<PAGE>

REVIEW OF THE COMPANY'S RESULTS OF OPERATIONS AND FINANCIAL CONDITION

FINANCIAL PERFORMANCE

     Consolidated earnings per share were $2.60 for 1995, compared to $2.50 in
1994 and $3.06 in 1993. While earnings in 1995 increased modestly over 1994, the
impact of the costs associated with the investigation and litigation involving
former officers and others, the provision for refunds to be passed back to
customers, and regulatory actions related to these events as well as a decline
in non-utility subsidiary operating results have all impacted the last three
years results. Despite the adverse effects of these items on earnings for the
1993-1995 time period, the core utility business produced strong operating
results, as electric sales to customers continued to increase, gas sales
remained stable and operating expenses decreased as part of the Company's cost
containment program during the period. The decline in non-utility earnings is
primarily a result of the continuing competitive pressure in the gas marketing
business, which substantially limited the subsidiary's gross profit margin, and
the continuing losses by the Company's discontinued broadcasting business, and
the reduction from revalued properties.

     Consolidated earnings available for common stock were $35.4 million in
1995, $34.0 million in 1994 and $41.5 million in 1993. Earnings per average
common share are summarized as follows:

<TABLE>
<CAPTION>
                                             1995      1994       1993
---------------------------------------------------------------------------
---------------------------------------------------------------------------
<S>                                         <C>       <C>         <C>
Utility operations                          $3.20     $3.14       $3.37
Events Affecting the Company:
  Investigation and litigation costs         (.35)     (.42)       (.29)
  Refunds of misappropriated funds           (.14)     (.20)         --
Diversified activities                       (.11)     (.02)       (.02)
---------------------------------------------------------------------------
Consolidated earnings per share             $2.60     $2.50       $3.06
---------------------------------------------------------------------------
</TABLE>

     The earned return on common equity was 9.4% in 1995, compared to 9.0% in
1994, and 11.2% in 1993. Book value per share at year-end 1995 was $27.82,
compared to $27.79 in 1994 and 1993.

     The Company continued to provide a fair and equitable return on
shareholders' investments by increasing the dividend paid on common stock to
$2.57 per share from the $2.54 paid in 1994 and the $2.49 paid in 1993. The
Company has maintained a strong capital structure of 46% long-term debt, 6%
preferred stock and 48% common equity.

INVESTIGATION AND LITIGATION

     The Company continues to pursue a lawsuit and arbitration proceedings
against a former officer to recover misappropriated funds and other costs
attributable to any wrongdoing and related investigation.

     For more information on these legal proceedings, refer to Note 12 of Notes
to Consolidated Financial Statements.


MANAGEMENT TEAM

     Recognizing the significant changes taking place in the utility industry,
the Company has engaged in a major corporate restructuring. In addition to the
appointment of D. Louis Peoples as Vice Chairman and Chief Executive Officer
(CEO) and R. Lee Haney as Vice President and Chief Financial Officer (CFO) in
1994, the Company made the following appointments in 1995. On February 2, 1995,
Richard N. White was appointed Ethics Officer. On February 21, 1995, the Company
appointed G.D. Caliendo as Vice President, General Counsel and Corporate
Secretary. On March 22, 1995, Nancy M. Jakobs was named Vice President of Human
Resources. The Company announced on December 7, 1995, the appointment of Larry
S. Brodsky, a former Senior Vice President at Illinois Power Company, as
President and Chief Operating Officer. Mr. Brodsky replaces Victor J. Blanchet,
Jr., who resigned on March 1, 1995. Mr. Brodsky assumed these duties on January
2, 1996.

     The Board of Directors appointed two new members during 1995. On February
2, and October 5, 1995, the Company appointed Frederic V. Salerno and Jon F.
Hanson, respectively, as new Board members.

     The Company believes that with this management team now in place, it is
better suited to deal with the changing industry and capitalize on new
competitive opportunities.

RESULTS OF OPERATIONS

     The discussion which follows identifies the principal causes of the
significant changes in the amounts of revenues and expenses affecting income
available for common stock by comparing 1995 to 1994 and 1994 to 1993. This
discussion should be read in conjunction with the Notes to Consolidated
Financial Statements and other financial and statistical information contained
elsewhere in this report. The following is a summary of the changes in earnings
available for common stock:

<TABLE>
<CAPTION>
Increase (Decrease) From Prior Year                  1995         1994
---------------------------------------------------------------------------
---------------------------------------------------------------------------
                                                  (Millions of Dollars)
<S>                                               <C>            <C>
Utility Operations:
  Operating revenues                            $ (36.0)       $(8.0)

  Energy costs                                    (26.6)        (4.9)
---------------------------------------------------------------------------

    Net revenues from utility operations           (9.4)        (3.1)

Other utility operating expenses and taxes        (10.2)         3.6
---------------------------------------------------------------------------

    Operating income from utility operations        0.8         (6.7)
Diversified revenues                               49.2         57.8

Diversified operating expenses and taxes           53.5         58.1
---------------------------------------------------------------------------

Income from operations                             (3.5)        (7.0)
Other income and deductions                         4.2         (0.8)

Interest charges                                   (0.7)        (0.2)
---------------------------------------------------------------------------

Net income                                          1.4         (7.6)

Preferred dividends                                (0.1)        (0.1)
---------------------------------------------------------------------------
Earnings available for common stock             $   1.5        $(7.5)
---------------------------------------------------------------------------
</TABLE>


                                       11

<PAGE>

ELECTRIC OPERATING REVENUES AND SALES

     Electric operating revenues, net of fuel and purchased power costs,
decreased by 2.5% or $8.5 million in 1995 after decreasing by 1.4% or $4.7
million in 1994.

     The components of these changes are attributable to the following factors:

<TABLE>
<CAPTION>
Increase (Decrease) From Prior Year                  1995         1994
---------------------------------------------------------------------------
---------------------------------------------------------------------------
                                                   (Millions of Dollars)
<S>                                               <C>            <C>
Retail sales:
  Price changes                                 $ (19.3)       $(5.3)

  Sales volume changes                              4.8          8.7
---------------------------------------------------------------------------
  Subtotal                                        (14.5)         3.4
Sales for resale                                   (4.5)         0.2

Other operating revenues                             --        (11.5)
---------------------------------------------------------------------------
    Total electric revenues                       (19.0)        (7.9)

Electric energy costs                             (10.5)        (3.2)
---------------------------------------------------------------------------
    Net electric revenues                       $  (8.5)       $(4.7)
---------------------------------------------------------------------------
</TABLE>

     Actual total sales of electric energy to retail customers during 1995 were
4,526 Mmwh, compared with 4,464 Mmwh during 1994 and 4,358 Mmwh in 1993. Before
reflecting the effects of the Revenue Decoupling Mechanism (RDM) in the
Company's New York jurisdiction, electric revenues associated with these sales
were $472.5 million, $487.0 million and $483.6 million in 1995, 1994 and 1993,
respectively.

     Electric sales to customers for the last five years are shown in the
following chart.

[Graphics Chart, see Appendix A of Exhibit 13]

     The changes in electric sales by class of customer from the prior year are
as follows:

<TABLE>
<CAPTION>
                                                   1995      1994
---------------------------------------------------------------------------
---------------------------------------------------------------------------
<S>                                               <C>       <C>
Residential                                       1.5%      3.0%
Commercial                                         .3%      1.5%
Industrial                                        3.6%      4.6%
Public street lighting                            1.0%       .5%
Sales to public authorities                       9.5%     (4.3%)
---------------------------------------------------------------------------
</TABLE>

     An increase in the number of customers, coupled with unusually warm weather
during the summer months compared to the previous year, was the primary reason
electric retail sales increased 1.4% in 1995. The increase in the number of
customers resulted in an increase in sales of 2.4% in 1994 compared to 1993.

     The Company continues to meet the needs of its customers by pursuing least-
cost strategies. Demand-Side Management (DSM) programs, which are designed to
reduce peak load, encourage efficient energy usage and reduce the need for
costly investments in new generating capacity, continue to be a part of the
Company's resource plan. These efforts resulted in the Company achieving an
energy-efficiency savings of approximately 234,845 Mwh in 1995, 193,864 Mwh in
1994 and 166,697 Mwh in 1993. Based on the energy efficiency  savings in New
York, the Company earned and filed to recover DSM incentives provided by the New
York State Public Service Commission (NYPSC). The Company was able to earn an
incentive of approximately $1.4 million in 1995, $0.6 million in 1994 and $3.1
million in 1993. In addition to DSM, the Company continues to actively seek
cost-effective energy supply options, such as purchased power agreements with
other utilities.

     Under the RDM, actual electric sales revenue based on usage in the
Company's New York franchise territory is reconciled to the level allowed in
rates, thereby minimizing the impact of sales volume changes on earnings. The
Company's earnings from New York electric operations under the RDM agreement are
dependent on controlling operating and maintenance costs within levels provided
for in rates, as well as achieving its  DSM goals. Under the agreement, New York
electric revenue targets, net of fuel and taxes amounted to $216.0, $224.8, and
$223.2 million, compared to actual sales revenues based upon usage of $230.3,
$237.1, and $230.1 million, in 1995, 1994, and 1993, respectively, requiring
the Company to record  revenue reductions of $14.3 million in 1995, $12.3
million in 1994 and $6.9 million in 1993.

     Although the RDM agreement was scheduled to expire on December 31, 1993,
the NYPSC's June 10, 1994 decision extended the provisions of the agreement with
certain modifications as more fully described under "Rate Activities". The RDM
agreement will continue to affect future electric earnings from the Company's
New York operations until new rates are implemented as a result of the pending
base rate case. Electric earnings from the Company's New Jersey and Pennsylvania
operations will continue to be affected by changes in sales volumes resulting
from the strength of the economy, weather conditions and the conservation
efforts of customers.

     Sales for resale decreased from $6.6 million in 1994 to $2.1 million in
1995 after increasing by $0.2 million in 1994. Revenues from these sales are
primarily a recovery of costs, under the applicable tariff regulations, and have
a minimal impact on the Company's earnings.


                                       12

<PAGE>

ELECTRIC ENERGY COSTS

     The cost of fuel used in electric generation and purchased power decreased
7.8% or $10.5 million in 1995, after decreasing 2.3% or $3.2 million in 1994.
The components of these changes in electric energy costs are as follows:

<TABLE>
<CAPTION>
Increase (Decrease) From Prior Year                1995           1994
---------------------------------------------------------------------------
---------------------------------------------------------------------------
                                                  (Millions of Dollars)
<S>                                               <C>             <C>
Prices paid for fuel and purchased power         $ (2.4)         $(8.3)
Changes in Kwh generated or purchased              (2.1)           3.1

Deferred fuel charges                              (6.0)           2.0
---------------------------------------------------------------------------
  Total                                          $(10.5)         $(3.2)
---------------------------------------------------------------------------
</TABLE>

     The decrease in electric energy costs in 1995 reflects the lower costs of
fuel used in generation, offset somewhat by an increase in purchased power
costs. Reduced prices paid for coal and natural gas used for generation,
partially offset by increases in kilowatt hour demand, was the primary reason
for the 1994 decrease.

     The price paid for fuel and purchased power per kilowatt hour over the last
five years is shown in the following chart.
[Graphics Chart, see Appendix A of Exhibit 13]

     The Company's tariff schedules include adjustment clauses under which fuel
and certain purchased power costs are recovered. In New York, an incentive-based
mechanism associated with the electric fuel adjustment clause requires the
Company to share 20% of the variation between actual costs and forecast fuel
targets, up to a maximum of $1,762,000. In 1995, 1994, and 1993, pre-tax
earnings were enhanced by $755,000, $1,241,000 and $755,000, respectively, as a
result of this mechanism. The Company maintains an aggressive program of
managing its sources of fuel and energy purchases to provide its customers with
the lowest cost of energy available at any given time. Energy is purchased
whenever available at a price lower than the cost of production at the Company's
generating plants. The Company continues to use the least costly fuel available
for generating electricity.

GAS OPERATING REVENUES AND SALES

     Gas operating revenues, net of gas purchased for resale, decreased by 1.2%,
or $0.9 million in 1995 as compared to an increase of 2.4%, or $1.6 million in
1994.

