission facility
agreement 3,482 (2,719) (7,778)
Miscellaneous (16,725) (9,049) (7,646)
Investment tax credit (ITC) (28) (32) 5,642
-------- -------- --------
134,781 115,891 94,144
Included in other income
Amortization of deferred ITC (6,380) (6,006) (8,892)
Miscellaneous (12,537) (7,424) 498
-------- -------- --------
Total $115,864 $102,461 $85,750
======== ======== ========
The company's effective tax rate differed from the statutory rate
of 35% due to the following:
Year ended December 31 1995 1994 1993
(Thousands)
Tax expense at statutory rate $109,396 $101,537 $88,684
Depreciation not normalized 19,774 18,552 16,984
ITC amortization (6,186) (6,006) (8,892)
Revenue Reconciliation Act
of 1993, net 1,455 (3,736) (631)
Research & Development
credit (5,547) (1,352) (5,139)
Cost of removal (3,772) (5,462) (4,921)
Other, net 744 (1,072) (335)
-------- -------- --------
Total $115,864 $102,461 $85,750
======== ======== ========
The company's deferred tax assets and liabilities consist of the
following:
December 31 1995 1994
(Thousands)
Current Deferred Taxes $(7,594) $(11,457)
--------- -------
Noncurrent Deferred Taxes
Depreciation $756,386 $740,961
Unfunded future federal income
taxes 128,643 143,285
Deferred ITC (net of Statement 109) 80,868 86,205
AMT credit (380) (16,716)
Other 12,363 14,829
--------- ---------
Total noncurrent deferred taxes $977,880 $968,564
--------- ---------
Total deferred taxes $970,286 $957,107
Valuation allowance 2,852 2,211
--------- ---------
Net deferred tax liabilities $973,138 $959,318
========= =========
The company has recorded unfunded future federal income
taxes and a corresponding receivable from customers of
approximately $323 million and $363 million as of December 31,
1995 and 1994, 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 less than $1 million of AMT credits that do
not expire.
3 Long-Term Debt
At December 31, 1995 and 1994, long-term debt was (Thousands):
First mortgage bonds Amount
Series Due 1995 1994
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
6 7/8% Dec. 1, 2006 - 25,000
8 5/8% Nov. 1, 2007 37,000 37,000
9 7/8% Feb. 1, 2020 46,000 100,000
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 963,000 1,054,000
---------- ----------
Pollution control notes
Interest Maturity Interest Rate Letter of Credit
Rate Date Adjustment Date Expiration Date
6.0 % June 1, 2006 - - 12,000 -
5.90% Dec. 1, 2006 - - 25,000 -
4.65%(1) Mar. 15, 2015 Mar. 15, 1996 Mar. 31, 1997 60,000 60,000
3.85%(1) Oct. 15, 2015 Oct. 15, 1996 Oct. 31, 1997 30,000 30,000
3.65%(1) Dec. 1, 2015 Dec. 1, 1996 Dec. 15, 1997 42,000 42,000
6.15% July 1, 2026 - - 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, 1997 37,500 37,500
Var.%(2) June 1, 2029 Various June 15, 1997 63,500 63,500
Var.%(2) Oct. 1, 2029 Various Oct. 25, 1997 74,000 74,000
6.05% Apr. 1, 2034 - - 100,000 100,000
---------- ----------
Total pollution control notes 613,000 576,000
---------- ----------
Long-term notes due December 31, 1998 31,000 34,000
Various long-term notes 5,501 11,806
Obligations under capital leases 14,799 21,423
Unamortized premium and discount on debt, net (8,849) (9,917)
---------- ----------
1,618,451 1,687,312
Less: debt due within one year - included
in current liabilities 37,003 36,231
---------- ----------
Total $1,581,448 $1,651,081
========== ==========
At December 31, 1995, long-term debt and capital lease
payments that will become due during the next five years are:
1996 1997 1998 1999 2000
(Thousands)
$37,003 $53,887 $62,314 $774 $322
The company's mortgage provides for a sinking and
improvement fund. This provision requires the company to make an
annual cash deposit 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 the requirement by depositing $23 million in cash in
both 1995 and 1996. The funds were used to redeem, at par, $23
million of 9 7/8% Series first mortgage bonds, due February 2020.
The company's first mortgage bond indenture constitutes a
direct first mortgage lien on substantially all utility plant.
(1) Adjustable rate pollution control notes totaling the
principal amount of $132 million 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, 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.
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 totaling the principal
amount of $175 million 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.
The 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 daily rate, a weekly rate, a
commercial paper 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. At December 31,
1995, the multi-mode pollution control notes bore interest at the
daily rate. The weighted average interest rate for all three
series was 3.7%, excluding letter of credit fees, for the year
ended December 31, 1995.
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, 1995 and 1994, serial cumulative preferred stock
was:
Shares
Par Value Authorized
Per Redeemable and Amount
Series Share Prior to Per Share Outstanding(1) 1995 1994
(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
7.40% (2) 25 12/1/98 26.85 1,000,000 25,000 25,000
Thereafter 25.00
Adjustable
Rate (3) 25 12/1/98 27.50 2,000,000 50,000 50,000
Thereafter 25.00
-------- --------
Total $140,500 $140,500
======== ========
Subject to mandatory redemption requirements:
6.30% (4) 100 1/1/97 104.41 250,000 $25,000 $25,000
8.95% (5) 25 1/1/97 26.49 4,000,000 100,000 100,000
-------- --------
Total $125,000 $125,000
======== ========
At December 31, 1995, preferred stock redemptions and annual
redeemable preferred stock sinking fund requirements for the next
five years are $100 million in 1996 and zero in the years 1997
through 2000.
(1) At December 31, 1995, and after giving effect to the
redemption referred to in (5) below, there were 1,550,000 shares
of $100 par value preferred stock, 7,800,000 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 this Series, for April 1, 1996, is at an
annual rate of 5.03% 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 $104.41 per share
prior to January 1, 1997. The $104.41 price will be reduced
annually by 63 cents for the years ending 1997 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) Redeemed January 1, 1996.
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 (48% at December 31,
1995) 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 $424 million and $347 million as of December 31,
1995 and 1994, respectively.
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 .10% to .25%
depending upon the ratings of the company's first mortgage bonds.
The commitment fee was .125% at December 31, 1995 and .1875% at
December 31, 1994 and 1993.
The revolving credit agreement does not require compensating
balances. The company did not have any outstanding loans under
the revolving credit agreement at December 31, 1995 or 1994.
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
commercial paper balances at December 31, 1995, 1994 and 1993
were 6.1%, 5.8% and 3.5%, respectively.
6 Restructuring
In the fourth quarter of 1993 the company recorded a $26
million charge for a corporate restructuring that reorganized the
way the company delivers services to its electric and natural gas
customers beginning in March 1994. As part of the restructuring,
384 employees accepted a voluntary early retirement program and
another 258 employees were involuntarily severed for a total
workforce reduction of 642. The $26 million restructuring
charge, which included $20 million for the early retirement
program, reduced 1993 earnings available for common stock by
approximately $17 million or 25 cents per share.
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 during 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 included the following components:
Year ended December 31 1995 1994 1993
(Thousands)
Service cost: Benefits
earned during the year $16,391 $17,637 $17,688
Interest cost on projected
benefit obligation 45,400 43,328 40,710
Actual return on plan assets (185,816) (17,409) (77,129)
Net amortization and deferral 111,209 (48,824) 12,989
--------- --------- ---------
Net pension (benefit) $(12,816) $(5,268) $(5,742)
========= ========= =========
The funded status of the plan was:
December 31 1995 1994
(Thousands)
Actuarial present value of accumulated
benefit obligation:
Vested $450,857 $410,732
Nonvested 53,837 38,176
-------- --------
Total $504,694 $448,908
======== ========
Fair value of plan assets $(888,190) $(733,661)
Actuarial present value of
projected benefit obligation (PBO) 661,138 597,398
-------- --------
Plan assets in excess of PBO (227,052) (136,263)
Unrecognized net transition asset 59,136 66,374
Unrecognized net gain 178,927 92,851
Unrecognized prior service cost (9,931) (9,066)
-------- --------
Net pension liability $1,080 $13,896
======== ========
Assumptions used to determine
actuarial valuations:
Discount rate used to determine PBO 7.0% 7.75%
Rate of compensation increase
used to determine PBO 4.75% 5.5%
Long-term rate of return on plan
assets for net pension benefit 8.0% 8.0%
Plan assets primarily consist of domestic and international
equity securities; U.S. agency, corporate and Treasury bonds; and
cash equivalents.