     These changes are attributable to the following factors:

<TABLE>
<CAPTION>
Increase (Decrease) From Prior Year            1995          1994
---------------------------------------------------------------------------
---------------------------------------------------------------------------
                                              (Millions of Dollars)
<S>                                         <C>              <C>
Sales to firm customers:
 Price changes                            $(19.6)          $   --

 Sales volume changes                       (1.9)            (0.4)
---------------------------------------------------------------------------
  Subtotal                                 (21.5)            (0.4)
Sales to interruptible customers             2.7              1.4
Sales for resale                            (0.1)             0.1

Other operating revenues                     1.9             (1.2)
---------------------------------------------------------------------------
  Total gas revenues                       (17.0)            (0.1)

Gas energy costs                           (16.1)            (1.7)
---------------------------------------------------------------------------
  Net gas revenues                       $  (0.9)           $ 1.6
---------------------------------------------------------------------------
</TABLE>

     Firm gas sales amounted to 19,825 million cubic feet (Mmcf) during 1995, a
decrease of 2.9% from the 1994 level of 20,421 Mmcf. Firm gas sales for 1993
were 20,556 Mmcf. Gas revenues from firm customers were $128.0 million, $149.4
million and $149.8 million in 1995, 1994 and 1993, respectively.

     Gas sales to firm customers for the last five years are shown in the
following chart.

[Graphics Chart, see Appendix A of Exhibit 13]

     The changes in firm gas sales by class of customer from the
prior year are as follows:

<TABLE>
<CAPTION>
                                              1995           1994
---------------------------------------------------------------------------
---------------------------------------------------------------------------
<S>                                       <C>             <C>
Residential                               (2.7%)          (1.0%)

Commercial and industrial                 (3.6%)           0.5%
---------------------------------------------------------------------------
</TABLE>

     Sales in 1995 and 1994 were adversely affected by weather conditions. The
increase in the number of customers in 1995 and 1994 somewhat offset the
decrease in sales.

     Under the terms of the current gas rate agreement in New York, the level of
firm sales is subject to a weather normalization adjustment. The Company adjusts
firm gas sales revenues to the extent actual degree days vary more than plus or
minus 2.2% from the degree days utilized to project sales during a heating
season. Therefore, weather conditions have a minimal impact on gas revenues.

     Revenues from interruptible gas customers (customers with alternative fuel
sources) increased by 68.3% and 53.4% in


                                       13

<PAGE>

1995 and 1994, respectively. These sales are dependent upon the availability and
price competitiveness of alternative fuel sources. As a result of applicable
tariff regulations, these sales do not have a substantial impact on earnings.

GAS ENERGY COSTS

     Utility gas energy costs decreased by 18.2%, or $16.1 million in 1995,
after decreasing 1.9% or $1.7 million in 1994.

     The changes in utility gas energy costs for the years 1995 and 1994 are a
result of the following:

<TABLE>
<CAPTION>
Increase (Decrease) From Prior Year                   1995         1994
---------------------------------------------------------------------------
---------------------------------------------------------------------------
                                                      (Millions of Dollars)
<S>                                                  <C>         <C>
Prices paid to gas suppliers*                        $(9.5)      $(2.7)
Firm and interruptible Mcf sendout                     3.1         3.2

Deferred fuel charges                                 (9.7)       (2.2)
---------------------------------------------------------------------------
 Total                                              $(16.1)      $(1.7)
---------------------------------------------------------------------------
</TABLE>

*Net of refunds received from gas suppliers.

     The Company continues its policy of the aggressive use of spot market
purchases in order to provide price flexibility, while assuring an adequate
supply of gas through a variety of long-term contracts with pipeline suppliers.

     The price paid for purchased gas per thousand cubic feet (Mcf) over the
last five years is shown in the following chart.

[Graphics Chart, See Appendix A of Exhibit 13]

     Gas costs from 1990-1993 were adversely affected by the actions of the
Federal Energy Regulatory Commission (FERC), which had authorized pipeline
suppliers to pass through take-or-pay costs. As required by the NYPSC in Case
88-G-062, the Company has deferred a portion of these costs. As of December 31,
1995, $1.6 million of deferred take-or-pay charges and accrued interest remain
on the books of the Company. The Company and the NYPSC have reached an agreement
allowing the Company to recover these costs.

     As a result of the FERC's objective to restructure the gas transportation
industry to promote competition among gas suppliers and to ensure supply at the
lowest reasonable costs, the FERC, pursuant to FERC Order No. 636, has
authorized pipelines to recover certain transition costs from their customers.
The Company currently estimates that its obligations for Order No. 636
transition costs will total approximately $25.1 million. Approximately $19.0
million of these transition costs have been billed to the Company.

     On December 20, 1994 the NYPSC issued an order establishing the regulatory
and rate-making policies applicable to New York gas distribution utilities
resulting from FERC Order No. 636. The order provides mechanisms for the full
recovery of transition costs. The Company is presently in the process of
recovering these costs from its customers and believes it will be allowed to
fully recover such costs by the end of 2000.

OTHER UTILITY OPERATING EXPENSES AND TAXES

     A comparison of other operating expenses and taxes for utility operations
is presented in the following table:

<TABLE>
<CAPTION>
Increase (Decrease) From Prior Year                   1995          1994
---------------------------------------------------------------------------
---------------------------------------------------------------------------
                                                     (Millions of Dollars)

<S>                                                <C>            <C>
Other operating expenses                           $(9.3)         $(0.2)
Maintenance                                         (2.8)           1.1
Depreciation & amortization                          2.1            1.7

Taxes                                               (0.2)           1.0
---------------------------------------------------------------------------
 Total                                            $(10.2)          $3.6
---------------------------------------------------------------------------
</TABLE>

     The costs of DSM programs, which decreased by $8.1 million in 1995 and $7.4
million in 1994, were the primary causes of the changes in other operating
expenses in 1995 and 1994. These costs are recovered in revenues on a current
basis. Additionally, the Company's cost containment program lowered 1995 costs
through operating efficiencies and lower labor costs realized by attrition. The
decrease in the cost of DSM programs in 1994 was offset by increases in the cost
of labor, material and services.

     Maintenance costs decreased 6.4% in 1995, as compared to an increase of
2.6% in 1994. The changes in 1995 and 1994 were primarily the result of
maintenance of the Company's distribution plant.

     Depreciation and amortization expenses increased $2.1 million in 1995 after
increasing $1.7 million in 1994. The increases in 1995 and 1994 were the result
of normal plant additions.

     Taxes other than income taxes decreased $1.9 million in 1995 as compared to
an increase of $2.6 million in 1994. The decrease in 1995 was the result of
lower taxes associated with revenues, while the increase in 1994 was primarily
the result of increases in taxes associated with revenues and property taxes.
Federal income tax expense increased $1.7 million in 1995, after decreasing $1.6
million in 1994. The changes in both years are the result of changes in pre-tax
book income. For a detailed analysis of income tax components, see Note 2 of
Notes to Consolidated Financial Statements.

DIVERSIFIED ACTIVITIES

     The Company's diversified activities, at year end, consisted of gas
marketing, gas production and land development businesses conducted by its
wholly owned non-utility subsidiaries.

     In September 1994, the Company sharpened its focus on its core energy
services business by adopting a plan to sell  the six radio broadcast properties
operated by one of its  non-utility subsidiaries. All sales have been finalized
and did not have a material effect on the Company's consolidated financial
statements. The Company is in the process of dissolving its gas production
business. It is anticipated the Company will cease these operations by the end
of 1996 and this will not have a material effect on the Company's Results of
Operations.

     The Company's wholly owned gas marketing subsidiary, NORSTAR Holdings,
formerly O&R Energy, Inc., signed an


                                       14

<PAGE>

agreement with a wholly owned subsidiary of Shell Gas Trading Company (Shell) to
create a new full service natural gas services and marketing company -- NORSTAR
Energy Limited Partnership. Under the terms of the agreement, Shell contributed
substantial firm gas supplies and other assets in exchange for approximately a
27 percent limited partnership interest. NORSTAR Holdings transferred its
natural gas  marketing business to the new venture in exchange for approximately
a 73 percent general partnership interest. The alliance of NORSTAR Holdings' gas
marketing and operations expertise with the commitment of firm gas supplies from
Shell will assure NORSTAR a strong capital structure and increase the range of
services available to support an aggressive  expansion into new markets.

     Revenues from diversified activities increased by $49.2 million and $57.8
million in 1995 and 1994, respectively, primarily as a result of increased sales
from gas marketing activities.

     Operating expenses, incurred by the non-utility subsidiaries, increased by
$53.5 million and $58.1 million in 1995 and 1994, respectively. These increases
are directly related to gas marketing purchases which were $53.6 million and
$55.5 million higher in 1995 and 1994, respectively. Other expenses of
operation, maintenance, depreciation and taxes decreased  $0.1 million in 1995,
after increasing by $2.6 million in 1994.  Earnings from diversified activities
decreased by $1.3  million and $0.9 million in 1995 and 1994, respectively. The
declines were primarily due to continued weakness in the natural gas price
resale market, resulting in insufficient margins realized by the gas marketing
subsidiary and losses by the Company's broadcasting business. Earnings in 1995
were  further reduced by the recognition of the market value of properties held
by an affiliate of our gas marketing subsidiary. However, diversified earnings
were enhanced by a $2.9 million gain realized as a result of the formation of
the NORSTAR Partnership.

OTHER INCOME AND DEDUCTIONS AND INTEREST CHARGES

     Other income and deductions increased by $4.2 million in 1995, after
decreasing by $0.8 million in 1994. The increase in 1995 is primarily the result
of the gain of $2.9 million from the formation of NORSTAR plus lower
investigation and litigation costs. The decrease in 1994 resulted from higher
investigation and litigation expenses, which reduced Other Income by $1.7
million, net of taxes. This decrease in income was somewhat offset by a $0.7
million reduction in political expenditures and charitable contributions and a
$0.4 million improvement in the operating results from the Company's radio
broadcasting subsidiary.

     Interest charges decreased $0.7 million, or 2.2% in 1995, after decreasing
$0.2 million, or 0.7%, in 1994. The 1995 and 1994 decreases are the result of
refinancing certain of the Company's long-term debt issues, taking advantage of
the lower interest rates available, and the retirement of long-term debt issues
in 1995, offset by an increase in the cost of short-term debt in 1995, after a
decrease in such costs in 1994.

LIQUIDITY AND CAPITAL RESOURCES

     The Company's construction program is designed to maintain reliable
electric and gas service, meet future customer service requirements and improve
the Company's competitive position. The cash expenditures related to the
construction program and other capital requirements for the years
1993-1995 were as follows:

<TABLE>
<CAPTION>
                                               1995       1994       1993
---------------------------------------------------------------------------
                                                  (Millions of Dollars)

<S>                                         <C>        <C>         <C>
Construction expenditures                   $56.8      $62.5       $57.2
Retirement of long-term debt &
  preferred stock -- net                     20.8        4.1         1.5
---------------------------------------------------------------------------
    Total                                   $77.6      $66.6       $58.7
---------------------------------------------------------------------------
</TABLE>

     At December 31, 1995, the Company estimated the cost of its construction
program in 1996 to be $52.8 million and retirement of long-term debt and
preferred stock to be $1.8 million. It is expected that the Company's capital
requirements for 1996 will be met primarily with funds from operations,
supplemented by the issuance of short-term borrowings.

     On July 27, 1995, the New York State Energy Research and Development
Authority (NYSERDA) issued, on behalf of  the Company, $44 million of variable
rate Pollution Control Refunding Revenue Bonds due August 1, 2015 (1995 Bonds).
The interest rate is adjusted weekly, unless converted to a fixed rate. The
average interest rate in 1995 was 3.63%. The proceeds from the issuance of the
1995 Bonds, together with other Company funds, were used to refund, on August
20, 1995, the $44 million NYSERDA 9% Pollution Control Revenue Bonds, 1985
Series issued on behalf of the Company.

     The Company's Dividend Reinvestment Plan (DRP) and its Employee Stock
Purchase and Dividend Reinvestment Plan (ESPP) provide that, at the option of
the Company, the  common stock requirements of the plans may be satisfied by
either original stock issues or open market purchases. Since November 1, 1994,
the requirements of both plans have been satisfied by open market purchases. The
Company, however, has authority to issue up to 750,000 shares of its common
stock under the DRP and ESPP through December 31, 1997, of which approximately
693,000 shares were unissued at December 31, 1995.