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. The postretirement benefit plans
were unfunded as of December 31, 1995 and 1994.
In January 1993 the company adopted Statement of Financial
Accounting Standards No. 106 (Statement 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 $207 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 Statement 106
for accounting and ratemaking purposes, and complies with
generally accepted accounting principles.
The net periodic postretirement benefits cost other than
pensions recognized on the income statements for 1995, 1994 and
1993 (below) represent the portion of Statement 106 costs that
the company has been allowed to collect from its customers. The
company has deferred $21 million and $10 million of Statement 106
costs as of December 31, 1995 and 1994, respectively. The
company expects to recover any deferred Statement 106 amounts by
the year 2000.
Net postretirement benefits cost other than pensions
included the following components:
Year ended December 31 1995 1994 1993
(Thousands)
Service cost: Benefits accumulated
during the year $5,412 $7,050 $6,888
Interest cost on accumulated
postretirement benefit obligation 15,228 15,903 16,304
Amortization of transition obligation
over 20 years 10,330 10,330 10,330
Amortization of (gain) loss (4,575) 2 -
Deferral for future recovery (7,742) (18,757) (22,095)
------- ------- -------
Net periodic postretirement
benefits cost $18,653 $14,528 $11,427
======= ======= =======
The status of the plans for postretirement benefits other
than pensions, as reflected in the company's consolidated balance
sheets, was as follows:
December 31 1995 1994
(Thousands)
Accumulated postretirement benefit
obligation (APBO):
Retired employees $114,383 $112,311
Fully eligible active plan
participants 15,214 7,774
Other active plan employees 106,689 92,464
-------- --------
Total APBO 236,286 212,549
Less unrecognized transition
obligation 175,608 185,937
Less unrecognized net gain (15,005) (28,382)
-------- --------
Accrued postretirement liability $75,683 $54,994
======== ========
A 10% annual rate of increase in the per capita costs of
covered health care benefits was assumed for 1996, 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, 1996, by $39 million and increase the aggregate
of the service cost and interest cost components of the net
postretirement benefits cost for 1995 by $4 million. Discount
rates of 7% and 7.75% were used to determine the APBO in 1995 and
1994, respectively.
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
206,000 kilowatts. The company's net utility plant investment,
excluding nuclear fuel, was approximately $625 million and $638
million, at December 31, 1995 and 1994, respectively. The
accumulated provision for depreciation was approximately $129
million and $120 million, at December 31, 1995 and 1994,
respectively. The company's share of operating expenses is
included in the consolidated statements of income.
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 $76 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 $14 million
per incident. The $76 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 has procured property insurance for NMP2
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
$3 million.
Nuclear plant decommissioning costs
In December 1995 Niagara Mohawk advised the company that a
new decommissioning study for NMP2 (study) had been completed.
The study's estimate of the cost to decommission NMP2 is
significantly higher than previous estimates, primarily due to
the inclusion of additional categories of costs such as fuel dry
storage and property taxes. Based on the results of the study,
the company's 18% share of the cost to decommission NMP2 is $145
million in 1996 dollars ($422 million in 2026 when NMP2's
operating license will expire). The estimated annual
contribution needed to cover the company's share of costs as
outlined in the study is approximately $4 million.
The company's estimated liability for decommissioning NMP2
using the Nuclear Regulatory Commission's (NRC) minimum funding
requirement is approximately $78 million in 1996 dollars. The
company's electric rates currently include an annual allowance
for decommissioning of $2 million which approximates the NRC's
minimum funding requirement. Decommissioning costs are charged
to depreciation and amortization expense and are recovered over
the expected life of the plant. The company expects to use the
new study in the future as a basis for increasing the amount
recoverable in rates for decommissioning and 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 and to comply with
NRC funding regulations. The balance in the fund, including
reinvested earnings, was approximately $9 million and $7 million
at December 31, 1995 and 1994, respectively. Those amounts are
included on the consolidated balance sheets in other property and
investments, net. The related liability for decommissioning is
included in other liabilities - other. At December 31, 1995, the
external trust fund investments were classified as available-
for-sale, and their carrying value approximated fair value.
In 1996 the Financial Accounting Standards Board is expected
to issue an exposure draft, Accounting for Liabilities Related to
Closure and Removal of Long-Lived Assets. The exposure draft is
expected to require companies to fully recognize the estimated
decommissioning costs based on discounted cash flows of future
liabilities. Using the new study, the estimated liability that
the company would have to recognize on its balance sheet to
comply with the expected exposure draft guidelines is
approximately $70 million.
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 944,000 kilowatts and its net
utility plant investment was approximately $276 million and $265
million at December 31, 1995 and 1994, respectively. The
accumulated provision for depreciation was approximately
$168 million and $153 million, at December 31, 1995 and 1994,
respectively. The company's share of operating expenses is
included in the consolidated statements of income.
9 Commitments
Capital expenditures
The company has substantial commitments in connection with
its capital expenditure program and estimates that expenditures
for 1996, 1997 and 1998 will approximate $215 million, $200
million and $168 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 minimizing
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 $187 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 $115 million had been incurred as of December
31, 1995. The cost to comply with the 1990 Amendments could be
significantly higher as a result of proposed U.S. Environmental
Protection Agency (EPA) regulations regarding nitrogen oxide
emissions. In addition, as a result of solid waste disposal
legislation and regulations in Pennsylvania, the company will
incur approximately $24 million, on a present value basis, of
additional costs over the next 30 years at the Homer City
Generating Station. The majority of those costs will be incurred
to install synthetic lining at the present ash disposal area.
Non-utility generator power purchase contracts
During 1995, 1994 and 1993 the company expensed
approximately $284 million, $214 million and $138 million,
respectively,for NUG power, including termination costs. The
company estimates that NUG power purchases, excluding termination
costs, will total $324 million in 1996, $333 million in 1997 and
$345 million in 1998.
10 Environmental Liability
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 the sites are
also included on the National Priorities list.
Any liability may be joint and several for certain of those
sites. The company has recorded a liability of $1 million
related to six of the nine sites, which is reflected in the
company's consolidated balance sheets at December 31, 1995.
However, the company has notified the EPA and the NYSDEC, as
appropriate, that it has no responsibility at two of the six
sites. The ultimate cost to remediate the sites may be
significantly more than the estimated 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. For two of the three remaining sites, the company
believes it has no responsibility and has notified the EPA and
the NYSDEC, as appropriate. The company has already incurred
expenditures related to the remediation at the one remaining
site.
A regulatory asset of $2 million has also been recorded, of
which $1 million relates to costs that have already been
incurred. Since the PSC has allowed the company to recover in
rates remediation costs for certain of the sites, there is a
reasonable basis to conclude that the company will be permitted
to recover in rates any remediation costs that it may incur for
the nine sites.
The estimated liability of $1 million was derived by
multiplying the total estimated cost to clean up a particular
site by the related company contribution factor. The estimated
liability is not discounted and does not include any unasserted
claims. 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, the estimate was
based on 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 the cleanup costs.
However, the company is unable to predict the amount of insurance
recoveries, if any, that it may obtain.