     The Company and its utility subsidiaries have unsecured bank lines of
credit totaling $64.5 million. The Company  may borrow under the lines of credit
through the issuance  of promissory notes to the banks. The Company, however,
utilizes such lines of credit to fully support commercial paper borrowings. The
aggregate amount of borrowings through the issuance of promissory notes and
commercial paper cannot exceed the aggregate lines of credit. In addition, non-
utility lines of credit amounted to $20.0 million at December 31, 1995, and the
non-utility subsidiaries may undertake short-term borrowings or make short-term
investments.


                                       15

<PAGE>

RATE ACTIVITIES

NEW YORK -- GAS

     On January 16, 1992, the Company filed an application for an increase in
gas rates with the NYPSC. The Settlement Agreement in that case, which was
approved by the NYPSC on September 30, 1992, provided, among other things, for
multi-year rate adjustments through 1996 and for certain gas incentives. The
second adjustment to gas rates under the Settlement Agreement, which amounted to
an increase of $3.8 million or 2.5%, was to become effective on January 1, 1994.
As a result of the ongoing investigation of alleged financial improprieties
(Investigation) as discussed below, however, the increase was first extended to
June 30, 1994 and then further extended to December 30, 1994. On November 4,
1994, the NYPSC issued an Order terminating the Settlement Agreement effective
December 31, 1994. The Order denied the Company the opportunity for rate
adjustments in the third and fourth years (1995 and 1996) of the four-year
Settlement Agreement. However, the Order authorized the Company to defer the
second stage rate adjustments and all previously authorized reconciliations
pertaining to periods prior to December 31, 1994, pending review and audit by
the NYPSC staff and the conclusion of the Investigation. In addition, on
February 7, 1995, the Accounting and Finance Division of the NYPSC issued an
interpretation of the November 4, 1994 termination order which stated that the
gas incentive mechanism related to the attainment of certain goals was no longer
available. The Company did not contest this interpretation.

     On October 2, 1995, the Company, the NYPSC Staff, the Industrial Energy
Users Association (IEUA), and the New  York State Consumer Protection Board
(NYCPB), reached a settlement which would resolve all outstanding issues
relating to the Investigation. The settlement provides for, among other things,
the cancellation of the second stage gas base rate increase discussed above. All
deferred balances resulting from expense reconciliations and deferral of the
second stage rate adjustment are to be offset with an equal amount of deferred
credits resulting from certain changes to depreciation approved as part of the
original multi-year rate plan. In  addition, the settlement provides for the
recognition in gas rates of the change in accounting required by Statement  of
Financial Accounting Standards No. 106, "Employee Postretirement Benefits Other
Than Pension". The annual cost increase due to gas operations will be offset by
an equal amount of deferred depreciation credits. On January 25,  1996 the
Administrative Law Judge issued a Recommended Decision which recommended that
the NYPSC approve the settlement. A final NYPSC decision is expected by April
1996.

NEW YORK -- ELECTRIC

     On June 10, 1994, the NYPSC issued an Order (the June Order) which
terminated the Company's January 1993 electric rate increase application. The
June Order provided, among other things, for a reduction in the threshold for
measuring excess earnings from 12.0% to 10.6%, effective retroactively  to
January 1, 1994. All earnings in excess of 10.6% were to  be deferred for future
disposition pending the conclusion  of the Investigation. On September 19, 1994,
the Company filed an appeal with the Supreme Court of New York challenging the
legality of the June Order. The appeal argued that by changing the excess
earnings threshold from 12.0% to 10.6% for the first six months of 1994, the
NYPSC engaged in retroactive rate-making. The appeal also argued that there was
no evidence in the record to support a determination that the cost of equity was
10.6%. This appeal was withdrawn pursuant to a Stipulation approved by the NYPSC
on August 1, 1995, as described below.

     On February 17, 1995, the Company submitted a compliance filing regarding
the operation of the Revenue Decoupling Mechanism (RDM). The filing included a
proposal to reduce the RDM Adjustment Factor from $7.7 million to $0, effective
May 1, 1995, reflecting the completion of the recovery of an RDM undercollection
applicable to the year 1993. This resulted in a 2.3% annual reduction in
revenues. In addition, the filing requested that a net RDM overcollection of
$0.7 million for the year 1994 be retained by the Company as a future rate
moderator, subject to NYPSC verification. On April 19, 1995, the NYPSC approved
the proposals, and the reduction of $7.7 million in the RDM Adjustment Factor
became effective May 1, 1995.

     On May 25, 1995, the Company filed a request with the NYPSC for a decrease
in electric revenues of $6.1 million to be effective April 1, 1996 (Case 95-E-
0491). This would produce an overall reduction of 1.8 percent in retail rates.
The filing reflected a reduction in operating expenses due to the complete
recovery of the Company's share of the Sterling Nuclear Project and other cost
reductions. The Company proposed a multi-year rate plan covering the three-year
period ending on March 31, 1999 with no base rate increases in the second and
third year of the plan. The Company has proposed an overall return on common
equity above 11.2%.

     On August 1, 1995, the NYPSC approved a Stipulation which provided for the
early implementation of the Company's proposed annual rate reduction of $6.1
million. As a result, reduced rates effective August 1, 1995 will produce a
revenue reduction of $3.8 million for the period August 1, 1995 - March 31,
1996. The Stipulation also increased the excess earnings threshold from 10.6% to
11.3%, with equal sharing of earnings above 11.3%, between shareholders and
ratepayers, for the period January 1, 1995 through March 31, 1996.


                                       16

<PAGE>

     The revenue reduction has been offset by the deferred  revenue associated
with the 1994 electric earned return  on equity in excess of 10.6% and the
customers' share of earnings under the new sharing mechanism effective January
1, 1995. The Stipulation also provided that the Company withdraw its September
19, 1994 appeal to the Supreme Court of New York challenging the June Order. On
January 16, 1996 the Supreme Court of New York approved a stipulation
withdrawing this appeal.

     On January 25, 1996, the Administrative Law Judge (ALJ) issued a
Recommended Decision (RD) related to outstanding Investigation issues and the
Company's currently pending New York electric rate proceeding (Case 95-E-0491).
Regarding the rate proceeding, the ALJ recommended a multi-year plan be approved
with an additional first year rate reduction of $4.3 million (1.3%) and no
changes to rates in the second and third years. The ALJ recommends a 10.6%
Return on Equity (ROE) with a 50 basis point deadband where no sharing is
required and equal sharing between the customer and shareholders of earnings
above 11.1%. In addition, performance mechanisms are recommended which could
negatively impact earned returns. The recommendation of a multi-year plan would
eliminate all revenue and expense reconciliation provisions of the Revenue
Decoupling Mechanism (RDM). A NYPSC action regarding permanent rates is expected
for rates effective April 1, 1996.

     On November 10, 1994, the Company filed, with the NYPSC, a quantification
of the rate-making effects of its ongoing investigation into prior financial
improprieties. The Company requested that the NYPSC approve a refund of
approximately $3.4 million to its New York electric and gas customers. This
amount would be in addition to the $369,000 already refunded by the Company.
This amount was charged to operations in the fourth quarter of 1994. The NYPSC
then instituted a proceeding (Case 93-M-0849) to provide the opportunity for
other parties, including the NYPSC Staff which was conducting an independent
investigation, to be heard on this matter. On July 6, 1995, the NYPSC issued an
order stating that the issues of the amount, timing and allocation of New York
ratepayer refunds as a result of the investigation in Case 93-M-0849 should be
considered in the context of the Company's current electric base rate case and
ordered the consolidation of the two cases.

     On October 2, 1995, the Company, the NYPSC Staff, the IEUA and the NYCPB
reached a settlement in order to resolve all outstanding issues relating to the
NYPSC Investigation. The settlement provided for a total of $8.5 million in
refunds for the Company's New York customers. The amount attributable to
electric operations is $6.5 million and the amount attributable to gas
operations is $2.0 million. As a result of this settlement, the Company charged
approximately $2.8 million to operations during the third quarter of 1995. The
settlement is being contested by certain parties. In his RD issued January 25,
1996 in Cases 93-M-0849 and 95-E-0491, the ALJ recommended that the NYPSC
approve the settlement. The ALJ noted that the settlement meets all of the
NYPSC's settlement guidelines and balances the interest of the Company's
customers and shareholders. A final NYPSC decision is expected by April 1996.

NEW JERSEY

     Under an agreement with the New Jersey Board of Public Utilities (NJBPU) to
return to customers any funds found to be misappropriated or otherwise
questionable as a result of  its investigation of certain former Company
officers and former employees, Rockland Electric Company (RECO), a  wholly owned
utility subsidiary of the Company, refunded to New Jersey ratepayers $93,000
through reductions in the applicable fuel adjustment charges in February and
March 1994. In December 1994, RECO submitted a proposal to the NJBPU to refund
an additional $704,000. By Order dated January 27, 1995, the NJBPU approved this
proposal and the refund was made in February 1995. In January 1996 the Company
proposed to refund an additional $482,000 to its New Jersey customers. These
amounts were charged to operations in the third quarter of 1995. The NJBPU has
not acted on this proposal. The Company is unable to predict what modifications,
if any, will be made to the amount proposed to be refunded in New Jersey.

     On November 3, 1993, the NJBPU commenced its periodic management audit of
RECO. The NJBPU audit included, in addition to a standard review of operating
procedures, policies and practices, a review of the posture of RECO management
regarding business ethics and a determination regarding the effect of such
events on RECO ratepayers. The audit findings are contained in a report titled
"Final Report on An Ethics Review of Rockland Electric Company" (Docket No. EA.
90030248) dated December 1, 1994. The NJBPU subsequently initiated an
examination of senior management appointments and changes to the composition of
the Company's Board of Directors and the development of an ethics program. The
results of this examination are contained in a report titled "Final Report of an
Ethics Oversight Review of Rockland Electric Company".

     The final Management Audit, Ethics Review, and Oversight Ethics Review
reports were approved by the NJBPU on July 7, 1995. The Oversight Ethics Review
report acknowledges that the NJBPU has approved refunds to the Company's New
Jersey customers and generally comments favorably about the changes instituted
by the Company. The NJBPU investigation into these matters is continuing and the
Company is unable to predict what modifications, if any, will be made to the
amount refunded.


                                       17

<PAGE>

COMPETITION

     Regulatory agencies in the three states in which the Company has retail
electric franchises are currently evaluating possible changes in regulatory and
rate-making practices designed to promote increased competition consistent with
safety, reliability and affordability standards. Depending on future
developments in this area, the Company's market share and profit margins could
become subject to competitive pressures in addition to regulatory constraints.

     The Company recognizes that the regulated utility environment is changing
and is committed to remaining competitive in its core energy services business
and to capitalizing on new market opportunities. The Company's strategy for
meeting the challenges of increased competition focuses on improving service
while reducing costs. The Company has adopted an aggressive cost-reduction
program and is currently evaluating the pricing of services provided to
customers. In addition, the Company's marketing function has been restructured
to identify growth opportunities and strengthen customer relations by improving
the value of energy services offered. Another component of the strategy is to
actively participate, with regulators and others, in developing a transition to
a more competitive environment which provides for an equitable sharing of
environmental, social, regulatory and taxation obligations among all parties, as
well as a reasonable opportunity for utilities to recover past investments and
expenditures made pursuant to their obligation to provide service to the public.

     In October, the Company and the seven other investor-owned utility members
of the Energy Association of New York State proposed a plan (Plan) for
restructuring the electric industry to permit wholesale competition within the
State. The Plan was drafted in response to NYPSC's Competitive Opportunities
Proceeding (Case 94-E-0952) initiated to identify regulatory and rate-making
practices that will assist in a transition to a more competitive electric energy
market. Under the Plan, all electricity producers, including the investor-owned
utilities and independent power producers, would compete in selling electricity
through a statewide pool market mechanism. Regulated utilities could purchase
energy from the pool and/or enter into separate agreements with power generators
or other parties to purchase electricity directly. In order to protect the
integrity of the electric system, an independent system operator would be
designated to coordinate operation of the bulk power transmission system and the
pool market mechanism. While such a wholesale structure would provide the
benefit of competition to all consumers, the development of retail access under
which all customers could select their own energy supplier will logically build
upon the experience gained in resolving many of the uncertainties and risks
under a competitive New York wholesale structure. The Plan also includes
proposals for regulatory and tax reform. The Company believes the Plan, with
some modifications, can successfully achieve an effective competitive
electricity market and lower electricity prices.