The company has liability at eight inactive gas
manufacturing sites listed in the New York State Registry. In
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 company has a program to investigate and perform
necessary remediation at its known inactive gas manufacturing
sites. Expenditures through the year 2009 are estimated at $31
million, including the impact of the Order on Consent. That
estimate was determined by using the company's experience and
knowledge related to the sites as a result of the investigation
and remediation that the company has performed to date. It could
change materially based on facts and circumstances derived from
site investigations, changes in required remedial action, changes
in technology relating to remedial alternatives and changes in
presently enacted laws and regulations. The liability to
investigate and perform remediation, as necessary, at the known
inactive gas manufacturing sites, is reflected in the company's
consolidated balance sheets at December 31, 1995 and 1994 in the
amounts of $31 million and $33 million, respectively. The
company also has recorded a corresponding regulatory 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 company has notified its former and current insurance
carriers that it seeks to recover from them certain of the
cleanup costs. However, the company is unable to predict the
amount of insurance recoveries, if any, that it may obtain.
11 Diversified Operations
In April 1992 the PSC issued an order allowing the company
to invest up to 5% of its consolidated capitalization
(approximately $175 million at December 31, 1995) 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 and XENERGY, Inc.
As of December 31, 1995 and 1994, the company had invested
approximately $54 million and $47 million, respectively, in NGE
to finance its diversified investments. The majority of the
investment is included in other property and investments, net on
the consolidated balance sheets. NGE's total liabilities and
capitalization at December 31, 1995 and 1994 was approximately
$48 million and $52 million, respectively. For the years ended
December 31, 1995, 1994 and 1993, NGE incurred net losses of $12
million, $6 million and $1 million, respectively, which are
included in other income and deductions on the consolidated
statements of income.
12 Fair Value of Financial Instruments
Certain of the company's financial instruments had carrying
amounts and estimated fair values (based on the quoted market
prices for the same or similar issues of the same remaining
maturities) as follows:
December 31 1995 1995 1994 1994
Carrying Estimated Carrying Estimated
Amount Fair Value Amount Fair Value
(Thousands)
Preferred stock subject
to mandatory redemption
requirements $125,000 $130,085 $125,000 $127,875
First mortgage bonds $954,151 $1,025,696 $1,044,083 $1,010,239
Pollution control notes $613,000 $617,446 $576,000 $484,005
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, commercial
paper and interest accrued.
Special deposits include restricted funds that are set aside
for preferred stock and long-term debt redemptions, and 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).
13 Industry Segment Information
Certain information pertaining to the electric and natural
gas operations of the company follows:
1995 1995 1994 1994 1993 1993
Natural Natural Natural
Electric Gas Electric Gas Electric Gas
(Thousands)
Operating
Revenues $1,708,297 $301,244 $1,600,075 $298,780 $1,527,362 $272,787
Income before
income taxes $421,328 $50,816 $397,747 $40,828 $364,406 $30,394
Depreciation and
amortization $172,831 $11,939 $167,484 $10,842 $155,231 $9,337
Capital
expenditures $113,539 $45,142 $183,910 $40,396 $208,576 $36,453
Identifiable
assets* $4,525,541 $493,537 $4,631,511 $486,075 $4,627,905 $458,596
* Assets used in electric, natural gas and unregulated operations not
included above were $95,253, $113,099 and $201,457 at December 31, 1995, 1994
and 1993, respectively. They consist primarily of cash and cash equivalents,
special deposits, prepayments and subsidiaries' assets.
14 Quarterly Financial Information (Unaudited)
Quarter ended March 31 June 30 Sept.30 Dec. 31
(Thousands, except per share amounts)
1995
Operating revenues $571,910 $439,916 $464,694 $533,021
Operating income $110,756 $60,893 $76,600 $89,114
Net income $75,584 $24,630 $43,503 $52,973
Earnings available
for common stock $70,825 $19,914 $38,878 $48,352
Earnings per share $.99 $.28 $.54 $.68
Dividends per share $.35 $.35 $.35 $.35
Average shares outstanding 71,503 71,503 71,503 71,503
Common stock price*
High $21.75 $24.00 $26.75 $26.38
Low $19.00 $21.25 $22.50 $24.75
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
(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.
* The company's common stock is listed on the New York Stock Exchange. The
number of shareholders of record at December 31, 1995, was 50,576.
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 financial statement schedule based on our audits.
We conducted our audits in accordance with generally accepted
accounting 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, 1995 and 1994, and the
consolidated results of their operations and their cash flows for
each of the three years in the period ended December 31, 1995, 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 26, 1996
NEW YORK STATE ELECTRIC & GAS CORPORATION
SCHEDULE II - Consolidated Valuation and Qualifying Accounts
(Thousands of Dollars)
Years Ended December 31, 1995, 1994 and 1993
Beginning End
Classification of Year Additions Write-offs (a) Adjustments of Year (b)
1995
Allowance for Doubtful
Accounts - Accounts
Receivable $7,198 $ 17,891 $(18,304) $ - $6,785
Deferred Tax Asset
Valuation Allowance $2,211 $ 641 $ - $ - $2,852
1994
Allowance for Doubtful
Accounts - Accounts
Receivable $4,000 $19,594 $(16,894) $498 (c) $7,198
Deferred Tax Asset
Valuation Allowance $ 663 $ 1,548 $ - $ - $2,211
1993
Allowance for Doubtful
Accounts - Accounts
Receivable $1,900 $15,306 $(13,206) $ - $4,000
Deferred Tax Asset
Valuation Allowance $1,800 $ - $ (1,137) $ - $ 663
(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 "Section 16 Compliance" in the Company's Proxy
Statement dated March 29, 1996. The information regarding executive officers
is on pages 24-25 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 29, 1996.
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 29, 1996.
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 29, 1996.
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, 1995 and 1994
b) For the three years ended December 31, 1995:
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, 1995:
II. Consolidated Valuation and Qualifying Accounts
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) 10-15 - Retirement Plan for Directors Amendment No. 2.
(A) 10-29 - Supplemental Executive Retirement Plan Amendment
No. 11.
(A) 10-36 - Annual Executive Incentive Plan.
(A) 10-42 - Performance Share Plan Amendment No. 5.
(A) 10-43 - Long-Term Executive Incentive Share Plan.
(A) 10-44 - Long-Term Executive Incentive Share Plan
Deferred Compensation Agreement.
(A) 10-48 - Employment Agreement for J.A. Carrigg Amendment No. 1.
(A) 10-50 - Form of Severance Agreement for Senior Vice
Presidents Amendment No. 1.
(A) 10-52 - Form of Severance Agreement for Vice Presidents
Amendment No. 1.
(A) 10-53 - Deferred Compensation Plan for Salaried Employees.
12 - Computation of Ratio of Earnings to Fixed Charges.
21 - Subsidiaries.
23 - Consent of Coopers & Lybrand L.L.P.to incorporation by reference
into certain registration statements.
27 - Financial Data Schedule.
(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
______________________________
(A) Management contract or compensatory plan or arrangement.
Exhibit No. Filed in As Exhibit No.
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
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
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
Exhibit No. Filed in As Exhibit No.
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)10-16 - 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)10-17 - 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)10-18 - Supplemental Executive Retirement Plan - Company's
10-Q for quarter ended March 31, 1994 -
File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-49
(A)10-19 - Supplemental Executive Retirement Plan Amendment
No. 1 - Company's 10-K for the year ended December
31, 1994 - File No. 1-3103-2 . . . . . . . . . . . . 10-18
(A)10-20 - 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)10-21 - 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)10-22 - 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)10-23 - 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)10-24 - 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)10-25 - 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) Management contract or compensatory plan or arrangement.
Exhibit No. Filed in As Exhibit No.
(A)10-26 - 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)10-27 - 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)10-28 - 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)10-30 - Annual Executive Incentive Compensation Plan.