     Competition in the Company's gas business has existed for several years
with interruptible customers and customers with alternative fuel usage capacity
having the option to obtain their own gas supply and transport it through the
Company's distribution system. In addition, FERC Order No. 636, which
deregulated much of the interstate pipeline industry, has enabled the Company to
contract directly with gas producers for supplies of natural gas. The Company is
successfully meeting the challenge of competition in the gas business by taking
advantage of the opportunities provided in this rapidly changing business
environment to obtain greater access to reasonably priced natural gas supplies
and storage. The Company has developed customized supply and flexible pricing
arrangements to provide value added service to its gas customers and is actively
seeking new marketing opportunities.

OTHER DEVELOPMENTS

     See Note 1 of Notes to Consolidated Financial Statements, for discussion on
SFAS No. 121, "Accounting for Impairment of Long-Lived Assets and Long-Lived
Assets to be Disposed Of".

EFFECTS OF INFLATION

     The Company's utility revenues are based on rate regulation, which provides
for recovery of operating costs and a return on rate base. Inflation affects the
Company's construction costs, operating expenses and interest charges and can
impact the Company's financial performance if rate relief is not granted on a
timely basis. Financial statements, which are prepared in accordance with
generally accepted accounting principles, report operating results in terms of
historic costs and do not generally recognize the impact of inflation.


                                       18

<PAGE>

CONSOLIDATED STATEMENTS OF
INCOME AND RETAINED EARNINGS

<TABLE>
<CAPTION>
                                                  Year Ended December 31,
                                               1995        1994       1993
--------------------------------------------------------------------------------
                                                        (Thousands of Dollars)
<S>                                      <C>           <C>          <C>
OPERATING REVENUES:
  Electric (Note 1)                      $   457,833    $  472,393  $  480,553
  Gas (Note 1)                               140,224       157,168     157,257
  Electric sales to other utilities            2,150         6,636       6,414
--------------------------------------------------------------------------------
    Total Utility Revenues                   600,207       636,197     644,224
  Diversified activities (Note 1)            429,906       380,705     322,925
--------------------------------------------------------------------------------
    Total Operating Revenues               1,030,113     1,016,902     967,149
--------------------------------------------------------------------------------
OPERATING EXPENSES:
  Operations:
    Fuel used in electric production
     (Note 1)                                 69,042        84,860      74,480
    Electricity purchased for resale
     (Note 1)                                 54,700        49,391      62,969
    Gas purchased for resale (Note 1)         72,213        88,305      89,984
    Non-utility gas marketing purchases      419,485       365,917     310,467
    Other expenses of operation              142,601       152,200     149,604
  Maintenance                                 41,190        44,011      42,861
  Depreciation and amortization (Note 1)      38,937        35,862      34,056
  Taxes other than income taxes               93,887        95,964      93,610
  Federal income taxes (Notes 1 and 2)        25,779        24,540      26,225
--------------------------------------------------------------------------------
    Total Operating Expenses                 957,834       941,050     884,256
--------------------------------------------------------------------------------
INCOME FROM OPERATIONS                        72,279        75,852      82,893
--------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS:
  Allowance for other funds used
    during construction                           28            69          40
  Investigation and litigation costs
    (Note 12)                                 (7,218)       (8,795)     (6,139)
  Other - net                                  4,945          (599)     (1,743)
  Taxes other than income taxes                 (581)         (123)        (94)
  Federal income taxes (Notes 1 and 2)         1,829         4,250       3,525
--------------------------------------------------------------------------------
    Total Other Income and Deductions           (997)       (5,198)     (4,411)
--------------------------------------------------------------------------------
INCOME BEFORE INTEREST CHARGES                71,282        70,654      78,482
--------------------------------------------------------------------------------
INTEREST CHARGES:
  Interest on long-term debt                  26,620        29,553      30,383
  Other Interest                               5,495         3,088       2,404
  Amortization of debt premium and
    expense - net                              1,394         1,244       1,116

  Allowance for borrowed funds used
    during construction                         (800)         (448)       (236)
--------------------------------------------------------------------------------
    Total Interest Charges                    32,709        33,437      33,667
--------------------------------------------------------------------------------
NET INCOME                                    38,573        37,217      44,815
Dividends on preferred and preference
  stock, at required rates                     3,135         3,251       3,364
--------------------------------------------------------------------------------
Earnings applicable to common stock           35,438        33,966      41,451
Cash dividends on common stock:
  $2.57, $2.54 and $2.49                      35,089        34,486      33,694
--------------------------------------------------------------------------------
Balance to retained earnings                     349          (520)      7,757
Retained earnings, beginning of year         183,659       184,179     176,422
--------------------------------------------------------------------------------
Retained earnings, end of year           $   184,008   $   183,659  $  184,179
--------------------------------------------------------------------------------
Average number of common shares
outstanding (000's)                           13,653        13,594      13,532
--------------------------------------------------------------------------------
EARNINGS PER AVERAGE
  COMMON SHARE OUTSTANDING               $      2.60   $      2.50  $     3.06
--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
</TABLE>

The accompanying notes are an integral part of these statements.


                                       19

<PAGE>

CONSOLIDATED BALANCE SHEETS

<TABLE>
<CAPTION>
                                                            December 31,
                                                      1995               1994
--------------------------------------------------------------------------------
<S>                                            <C>                 <C>
ASSETS:                                                (Thousands of Dollars)
UTILITY PLANT:
  Electric                                     $   993,926         $  951,019
  Gas                                              211,135            198,755
  Common                                            56,796             55,445
--------------------------------------------------------------------------------
    Utility Plant in Service                     1,261,857          1,205,219
  Less accumulated depreciation                    419,844            398,584
--------------------------------------------------------------------------------
    Net Utility Plant in Service                   842,013            806,635
  Construction work in progress                     31,655             49,654
--------------------------------------------------------------------------------
    Net Utility Plant (Notes 1, 7, 11 and 12)      873,668            856,289
--------------------------------------------------------------------------------
NON-UTILITY PROPERTY:
  Non-utility property                              34,376             34,585
  Less accumulated depreciation,
    depletion and amortization                      12,945             13,977
--------------------------------------------------------------------------------
    Net Non-utility Property (Notes 1 and 7)        21,431             20,608
--------------------------------------------------------------------------------



CURRENT ASSETS:
  Cash and cash equivalents (Notes 8 and 9)          5,164             16,081
  Temporary cash investments (Note 9)                1,335              1,839
  Customer accounts receivable, less
    allowance for uncollectible accounts of
    $2,307 and $2,200                               61,653             44,105
  Accrued utility revenue (Note 1)                  22,198             27,273
  Other accounts receivable, less allowance
    for uncollectible accounts
    of $169 and $209                                 9,752             17,384
  Gas marketing accounts receivable, less
    allowance for uncollectible accounts of
    $133 and $327                                   51,198             58,470
  Materials and supplies (at average cost):
    Fuel for electric generation                     8,290              9,309
    Gas in storage                                   8,627             11,544
    Construction and other supplies                 15,751             16,983
  Prepaid property taxes                            20,687             19,327
  Prepayments and other current assets              26,463             28,877
--------------------------------------------------------------------------------
    Total Current Assets                           231,118            251,192
--------------------------------------------------------------------------------



DEFERRED DEBITS:
  Income tax recoverable in future
    rates(Notes 1 and 2)                            72,631             73,261
  Extraordinary property loss -- Sterling
    Nuclear Project(Notes 1 and 3)                   4,250             10,139
  Deferred Order No. 636 transition costs
    (Notes 1 and 12)                                 6,064             13,527
  Deferred revenue taxes(Note 1)                    15,596             16,888
  Deferred pension and other postretirement
    benefits(Notes 1 and 10)                        10,422             10,505
  IPP settlement agreements(Notes 1 and 12)         40,034             17,821
  Unamortized debt expense(amortized over
    term of securities)                             11,417             10,493
  Deferred Federal income taxes                     30,631             34,645

  Other deferred debits                             22,507             32,271
--------------------------------------------------------------------------------
    Total Deferred Debits                          213,552            219,550
--------------------------------------------------------------------------------
    TOTAL                                       $1,339,769         $1,347,639
--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
</TABLE>

The accompanying notes are an integral part of these statements.


                                       20

<PAGE>

<TABLE>
<CAPTION>
                                                            December 31,
                                                      1995               1994
--------------------------------------------------------------------------------
<S>                                            <C>                 <C>

CAPITALIZATION AND LIABILITIES:                         (Thousands of Dollars)
CAPITALIZATION:
  Common stock (Note 5)                        $    68,268        $    68,265
  Premium on capital stock (Note 5)                133,607            133,595
  Capital stock expense                             (6,107)            (6,116)

  Retained earnings (Note 4)                       184,008            183,659
--------------------------------------------------------------------------------
    Total Common Stock Equity                      379,776            379,403
--------------------------------------------------------------------------------
  Non-redeemable preferred stock                    42,844             42,844
  Non-redeemable cumulative preference stock           409                424
--------------------------------------------------------------------------------
    Total Non-Redeemable Stock (Note 5)             43,253             43,268
--------------------------------------------------------------------------------
  Redeemable preferred stock (Note 6)                1,390              2,774
--------------------------------------------------------------------------------
  Long-term debt (Notes 7 and 9)                   359,736            359,622
--------------------------------------------------------------------------------
    Total Capitalization                           784,155            785,067
--------------------------------------------------------------------------------
NON-CURRENT LIABILITIES:
  Reserve for claims and damages (Note 1)            3,848              4,713
  Postretirement benefits (Note 10)                 13,756             15,625
  Pension costs (Note 10)                           38,740             39,854
  Obligation under capital leases (Note 11)             --                275
--------------------------------------------------------------------------------
    Total Non-current Liabilities                   56,344             60,467
--------------------------------------------------------------------------------
CURRENT LIABILITIES:
  Long-term debt and lease obligation
    due within one year (Note 7)                       466             19,910
  Preferred stock to be redeemed within one
    year (Note 6)                                    1,384              1,384
  Notes payable (Notes 8 and 9)                      7,300                 --
  Commercial paper (Notes 8 and 9)                  61,250             29,400
  Accounts payable                                  62,082             63,855
  Gas marketing accounts payable                    44,630             71,913
  Dividends payable                                    693                725
  Customer deposits                                  5,455              5,669
  Accrued Federal income and other taxes             2,050              5,949
  Accrued interest                                   7,252              8,608
  Refundable gas costs (Note 1)                     10,111              7,554
  Refundable fuel costs (Note 1)                     1,203             10,366
  Refunds to customers                              13,903             10,265
  Other current liabilities                         22,942             16,127
--------------------------------------------------------------------------------
    Total Current Liabilities                      240,721            251,725
--------------------------------------------------------------------------------
DEFERRED TAXES AND OTHER:
  Deferred Federal income taxes
    (Notes 1 and 2)                                214,027            207,952
  Deferred investment tax credits
    (Notes 1 and 2)                                 16,217             17,109
  Accrued Order No. 636 transition costs
    (Note 12)                                        5,980             13,480
  Accrued IPP settlement agreements
    (Notes 1 and 12)                                17,500              8,000
  Other deferred credits                             4,825              3,839
--------------------------------------------------------------------------------
    Total Deferred Taxes and Other                 258,549            250,380
--------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES (Note 12)                 --                 --
--------------------------------------------------------------------------------  
  TOTAL                                         $1,339,769         $1,347,639
--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
</TABLE>


The accompanying notes are an integral part of these statements.