Company's 10-K for year ended December 31, 1992 -
File No. 1-3103-2 . . . . . . . . . . . . . . . . . . 10-30
(A)10-31 - 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)10-32 - 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 - Annual Executive Incentive Compensation Plan
Amendment No. 3 - Company's 10-K for the year ended
1994 - File No. 1-3103-2. . . . . . . . . . . . . . . 10-31
(A)10-34 - Annual Executive Incentive Compensation Plan
Amendment No. 4 - Company's 10-K for the year ended
1994 - File No. 1-3103-2. . . . . . . . . . . . . . . 10-32
(A)10-35 - Annual Executive Incentive Compensation Plan
Amendment No. 5 - Company's 10-Q for the quarter ended
September 30, 1995 - File No. 1-3103-2. . . . . . . . 10-45
(A)10-37 - Performance Share Plan - Company's 10-K for year
ended December 31, 1990 - File No. 1-3103-2 . . . . 10-36
(A)10-38 - Performance Share Plan Amendment No. 1 - Company's
10-Q for quarter ended March 31, 1991 -
File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-38
(A)10-39 - Performance Share Plan Amendment No. 2 - Company's
10-Q for quarter ended June 30, 1991 -
File No. 1-3103-2 . . . . . . . . . . . . . . . . . 10-39
(A)10-40 - Performance Share Plan Amendment No. 3 - Company's
10-K for year ended December 31, 1992 - File No.
1-3103-2. . . . . . . . . . . . . . . . . . . . . . 10-34
(A)10-41 - Performance Share Plan Amendment No. 4 - Company's
10-K for year ended December 31, 1993 - File No.
1-3103-2. . . . . . . . . . . . . . . . . . . . . . 10-41
(A)10-45 - Employment Contract for A. E. Kintigh - Company's
10-K for year ended December 31, 1988 - File
No. 1-3103-2. . . . . . . . . . . . . . . . . . . . 10-26
(A)10-46 - Agreement with M.I. German - Company's 10-K for the
year ended December 31, 1994 - File No. 1-2103-2. . 10-41
(A)10-47 - Employment Agreement for J. A. Carrigg - Company's
10-K for year ended December 31, 1993 - File No.
1-3103-2. . . . . . . . . . . . . . . . . . . . . . . 10-46
(A)10-49 - 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)10-51 - Form of Severance Agreement for Vice Presidents -
Company's 10-K for year ended December 31, 1993 -
File No. 1-3103-2 . . . . . . . . . . . . . . . . . . 10-48
______________________________
(A) Management contract or compensatory plan or arrangement.
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
None
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 8, 1996 By Gary J. Turton
Gary J. Turton
Vice President and 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 8, 1996 By James A. Carrigg
James A. Carrigg
Chairman, President,
Chief Executive Officer and
Director
PRINCIPAL FINANCIAL OFFICER
Date: March 8, 1996 By Sherwood J. Rafferty
Sherwood J. Rafferty
Senior Vice President and
Chief Financial Officer
PRINCIPAL ACCOUNTING OFFICER
Date: March 8, 1996 By Gary J. Turton
Gary J. Turton
Vice President and Controller
Date: March 8, 1996 By Alison P. Casarett
Alison P. Casarett
Director
Date: March 8, 1996 By Joseph J. Castiglia
Joseph J. Castiglia
Director
Signatures (Cont'd)
Date: March 8, 1996 By Lois B. DeFleur
Lois B. DeFleur
Director
Date: March 8, 1996 By Everett A. Gilmour
Everett A. Gilmour
Director
Date: March 8, 1996 By John M. Keeler
John M. Keeler
Director
Date: March 8, 1996 By Allen E. Kintigh
Allen E. Kintigh
Director
Date: March 8, 1996 By Ben E. Lynch
Ben E. Lynch
Director
Date: March 8, 1996 By Alton G. Marshall
Alton G. Marshall
Director
Date: March 8, 1996 By David R. Newcomb
David R. Newcomb
Director
Date: March 8, 1996 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.
* 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.
___________________________________
* Incorporated by reference.
EXHIBIT INDEX (Cont'd)
* 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.
* 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.
* * * * * * * * * *
___________________________________
* Incorporated by reference.
EXHIBIT INDEX (Cont'd)
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.
* 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 -- Retirement Plan for Directors Amendment No. 2.
(A)* 10-16 -- Form of Deferred Compensation Plan for Directors.
(A)* 10-17 -- Deferred Compensation Plan for Directors
Amendment No. 1.
(A)* 10-18 -- Supplemental Executive Retirement Plan.
(A)* 10-19 -- Supplemental Executive Retirement Plan Amendment
No. 1.
(A)* 10-20 -- Supplemental Executive Retirement Plan Amendment
No. 2.
(A)* 10-21 -- Supplemental Executive Retirement Plan Amendment
No. 3.
(A)* 10-22 -- Supplemental Executive Retirement Plan Amendment
No. 4.
(A)* 10-23 -- Supplemental Executive Retirement Plan Amendment
No. 5.
(A)* 10-24 -- Supplemental Executive Retirement Plan Amendment
No. 6.
(A)* 10-25 -- Supplemental Executive Retirement Plan Amendment
No. 7.
(A)* 10-26 -- Supplemental Executive Retirement Plan Amendment
No. 8.
(A)* 10-27 -- Supplemental Executive Retirement Plan Amendment
No. 9.
(A)* 10-28 -- Supplemental Executive Retirement Plan Amendment
No. 10.
(A) 10-29 -- Supplemental Executive Retirement Plan Amendment
No. 11.
(A)* 10-30 -- Annual Executive Incentive Compensation Plan.
(A)* 10-31 -- Annual Executive Incentive Compensation Plan
Amendment No. 1.
___________________________________
* Incorporated by reference.
EXHIBIT INDEX (Cont'd)
(A)* 10-32 -- Annual Executive Incentive Compensation Plan
Amendment No. 2.
(A)* 10-33 -- Annual Executive Incentive Compensation Plan Amendment
No. 3.
(A)* 10-34 -- Annual Executive Incentive Compensation Plan Amendment
No. 4.
(A)* 10-35 -- Annual Executive Incentive Compensation Plan Amendment
No. 5.
(A) 10-36 -- Annual Executive Incentive Plan.
(A)* 10-37 -- Performance Share Plan.
(A)* 10-38 -- Performance Share Plan Amendment No. 1.
(A)* 10-39 -- Performance Share Plan Amendment No. 2.
(A)* 10-40 -- Performance Share Plan Amendment No. 3.
(A)* 10-41 -- Performance Share Plan Amendment No. 4.
(A) 10-42 -- Performance Share Plan Amendment No. 5.
(A) 10-43 -- Long-Term Executive Incentive Share Plan.
(A) 10-44 -- Long-Term Executive Incentive Share Plan Deferred
Compensation Agreement.
(A)* 10-45 -- Employment Contract for A. E. Kintigh.
(A)* 10-46 -- Agreement with M. I. German.
(A)* 10-47 -- Employment Agreement for J. A. Carrigg.
(A) 10-48 -- Employment Agreement for J. A. Carrigg Amendment
No. 1.
(A)* 10-49 -- Form of Severance Agreement for Senior Vice
Presidents.
(A) 10-50 -- Form of Severance Agreement for Senior Vice
Presidents Amendment No. 1.
(A)* 10-51 -- Form of Severance Agreement for Vice Presidents.
(A) 10-52 -- Form of Severance Agreement for Vice Presidents
Amendment No. 1.
(A) 10-53 -- Deferred Compensation Plan for Salaried Employees.
12 -- Computation of Ratio of Earnings to Fixed Charges.
21 -- Subsidiaries.
23 -- Consent of Coopers & Lybrand L.L.P. to incorporation
by reference into certain registration statements.
27 -- Financial Data Schedule.
___________________________________
(A) Management contract or compensatory plan or arrangement.
* Incorporated by reference.