                                       21

<PAGE>

CONSOLIDATED CASH FLOW STATEMENTS

<TABLE>
<CAPTION>
                                                      Year Ended December 31,
                                                     1995       1994     1993
--------------------------------------------------------------------------------
<S>                                                <C>       <C>      <C>
CASH FLOW FROM OPERATIONS:                             (Thousands of Dollars)
  Net Income                                       $38,573   $37,217  $44,815
  Adjustments to reconcile net income to
    net cash provided by operating activities:
    Depreciation and amortization                   37,131    35,938   34,571
    Deferred Federal income taxes (Note 2)           9,924      (188)     (39)
    Deferred investment tax credit (Note 2)           (892)     (895)    (963)
    Deferred and refundable fuel and gas costs      (6,606)    4,548    7,802
    Allowance for funds used during construction      (828)     (517)    (276)
    Other non-cash changes                           8,682     6,042   (8,055)
    Changes in certain current assets and
      liabilities:
    Accounts and gas marketing receivables, net
      and accrued utility revenue                    2,431    (3,101) (17,286)
    Materials and supplies                           4,941     1,226     (737)
    Prepaid property taxes                          (1,360)     (913)  (1,066)
    Prepayments and other current assets             2,414    (6,665)  (3,983)
    Operating and gas marketing accounts payable   (29,056)   24,162   19,407
    Accrued Federal income and other taxes          (3,899)   (3,637)   4,911
    Accrued interest                                (1,356)   (1,269)     779
    Refunds to customers                             3,638     9,472      753
    Other current liabilities                        6,601      (332)   2,336

    Other -- net                                    (7,123)   16,402    4,814
--------------------------------------------------------------------------------
      Net Cash Provided by Operations               63,215   117,490   87,783
--------------------------------------------------------------------------------
CASH FLOW FROM INVESTING ACTIVITIES:
  Additions to plant                               (55,030)  (60,542) (54,308)
  Temporary cash investments                           504      (392)    (569)
  Allowance for funds used during construction         828       517      276
--------------------------------------------------------------------------------
  Net Cash Used in Investing Activities            (53,698)  (60,417) (54,601)
--------------------------------------------------------------------------------

CASH FLOW FROM FINANCING ACTIVITIES:
  Proceeds from:
    Issuance of common stock (Note 5)                   --     3,868       --
    Issuance of long-term debt (Note 7)             44,048    55,000   75,000
  Retirement of:
    Preference and preferred stock (Note 6)         (1,384)   (1,384)  (1,384)
    Long-term debt                                 (63,471)  (57,688) (75,091)
    Capital lease obligations -- net (Note 11)        (518)     (479)    (443)
  Net borrowings (repayments) under short-term
    debt arrangements (Note 8)                      39,150   (16,800)   4,700

  Dividends on preferred and common stock          (38,259)  (37,765) (37,086)
--------------------------------------------------------------------------------
    Net Cash Used in Financing Activities          (20,434)  (55,248) (34,304)
--------------------------------------------------------------------------------
NET CHANGE IN CASH AND CASH EQUIVALENTS            (10,917)    1,825   (1,122)
Cash and Cash Equivalents at Beginning of Year      16,081    14,256   15,378
--------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS AT END OF YEAR          $  5,164   $16,081  $14,256
--------------------------------------------------------------------------------
SUPPLEMENTAL DISCLOSURE OF CASH FLOW
  INFORMATION
  Cash paid during the year for:
    Interest, net of amounts capitalized           $31,782   $33,134  $32,012
    Federal income taxes                           $15,575   $21,558  $27,020
--------------------------------------------------------------------------------
</TABLE>

The accompanying notes are an integral part of these statements.


                                       22

<PAGE>

NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS

NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES.

GENERAL

     Orange and Rockland Utilities, Inc. (the Company) and its wholly owned
utility subsidiaries, Rockland Electric Company (RECO) and Pike County Light &
Power Company (Pike),  are subject to regulation by the Federal Energy
Regulatory Commission (FERC) and various state regulatory authorities with
respect to their rates and accounting. Accounting policies conform to generally
accepted accounting principles, as applied in the case of regulated public
utilities, and are in accordance with the accounting requirements and rate-
making practices of the regulatory authority having jurisdiction. The
preparation of 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 and disclosure of
contingent 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. A description of the
significant accounting policies follows.

PRINCIPLES OF CONSOLIDATION

     The consolidated financial statements include the accounts of the Company,
all subsidiaries and the Company's pro rata share of an unincorporated joint
venture. All intercompany balances and transactions have been eliminated.

     The Company's non-utility subsidiaries are wholly owned land development,
gas marketing and gas production companies.

RATE REGULATION

     The Company and its subsidiaries are subject to rate regulation by the New
York Public Service Commission (NYPSC), the New Jersey Board of Public Utilities
(NJBPU), the Pennsylvania Public Utility Commission (PPUC) and the Federal
Energy Regulatory Commission (FERC). The consolidated financial statements of
the Company are based on generally accepted accounting principles, including the
provisions of statement of Financial Accounting Standards No. 71 (SFAS No. 71),
"Accounting for the Effects of Certain Types of Regulation," which gives
recognition to the rate-making and accounting practices of the regulatory
agencies. The principal effect of the rate-making process on the Company's
consolidated financial statements is that of the timing of the recognition of
incurred costs. If rate regulation provides reasonable assurance that an
incurred cost will be recovered in a future period by inclusion of that cost in
rates, SFAS No. 71 requires the capitalization of the cost. Regulatory assets
represent probable future revenue associated with certain incurred costs, as
these costs are recovered through the rate-making process. The following
regulatory assets were reflected in the Consolidated Balance Sheets as of
December 31, 1995 and 1994:

<TABLE>
<CAPTION>
                                     1995          1994
-------------------------------------------------------------
                                    (Thousands of Dollars)
<S>                                 <C>          <C>
Deferred Income Taxes (Note 2)       $ 72,631    $  73,261
Extraordinary Property Loss
  (Note 3)                              4,250       10,139
FERC Order No.636 Costs
  (Note 12)                             6,064       13,527
Deferred Revenue Taxes (Note 1)        15,596       16,888
Deferred Pension and Other
  Postretirement Benefits (Note 10)    10,422       10,505
Gas Take-or-Pay Costs (Note 12)         1,640        2,837
Revenue Decoupling Mechanism
  (Note 1)                             (2,485)       1,295
Deferred Plant Maintenance
  Costs (Note 1)                        4,944        4,699
Demand-Side Management Costs
  (Note 1)                               (445)         (96)
Deferred Fuel and Gas Costs
  (Note 1)                            (11,314)     (17,920)
IPP Settlement Agreements
  (Note 1)                             40,034       17,821
Other                                   5,778        5,107
-------------------------------------------------------------
  Total                              $147,115     $138,063
-------------------------------------------------------------
</TABLE>

     In March 1995, the Financial Accounting Standards Board issued SFAS No.
121, "Accounting for Impairment of Long-Lived Assets and Long-Lived Assets to be
Disposed Of". This Statement imposes criteria for the continued recognition of
regulatory assets by requiring that such assets be probable of future recovery
at each balance sheet date. The Company will adopt this standard on January 1,
1996. Based on the current regulatory structure in which the Company operates,
the adoption will not have any effect on the financial position or results of
operations of the Company. This conclusion may change in the future as
competitive factors influence wholesale and retail pricing in this industry.

UTILITY REVENUES

     Utility revenues are recorded on the basis of cycle billings rendered to
certain customers monthly and others bimonthly. Unbilled revenues are accrued at
the end of each month for  estimated energy usage since the last meter reading.
Under the Company's Revenue Decoupling Mechanism (RDM) agreement, New York's
electric revenues are recognized in the accompanying consolidated financial
statements based on established targets. The RDM also provides for the
reconciliation of Demand-Side Management expenditures and the adjustment of
certain operating costs. Any variation between actual results and the
established targets are deferred and recovered from or returned to customers
over a subsequent 12-month period.

     The level of revenues from gas sales in New York is subject to a weather
normalization clause that requires recovery from or refund to firm customers of
shortfalls or excesses of firm net revenues during a heating season due to
variation from normal weather, which is the basis for projecting base tariff
requirements.

FUEL COSTS

     The tariff schedules for electric and gas services in New York include
adjustment clauses under which fuel, purchased gas and certain purchased power
costs, above or below levels allowed  in approved rate schedules, are billed or
credited to customers up to approximately 60 days after the costs are incurred.
In accordance with regulatory commission policy, such costs,  along with the
related income tax effects, are deferred until billed to customers.

     A reconciliation of recoverable gas costs with billed gas revenues is done
annually, as of August 31, and the excess or deficiency is refunded to or
recovered from customers during a subsequent twelve-month period. The NYPSC
provides for a modified electric fuel adjustment clause requiring an 80%/20%
sharing between customers and shareholders of variations between actual and
forecasted fuel costs annually. The 20% portion of fluctuations from forecasted
costs is limited to a maximum of $1,762,000 annually. The fuel costs targets are
approved by the NYPSC for each calendar year following the Company's filing of
forecasted fuel costs. Tariffs for electric and gas service in Pennsylvania and
electric service in New Jersey contain adjustment clauses which utilize
estimated prospective energy costs on an annual basis. The recovery of such
estimated costs is made through equal monthly charges over the year of
projection. Any over or under recoveries are deferred and refunded or charged to
customers during the subsequent twelve-month period.

UTILITY PLANT

     Utility plant is stated at original cost. The cost of additions to, and
replacements of, utility plant include contracted work, direct labor and
material, allocable overheads, allowance for funds used during construction and
indirect charges for engineering and supervision. Replacement of minor items of
property and the cost of repairs are charged to maintenance expense. At the time
depreciable plant is retired or otherwise disposed of, the original cost,
together with removal cost less salvage, is charged to the accumulated provision
for depreciation.


                                       23

<PAGE>

DEPRECIATION

     For financial reporting purposes, depreciation is computed on the straight-
line method based on the estimated useful lives of the various classes of
property. Provisions for depreciation are equivalent to the following composite
rates based on the average depreciable plant balances at the beginning and end
of the year:

<TABLE>
<CAPTION>
Year Ended December 31,                    1995        1994         1993
---------------------------------------------------------------------------
---------------------------------------------------------------------------
<S>                                        <C>         <C>          <C>
Plant Classification:
  Electric                                 3.07%       3.05%        3.04%
  Gas                                      2.95%       2.80%        2.68%
  Common                                   6.64%       6.37%        6.07%
---------------------------------------------------------------------------
</TABLE>


JOINTLY OWNED UTILITY PLANT

     The Company has a one-third interest in the 1,200 megawatt Bowline Point
generating facility, which it owns jointly with The Consolidated Edison Company
of New York, Inc. The Company is the operator of the joint venture. Each
participant is entitled to its proportionate share of the energy produced. The
operation and maintenance expenses of the facility are shared proportionately,
based on the energy received from the plant by the partners.

     Under this agreement, each co-owner has an undivided interest in the
facility and is responsible for its own financing. The Company's interest in
this jointly owned plant consists primarily of the following:

<TABLE>
<CAPTION>
Year Ended December 31,                          1995           1994
---------------------------------------------------------------------------
---------------------------------------------------------------------------
                                                (Thousands of Dollars)
<S>                                            <C>             <C>
Electric Utility Plant in Service              $101,747        $98,171
Construction Work in Progress                     1,038          2,984
---------------------------------------------------------------------------
</TABLE>

FEDERAL INCOME TAXES

     The Company and its subsidiaries file a consolidated Federal income tax
return, and income taxes are allocated to each  company based on the taxable
income or loss of each.  Investment tax credits, which were available prior to
the Tax Reform Act of 1986, have been fully normalized and are being amortized
over the remaining useful life of the related property for financial reporting
purposes.

     The consolidated financial statements of the Company are stated under the
provisions of Statement of Financial Accounting Standards No. 109 (SFAS No. 109)
"Accounting for Income Taxes", which require the asset and liability method of
accounting for income taxes. SFAS No. 109 retains the requirement to record
deferred income taxes for temporary differences that are reported in different
years for financial reporting and tax purposes. The statement also requires that
deferred tax liabilities or assets be adjusted for the future effects of any
changes in tax laws or rates and that regulated enterprises recognize an
offsetting regulatory asset representing the probable future rate recoveries for
additional deferred tax liabilities. The probable future rate recoveries
(revenues) to be recorded take into consideration the additional future taxes
which will be generated by that revenue.

DEFERRED REVENUE TAXES

     Deferred revenue taxes represent the unamortized balance of an accelerated
payment of New Jersey Gross Receipts and Franchise Tax required by legislation
enacted effective June 1, 1991. In accordance with an order by the NJBPU, the
expenditure has been deferred and is being recovered in rates, with a carrying
charge of 7.5% on the unamortized balance, over a ten-year period. In addition,
certain New York State revenue taxes included in rate base are deferred and
amortized over a 12-month period following payment in accordance with the
requirements of the NYPSC.

IPP SETTLEMENT AGREEMENTS

     During 1994, the Company negotiated termination agreements with two of the
three Independent Power Producers (IPP) scheduled to provide electric generating
capacity and energy services to the Company in the late 1990's. On June 14,
1995, the Company entered into an agreement with Wallkill Generating Company,
L.P. (Wallkill Generating), which terminated its contract to construct and
operate a  gas-fired combined cycle generating facility and sell 95 Mw of
capacity and associated energy to the Company.

     At December 31, 1995, $40.0 million of termination costs associated with
these three settlement agreements have been deferred in accordance with
regulatory accounting procedures pending a determination of the recoverability
of the costs in rates. In January 1995, the New Jersey Board of Public Utilities
(NJBPU) Commissioners authorized the recovery of $0.9 million over a 12-month
period ending December 31, 1995 for the portion of one of the settlement
agreements applicable to New Jersey electric operations. An agreement for
recovery of approximately $10.3 million over a three-year period applicable to
New Jersey electric operations has been reached. Approval by the NJBPU is
expected in February 1996. The recovery of the portion of termination costs
applicable to New York operations, which amounted to approximately $29.4 million
at December 31, 1995, is being addressed in the Company's current electric base
rate proceeding before the NYPSC. The Administrative Law Judge, as part of his
January 25, 1996 Recommended Decision, recommended that the NYPSC allow full
recovery of termination costs applicable to New York operations over a three-
year period. Recovery of these termination costs is still subject to NYPSC
approval. A final NYPSC decision is expected by April 1996. Management believes
that the termination costs were prudently incurred and therefore are probable of
being fully recoverable in rates.

DEFERRED PLANT MAINTENANCE COSTS

     The Company utilizes a silicone injection procedure as part of its
maintenance program for residential underground electric cable in order to
prevent premature failures and ensure the realization of the expected useful
life of the facilities. In 1992 the FERC issued an accounting order that
required the cost of this procedure to be treated as maintenance expense rather
than as a plant addition. The Company requested deferred accounting for these
expenditures from the NYPSC and NJBPU in order to properly match the cost of the
procedure with the periods benefited. In 1994 the NYPSC approved the deferred
accounting request and authorized a ten-year amortization. On January 12, 1996,
the NJBPU authorized these costs to be capitalized until the next base rate
case.

RESERVE FOR CLAIMS AND DAMAGES

     Costs arising from workers' compensation claims, property damage, general
liability and unusual production plant repair costs are partially self-funded.
Provisions for the reserves are based on experience, risk of loss and the rate-
making practices of regulatory authorities.

SALE OF BROADCAST PROPERTIES

     On September 8, 1994, the Company adopted a formal plan to sell the six
radio broadcasting properties operated by a wholly owned indirect subsidiary,
Atlantic Morris Broadcasting, Inc. (AMB), and AMB subsequently entered into
contracts for the sale of the stations. At December 31, 1995, all sales have
been completed. There is a Petition for Reconsideration outstanding on one of
the sales. However, this petition has been rejected on two previous occasions
and the Company believes this current petition will be rejected and have no
impact on sale transactions. The sale of the properties did not have material
effect on the Company's financial statements.

     Operating results of $(1,188,000), $(484,000) and $(804,000) for the years
ended December 31, 1995, 1994, and 1993, respectively, for the radio broadcast
properties are included in Other Income and Deductions in the accompanying
Consolidated Statements of Income and Retained Earnings.


                                       24

<PAGE>

RECLASSIFICATIONS

     Certain amounts from prior years have been reclassified to conform with the
current year presentation.


NOTE 2. FEDERAL INCOME TAXES.

     The Internal Revenue Service (IRS) is currently examining the Company's tax
returns for 1990, 1991 and 1992. Notification of all findings for these years
has not yet been received.

     The components of Federal income taxes are as follows:

<TABLE>
<CAPTION>
Year Ended December 31,                      1995       1994        1993
---------------------------------------------------------------------------
---------------------------------------------------------------------------
<S>                                       <C>          <C>        <C>
(Thousands of Dollars)
Charged to operations:
  Current                                  $18,078     $24,415    $26,332
  Deferred-net                               7,828         262         86

  Amortization of investment tax credit       (127)       (137)      (193)
---------------------------------------------------------------------------
                                            25,779      24,540     26,225
---------------------------------------------------------------------------
Charged to other income:
  Current                                   (3,160)     (3,042)    (2,630)
  Deferred-net                               2,096        (450)      (125)
  Amortization of investment tax credit       (765)       (758)      (770)
---------------------------------------------------------------------------
                                            (1,829)     (4,250)    (3,525)
---------------------------------------------------------------------------
Total                                      $23,950     $20,290    $22,700
---------------------------------------------------------------------------
</TABLE>

     The tax effect of temporary differences which gave rise to deferred tax
assets and liabilities are as follows:

<TABLE>
<CAPTION>
As of December 31,                                   1995          1994
---------------------------------------------------------------------------
                                                    (Thousands of Dollars)
<S>                                                 <C>         <C>
Liabilities:
  Accelerated depreciation                          $180,954    $177,362
  Other                                               33,073      30,590
---------------------------------------------------------------------------
     Total liabilities                               214,027     207,952
---------------------------------------------------------------------------
Assets:
  Employee benefits                                  (14,902)    (15,269)
  Deferred fuel costs                                 (1,601)     (4,784)
  Other                                              (14,128)    (14,592)
---------------------------------------------------------------------------
     Total assets                                    (30,631)    (34,645)
---------------------------------------------------------------------------
Net Liability                                       $183,396    $173,307
---------------------------------------------------------------------------
</TABLE>

     Reconciliation of the difference between Federal income tax expenses and
the amount computed by applying the prevailing statutory income tax rate to
income before income taxes is as follows:

<TABLE>
<CAPTION>
Year Ended December 31,                            1995    1994       1993
---------------------------------------------------------------------------
---------------------------------------------------------------------------
                                                     (% of Pre-tax Income)
<S>                                                <C>     <C>       <C>
Statutory tax rate                                 35%     35%        35%
Reduction in computed taxes resulting from:
  Amortization of investment tax credits           (1)     (2)        (1)
  Cost of removal                                  (2)     (1)        (2)
  Additional depreciation deducted for
    book purposes                                   5       5          4

  Other                                            (2)     (2)        (3)
---------------------------------------------------------------------------
     Effective Tax Rate                            35%     35%        33%
---------------------------------------------------------------------------
</TABLE>

NOTE 3. STERLING NUCLEAR PROJECT.

     Costs associated with the Sterling Nuclear Project, which was abandoned in
1980, and in which the Company was a 33% participant, are recorded in Deferred
Debits--Extraordinary Property Loss.

     The Company has been authorized by the NYPSC to recover all costs
associated with the Sterling Nuclear Project. An annual amortization has been
approved which includes a return on investment equal to the Company's current
overall rate of return. Amortization of project costs applicable to New York
operations will be completed by March 1996. The NJBPU had approved a twenty-year
amortization, which commenced June 23, 1982, of costs (excluding a return on the
unamortized balance) attributable to the Company's subsidiary, RECO.

     At December 31, 1995 and 1994, the unamortized Sterling Project costs which
have been approved for amortization and recovery, before reduction for deferred
taxes, amounted to $4.6 million and $10.8 million, respectively. Approximately
$3.9 million and $4.7 million of such recoverable costs at December 31, 1995 and
December 31, 1994, respectively, are attributable to RECO and are not subject to
an earned return on the unamortized balance.

NOTE 4. RETAINED EARNINGS.

     Various restrictions on the availability of retained earnings of RECO for
cash dividends are contained in, or result from, covenants in indentures
supplemental to that company's Mortgage Trust Indenture. Approximately
$7,501,600 at December 31, 1995 and 1994 was so restricted.

NOTE 5. CAPITAL STOCK OTHER THAN REDEEMABLE PREFERRED STOCK.

     The table below summarizes the changes in Capital Stock, issued and
outstanding, for the years 1993, 1994 and 1995.
<TABLE>
<CAPTION>

                                          (B)               (C)
                                     Non-Redeemable    Non-Redeemable
                         (A)          Cumulative         Cumulative
                       Common          Preferred         Preference      Capital
                        Stock            Stock             Stock          Stock
                   ($5 par value)  ($100 par value)    (no par value)    Premium
                 Shares   Amount*  Shares    Amount*   Shares Amount*    Amount*
--------------------------------------------------------------------------------
<S>           <C>         <C>      <C>      <C>        <C>      <C>     <C>
Balance
  12/31/92:   13,531,191  $67,656  428,443  $42,844    14,189   $462    $130,298
  Conversions        864        4                        (599)   (19)         15
--------------------------------------------------------------------------------
Balance
  12/31/93:   13,532,055   67,660  428,443   42,844    13,590    443     130,313
  Sales          120,041      601                                          3,267
  Conversions        817        4                        (565)   (19)         15
--------------------------------------------------------------------------------
Balance
  12/31/94:   13,652,913   68,265  428,443   42,844    13,025    424     133,595
  Conversions        700        3                        (486)   (15)         12
--------------------------------------------------------------------------------
Balance
  12/31/95:   13,653,613  $68,268  428,443  $42,844    12,539   $409    $133,607
--------------------------------------------------------------------------------
  Shares
  Authorized  15,000,000           820,000          1,500,000
--------------------------------------------------------------------------------
*(in thousands)
</TABLE>

     (A) At December 31, 1995, 18,432 shares of common stock were reserved for
conversion of preference stock.
     (B) Non-Redeemable Preferred Stock (cumulative):

<TABLE>
<CAPTION>
                               Par Value            Callable
                          -------------------
            Shares            December 31,         Redemption
Series    Outstanding     1993, 1994 and 1995    Price Per Share
----------------------------------------------------------------------
                         (Thousands of Dollars)
<S>       <C>            <C>                     <C>
A,4.65%      50,000           $  5,000               $104.25
B,4.75%      40,000              4,000               $102.00
D,4.00%       3,443                344               $100.00
F,4.68%      75,000              7,500               $102.00
G,7.10%     110,000             11,000               $101.00
H,8.08%     150,000             15,000               $102.43
----------------------------------------------------------------------
            428,443            $42,844
----------------------------------------------------------------------
</TABLE>

     This stock is not subject to mandatory redemption, but rather is subject to
redemption, at any time, solely at the option of the Company on 30 days' minimum
notice upon payment of the redemption price, plus accrued and unpaid dividends
to the date fixed for redemption. Furthermore, the preferred stock is superior
to cumulative preference stock and common stock with respect to dividends and
liquidation rights.

     (C) The Non-Redeemable $1.52 Convertible Cumulative Preference Stock,
Series A, is redeemable at the option of the Company on 30 days' minimum notice
upon payment of the redemption price, plus accrued and unpaid dividends. The
redemption price per share is $32.50, plus accrued and unpaid dividends to the
date fixed for redemption. This stock ranks junior to cumulative preferred stock
and superior to common stock as to dividends and liquidation rights.
Furthermore, this stock is convertible, at the option of the shareholder, into
common stock at the ratio of 1.47 shares of common stock for each share of
preference stock, subject to adjustment.


                                       25

<PAGE>

NOTE 6. REDEEMABLE PREFERRED STOCK.

     The table below summarizes the changes in Redeemable Cumulative Preferred
Stock, issued and outstanding, for the years 1993, 1994 and 1995.

<TABLE>
<CAPTION>
                                                  ($100 par value)
-----------------------------------------------------------------------
                                               Shares           Amount*
-----------------------------------------------------------------------
<S>                                           <C>               <C>
Balance 12/31/92:                              69,264           $6,926
  Redemptions                                 (13,842)          (1,384)
-----------------------------------------------------------------------
Balance 12/31/93:                              55,422            5,542
  Redemptions                                 (13,842)          (1,384)
-----------------------------------------------------------------------
Balance 12/31/94:                              41,580            4,158
  Redemptions                                 (13,842)          (1,384)
-----------------------------------------------------------------------
Balance 12/31/95:                              27,738           $2,774
-----------------------------------------------------------------------
Shares Authorized                             180,000
-----------------------------------------------------
*(in thousands)
</TABLE>

     The Redeemable Cumulative Preferred Stock, Series I, 8 1/8%, is redeemable
in whole or in part at the option of the Company on 30 days' minimum notice at
the redemption price, plus accrued and unpaid dividends to the date fixed for
redemption. The redemption price per share is $101 through January 1, 1997, and
$100 thereafter.

     The preferred stock is superior to the cumulative preference stock and
common stock with respect to dividends and liquidation rights. A sinking fund
provision requires that the Company, on each December 31, call for the
redemption and retirement of 13,842 shares at $100 per share, provided, however,
that the Company will call for redemption and retire on December 31, 1997, the
remaining shares outstanding at the redemption price of $100 per share plus
accrued and unpaid dividends to the date fixed for redemption. The redemption
requirement for each year following 1995 is as follows: $1,384,200 in 1996 and
$1,389,600 at maturity in 1997.

NOTE 7. LONG-TERM DEBT.

     Under the terms of the Company's First Mortgage Indenture and the
indentures supplemental thereto, and relative to all series of First Mortgage
Bonds, the Company on May 1 of each year is required to make annual sinking fund
payments equal to 1% of the maximum amount of bonds outstanding during the
preceding calendar year. The Company has satisfied such requirements through the
year 1995 by allocating an amount of additional property and expects to continue
such practice in succeeding years. Pike is required, pursuant to its First
Mortgage Indenture, to make annual sinking fund payments in the amount of $9,500
on July 15 of each year, with respect to its Series "A" Bonds. The sinking fund
requirements of Pike for 1995 were satisfied by the allocation of an amount of
additional property and Pike expects to continue such practice in succeeding
years.

     On July 27, 1995, the New York State Energy Research and Development
Authority (NYSERDA) issued, on behalf of the Company, $44 million of variable
rate Pollution Control Refunding Revenue Bonds due August 1, 2015 (the 1995
Bonds). The proceeds from the issuance of the 1995 Bonds, together with other
Company funds, were used to refund, on August 20, 1995, the $44 million NYSERDA
9% Pollution Control Revenue Bonds, 1985 Series issued on behalf of the Company.

     Two issues of First Mortgage Bonds matured on August 15, 1995; the
Company's $17 million Series H, 4 7/8% and RECO's $2 million Series C, 4 5/8%.

     Details of long-term debt at December 31, 1995 and 1994 are as follows:

<TABLE>
<CAPTION>
December 31,                                      1995          1994
-----------------------------------------------------------------------
-----------------------------------------------------------------------
                                                 (Thousands of Dollars)
<S>                                           <C>           <C>
Orange and Rockland Utilities,Inc.:
  First Mortgage Bonds:
    Series H, 4 7/8% due Aug. 15, 1995        $        --   $  17,000
    Series I, 6 1/2% due Oct. 1, 1997              23,000      23,000
  Promissory Notes (unsecured):
    6.9% - 12.9% due through July 15, 1999             48          25
    9% due Aug. 1, 2015                                --      44,000
    6.09% due Oct. 1, 2014 (a)                     55,000      55,000
    Variable due Aug. 1, 2015 (b)                  44,000          --
  Debentures:
    Series A, 9 3/8% due Mar. 15, 2000             80,000      80,000
    Series B, 6 1/2% due Oct. 15, 1997             55,000      55,000
    Series C, 6.14% due Mar. 1, 2000               20,000      20,000
    Series D, 6.56% due Mar. 1, 2003               35,000      35,000
Rockland Electric Company:
  First Mortgage Bonds:
    Series C, 4 5/8% due Aug. 15, 1995                 --       2,000
    Series H, 9.59% due July 1, 2020               20,000      20,000
    Series I, 6% due July 1, 2000                  20,000      20,000
Pike County Light & Power Company:
  First Mortgage Bonds:
    Series A, 9% due July 15, 2001                    884         884
    Series B, 9.95% due Aug. 15, 2020               1,800       1,800
Diversified Operations:
  Mortgage (secured)
    8 1/2% due through June 18, 1999                5,405       5,575
    Secured Notes 8 1/2% due thru Aug. 31, 1998        --         277
-----------------------------------------------------------------------

                                                  360,137     379,561

    Less: Amount due within one year                  192      19,392

                                                  359,945     360,169

    Unamortized discount on long-term debt           (209)       (547)
    Total Long-Term Debt                         $359,736    $359,622
-----------------------------------------------------------------------
</TABLE>


     (a) The Company's $55 million Promissory Note was issued in connection with
NYSERDA's variable rate Pollution Control Refunding Revenue Bonds (Orange and
Rockland Utilities, Inc. Projects), 1994 Series A (1994 Bonds). Pursuant to an
interest rate swap agreement, the Company pays interest at a fixed rate of 6.09%
to a swap counterparty and receives a variable rate of interest in return which
is identical to the variable rate on the 1994 Bonds. The result is to
effectively establish a fixed rate of interest on the 1994 Bonds of 6.09%.

     (b) The Company's $44 million Promissory Note was issued in connection with
the 1995 Bonds. The average interest rate on the 1995 Bonds was 3.63% for 1995.
The interest rate is adjusted weekly, unless converted to a fixed rate.

     The aggregate amount of debt maturities, which will be satisfied by cash
payments and sinking fund requirements (allocation of additional property) for
each of the five years following 1995 is as follows: 1996--$430,000; 1997--
$78,208,000; 1998--$133,000; 1999--$4,950,000; 2000--$120,010,000.

     Substantially all of the utility plant and other physical property is
subject to the liens of the respective indentures securing the First Mortgage
Bonds of the Company and its utility subsidiaries.

     Investments in the Company's wholly owned utility subsidiaries, costing
$11,828,700, which have been eliminated from the consolidated balance sheet, are
pledged under the Second Supplemental Indenture to the Company's First Mortgage
Indenture.


                                       26

<PAGE>

NOTE 8. CASH AND SHORT-TERM DEBT.

     The Company considers all cash and highly liquid debt instruments purchased
with a maturity date of three months or less to be cash and cash equivalents for
the purposes of the Consolidated Financial Statements.

     At December 31, 1995, the Company and its utility subsidiaries had
unsecured bank lines of credit with nine commercial banks aggregating $64.5
million. In most cases the annual fees equal to one-eighth of 1% are paid to the
banks for such lines of credit. The Company may borrow under the lines of credit
through the issuance of promissory notes to the banks at their prevailing
interest rate for prime commercial borrowers. The Company, however, utilizes
such lines of credit to fully support commercial paper borrowings, which are
issued through dealers at the prevailing interest rate for prime commercial
paper. The aggregate amount of borrowings through the issuance of promissory
notes and commercial paper cannot exceed the aggregate lines of credit. In
addition, NORSTAR Energy Limited Partnership (NORSTAR), a subsidiary of RECO,
maintains a $20 million line of credit with one commercial bank under which
there were $6.0 million of letters of credit outstanding at December 31, 1995.
Additionally, NORSTAR had $7.3 million of notes outstanding under this line of
credit. Annual fees on this credit line are equal to one-quarter of one percent
on the unused balance in addition to an initial fee of $100,000. Borrowings
under this line are made at rates based on various financial indices, as
determined by the borrower at the time of borrowing plus a premium.

     All borrowings for 1995, 1994 and 1993 had maturity dates of three months
or less.

     Information regarding short-term borrowings during the past three years is
as follows:

<TABLE>
<CAPTION>
                                              1995     1994    1993
-----------------------------------------------------------------------
-----------------------------------------------------------------------
                                              (Millions of Dollars)
<S>                                         <C>      <C>     <C>
Weighted average interest rate at year-end    6.5%     6.4%    3.6%
Amount outstanding at year-end              $68.6    $29.4   $46.2
Average amount outstanding for the year     $43.4    $31.3   $35.3
Daily weighted average interest rate
  during the year                             6.5%     4.5%    3.3%
Maximum amount outstanding
  at any month-end                          $69.6    $42.9   $46.2
-----------------------------------------------------------------------
</TABLE>

NOTE 9. FAIR VALUE OF FINANCIAL INSTRUMENTS.

FINANCIAL ASSETS AND LIABILITIES

     For the Company, financial assets and liabilities consist principally of
cash and cash equivalents, short-term debt, commercial paper, long-term debt and
redeemable preferred stock. The methods and assumptions used to estimate the
fair value of each class of financial assets and liabilities for which it is
practicable to estimate that value are as follows:

     Cash equivalents and temporary cash investments--The carrying amount
reasonably approximates fair value because of the short maturity of those
instruments.

     Long-term debt--The fair value of the Company's long-term debt is estimated
based on the quoted market prices for the same or similar issues.

     Notes payable and commercial paper--The carrying amount reasonably
approximates fair value because of the short maturity of those instruments.

     Redeemable preferred stock--The fair value of the Company's redeemable
preferred stock is estimated based on the quoted market prices for the same or
similar issues.

<TABLE>
<CAPTION>
                                    1995               1994
-----------------------------------------------------------------------
                             Carrying   Fair     Carrying   Fair
                              Amount   Amount     Amount   Amount
-----------------------------------------------------------------------
                                      (Thousands of Dollars)
<S>                         <C>        <C>       <C>       <C>

Cash and cash equivalents     $5,164    $5,164    $16,081  $16,081
Temporary cash investments     1,335     1,335      1,839    1,839
Long-term debt               360,137   349,694    379,561  371,730
Notes payable
  and commercial paper        68,550    68,550     29,400   29,400
Redeemable preferred stock     2,774     2,820      4,158    4,136
-----------------------------------------------------------------------
</TABLE>

OFF BALANCE SHEET AND DERIVATIVE FINANCIAL INSTRUMENTS

     The Company utilizes certain off balance sheet, derivative financial
instruments. Information regarding such instruments is as follows:

     Swap Agreement--In connection with the issuance of the 1994 Bonds, the
Company entered into a single interest rate swap agreement during 1992. The
purpose of the swap agreement, which became effective on October 1, 1994, was to
take advantage of the favorable interest rates which existed during 1992. Under
the terms of the interest rate swap agreement, the Company pays interest at a
fixed rate of 6.09% to a swap counterparty and receives a variable rate of
interest in return which is identical to the variable rate payment on the 1994
Bonds made pursuant to an indenture of trust dated August 15, 1994. The result
is to effectively fix the interest rate on the 1994 Bonds at 6.09%. There were
no gains or losses due to the execution of the Swap Agreement. The terms and
conditions of the Swap Agreement are specific to the financing described. As a
result, no market price is available. Under certain circumstances, although none
are anticipated, the agreement may be terminated. The fair value of the
agreement is the amount which one counterparty may be required to pay the other
upon early termination. If the agreement had been terminated on December 31,
1995, the Company would have been required to make a payment of approximately
$7,300,000 to the Swap counterparty.

     Gas Futures Contracts--The Company's Gas Marketing subsidiary utilizes
certain off balance sheet derivative financial instruments, principally natural
gas futures contracts, commodity price swap agreements and purchase options to
reduce exposure to changes in the price of natural gas. These transactions are
accounted for as hedges in accordance with Statement of Financial Accounting
Standards No. 80 "Accounting for Futures Contracts". Gains and losses on futures
contracts and purchased options, and payments or receipts under swap agreements,
are recognized when the underlying gas is sold, purchased or transported, and
are reflected as cash flows from operations in the accompanying Statement of
Cash Flows at that time. Futures contracts outstanding at December 31, 1995 and
December 31, 1994, amounted to 449 contracts purchased and 257 net contracts
purchased (4,145 contracts purchased and 3,888 contracts sold), respectively.
The related margin deposits with brokers at December 31, 1995 and December 31,
1994, amounted to $2,202,542 and $672,000, respectively. The underlying futures
contracts as of December 31, 1995 and December 31, 1994, are of varying
durations, none of which extend beyond September 1997 and November 1995,
respectively. The fair value of the open futures contracts at December 31, 1995
and the amount the Company would receive if these were settled on that day is
approximately $995,000. The fair value of the open futures contracts at December
31, 1994 and the amount the Company would have been required to pay to settle
those contracts was approximately $30,000. Deferred gains at December 31, 1995,
relating to futures contracts were $2,035,000. Deferred losses at December 31,
1994, relating to futures contracts were $534,000 and relating to purchased
option contracts were $41,270.


                                       27

<PAGE>

     Swap transactions were entered into in order to eliminate the commodity
price risk relating to long-term fixed price sales commitments and variable
price purchase commitments. The swap agreements require payments to (or receipt
from) the broker based on the differential between a fixed and variable price
for natural gas. Under a long-term swap agreement the Company hedges 4.7 BCF of
natural gas to be purchased and delivered over the five years ended October
1999. The related margin deposits at December 31, 1995 and December 31, 1994
amounted to $1,500,000 and $1,521,000, respectively. Margin deposits in 1995
consist of letters of credit and in 1994 they consist of cash and letters of
credit. In March 1995, the Company and the broker revised the formula for
calculating margin requirements. If the revised formula was used at December 31,
1994, the margin deposits would have been $500,000. The Company would be
required to pay $1,232,000 and $1,021,000 to settle these contracts at December
31, 1995 and December 31, 1994, respectively. Short-term swap transactions were
entered into to hedge 2.3 BCF of natural gas to be purchased and delivered
during the months of January and February 1996. At December 31, 1995, there were
no margin deposits for the short-term swap transactions. The Company would
receive $190,000 to liquidate the short-term swap positions at December 31,
1995.

     The Company is exposed to credit risk in the event of nonperformance by
counter parties to swap contracts, as well as nonperformance by the counter
parties of the transaction which they hedge. The Company believes that the
credit risk related to the futures and swap contracts is no greater than that
associated with the primary contracts which they hedge, as these contracts are
with major investment grade financial institutions, and that the elimination of
the commodity price risk lowers the Company's overall business risk.

NOTE 10. PENSION AND POSTRETIREMENT BENEFITS.

PENSION BENEFITS

     The Company maintains a non-contributory defined benefit retirement plan,
covering substantially all employees. The plan calls for benefits, based
primarily on years of service and average career compensation, to be paid to
eligible employees at retirement. For financial reporting purposes, pension
costs are accounted for in accordance with the requirements of Statement of
Financial Accounting Standards No. 87 (SFAS No. 87), "Employers' Accounting for
Pensions".

     SFAS No. 87 results in a difference in the method of determining pension
costs for financial reporting and funding purposes. Plan valuation for funding
and income tax purposes is prepared on the unit credit cost method, which makes
no assumptions as to future compensation levels. In contrast, the projected unit
credit cost method required for accounting purposes by SFAS No. 87 reflects
assumptions as to future compensation levels. The Company's policy is to fund
the pension costs determined by the unit credit cost method subject to the IRS
funding limitation rules. For rate-making purposes, pension expense determined
under SFAS No. 87 is reconciled with the amount provided in rates for pensions.
Any difference is deferred for subsequent recovery or refund.

     Net periodic pension expense calculated pursuant to the requirements of
SFAS No. 87 for the years 1995, 1994 and 1993 includes the following components:

<TABLE>
<CAPTION>
December 31,                               1995      1994      1993
-----------------------------------------------------------------------
-----------------------------------------------------------------------
                                               (Thousands of Dollars)
<S>                                     <C>       <C>       <C>
Service cost-benefits earned during
  year                                  $  5,151  $  6,250  $  5,690
Interest cost on projected benefit
  obligation                              14,996    14,132    12,915
Actual return on plan assets             (37,863)    2,634   (19,383)

Net deferral and capitalized              20,129   (18,426)    5,014
-----------------------------------------------------------------------
Net Pension Expense                     $  2,413  $  4,590  $  4,236
-----------------------------------------------------------------------
</TABLE>

     The following table sets forth, pursuant to the requirements of SFAS No.
87, the plan's funded status and amounts recognized in the Consolidated Balance
Sheets at December 31, 1995 and 1994. Plan assets are stated at fair market
value and are composed primarily of common stocks and investment
grade debt securities.

<TABLE>
<CAPTION>
December 31,                                        1995         1994
-----------------------------------------------------------------------
-----------------------------------------------------------------------
                                                 (Thousands of Dollars)
<S>                                              <C>         <C>
Actuarial present value of benefit
  obligations:
  Vested                                         $(178,903)  $(154,980)
  Nonvested                                        (15,719)    (13,644)
-----------------------------------------------------------------------
Accumulated benefit obligation                   $(194,622)  $(168,624)
-----------------------------------------------------------------------
Projected benefit obligation                     $(203,956)  $(181,625)
Plan assets at fair market value                   205,342     172,835
-----------------------------------------------------------------------
Excess of plan assets over projected
  benefit obligation                                 1,386      (8,790)
Unamortized net transition asset at adoption
  of SFAS No. 87 being amortized over 15 years      (6,681)     (7,795)
Unrecognized prior service costs                    32,455      35,425
Unrecognized net gain                              (55,649)    (49,137)
-----------------------------------------------------------------------
Accrued Pension Cost                             $ (28,489)  $ (30,297)
-----------------------------------------------------------------------
</TABLE>

     The expected long-term rate of return on plan assets, the weighted average
discount rate and the annual rate of increase in future compensation assumed in
determining the projected benefit obligation were 8.0%, 7.5% and 2.5%; and 8.0%,
8.5% and 3.5%, respectively, for 1995 and 1994.

POSTRETIREMENT BENEFITS

     In addition to providing pension benefits, the Company and its subsidiaries
provide certain health care and life insurance benefits for retired employees.
Employees retiring from the Company on or after having attained age 55 who have
rendered at least 10 years of service are entitled to postretirement health care
coverage.

     Pursuant to the provisions of Statement of Financial Accounting Standards
No. 106 (SFAS No. 106), "Employers' Accounting for Postretirement Benefits Other
Than Pensions", which established the accounting and financial reporting
standards for postretirement benefits other than pensions, the Company is
required to accrue the estimated future cost of postretirement health and non-
pension benefits during the years that employees render the necessary service,
rather than recognizing the cost of such benefits after employees have retired
and when the benefits are actually paid. Deferred accounting for any difference
between the expense charge required under SFAS No. 106 and the current rate
allowance has been authorized by the NYPSC for the Company's New York electric
and gas operations. A similar procedure has been adopted by the NJBPU for the
operations in that state.

     The NYPSC allows the Company to recover SFAS No. 106 costs applicable to
New York electric operations. Rate recovery of SFAS No. 106 costs applicable to
the Company's New York gas operations has been agreed to as part of the
Investigation Stipulation Settlement, pending NYPSC approval. New Jersey
electric operations will be addressed in future rate filings.

     In order to provide funding for active employees' post- retirement
benefits, the Company has established Voluntary Employees' Beneficiary
Association (VEBA) trusts for  collectively bargained employees and management
employees. Contributions to the VEBA trusts are tax deductible, subject  to
limitations contained in the Internal Revenue Code. The Company's policy is to
fund postretirement health and life  insurance costs to the extent recoveries
are realized for these costs through rates. During 1995, the Company contributed
$8.6 million to the Trust Funds. Rate recoveries and billings to others totaled
$3.9 million in 1995 and $4.0 million 1994.  

 As permitted by SFAS No. 106, the Company has elected to amortize the 
accumulated postretirement benefit obligation at


                                       28

<PAGE>

the date of adoption of the accounting standard, January 1, 1993, over a 20 year
period. This transition obligation totaled $57.2 million. The following table
sets forth the plan's funded status, reconciled with amounts recognized in the
Company's financial statements at December 31, 1995 and December 31, 1994:

<TABLE>
<CAPTION>
                                                1995         1994
-----------------------------------------------------------------------
-----------------------------------------------------------------------
                                              (Thousands of Dollars)
<S>                                           <C>            <C>
Accumulated postretirement benefit
  obligation:
  Fully eligible active employees             $(18,989)     $(19,574)
  Other active employees                       (31,644)      (25,248)
  Retirees                                     (26,976)      (20,677)
-----------------------------------------------------------------------
    Total benefit obligation                   (77,609)      (65,499)

Plan assets at fair value                        8,926           -0-
-----------------------------------------------------------------------

Accumulated postretirement obligation
  in excess of plan assets                     (68,683)      (65,499)
Unrecognized experience net (gain) loss          8,639          (736)
Unrecognized transition obligation              47,185        51,522
-----------------------------------------------------------------------
Accrued Postretirement Benefit Cost           $(12,859)     $(14,713)
-----------------------------------------------------------------------
</TABLE>

     The components of net periodic postretirement benefit cost for the years
ended December 31, 1995, 1994 and 1993 are as follows:

<TABLE>
<CAPTION>
                                              1995     1994    1993
-----------------------------------------------------------------------
-----------------------------------------------------------------------
                                              (Thousands of Dollars)
<S>                                          <C>     <C>      <C>
Service cost                                 $1,586  $1,817   $1,535
Interest cost                                 5,622   5,198    4,598
Return on plan assets                          (319)    -0-      -0-
Amortization of transition obligation         2,790   2,861    2,861
Net losses/(gains)                              529     553      -0-
Deferred and capitalized                     (3,424) (4,480)  (6,719)
-----------------------------------------------------------------------
Net Expense                                  $6,784  $5,949   $2,275
-----------------------------------------------------------------------
</TABLE>

     The calculation of the actuarial present value of benefit obligations at
December 31, 1995 assumes a discount rate of 7.5% and health care cost trend
rates of 8.0% for medical costs and 11.0% for prescription drugs in 1996,
decreasing through 2002 to a rate of 5.0%. If the health care trend rate
assumptions were increased by 1 percent, the accumulated postretirement benefit
obligation would be increased by approximately $8.3 million. The effect of this
change on the sum of the service cost and interest cost would be an increase of
$1.1 million. 1994 assumed a discount rate of 8.5% and health care cost trend
rates of 8.5% for medical costs and 12% for prescription drugs in 1995,
decreasing through 2002 to a rate of 5.0%.

OTHER

     The Company and two of its wholly owned non-utility subsidiaries
established a Subsidiary Equity Incentive Plan, which expired in 1995, in which
plan participants were entitled to certain rights measured as Performance Units.
Each Performance Unit gave the plan participant the opportunity to receive an
incentive award of up to 3-5% of the net increase, subject to certain
restrictions, in the value of the Company's investment in the participating
subsidiaries over its initial investment.

     Incentive awards granted during 1995, 1994 and 1993 were $1.3 million, $0.6
million and $0, respectively. The Company's obligation for these incentive
awards is fully provided for.

NOTE 11. LEASES.

     The future minimum rental commitments under the Company's noncancellable
operating leases are as follows:

<TABLE>
<CAPTION>
                                                    Noncancellable
                                                      Operating
                                                        Leases
-----------------------------------------------------------------------
-----------------------------------------------------------------------
                                                 (Thousands of Dollars)
<S>                                              <C>
1996                                               $   4,710
1997                                                   3,896
1998                                                   3,600
1999                                                   3,286
2000                                                   3,127
All years thereafter                                  26,834
-----------------------------------------------------------------------
Total                                                $45,453
-----------------------------------------------------------------------
</TABLE>

     Rental expense for 1995, 1994 and 1993 was $6.0 million, $5.3 million and
$6.0 million, respectively.


NOTE 12. COMMITMENTS AND CONTINGENCIES.

CONCENTRATION OF CREDIT RISK

     Financial instruments which potentially subject the Company to
concentrations of credit risk, as defined by Statement of Financial Accounting
Standards No. 105 "Financial Instruments with Concentrations of Credit Risk",
consist principally of temporary cash investments, accounts receivable and gas
marketing accounts receivables. The Company places its temporary cash
investments with high quality financial institutions. Concentrations of credit
risk with respect to accounts receivable are limited due to the Company's large,
diverse customer base within its service territory. With respect to gas
marketing operations, the customer base consists of a large diverse group of
users of natural gas across the United States, with the Company's credit risk
being dependent on overall economic conditions. Therefore, as of December 31,
1995, the Company had no significant concentrations of credit risk.

CONSTRUCTION PROGRAM

     Under the construction program of the Company and its subsidiaries, it is
estimated that expenditures (excluding AFUDC) of approximately $52.8 million
will be incurred during 1996. Construction expenditures, including cost of
removal and salvage, amounted to $56.8 million for 1995.

GAS SUPPLY AND STORAGE CONTRACTS

     The Company has long-term contracts for firm supply, transportation and
storage of gas. The Company's obligations under these contracts for the five
years following 1995 are as follows: 1996--$68,600,000; 1997--$69,400,000; 
1998--$69,400,000; 1999--$72,300,000 and 2000--$69,300,000.

     On July 1, 1995, pursuant to a settlement agreement between the Company and
the NYPSC, all issues concerning the Company's take-or-pay liability have been
resolved. The Company has been granted permission to pass back the remaining
deferred amounts plus accrued interest. As of December 31, 1995, the Company has
deferred $1.6 million of these costs remaining on the books of the Company.

     On April 8, 1992, the FERC issued Order No. 636. The rule required
significant changes to the structure of the natural gas industry, and more
specifically, to the manner in which pipelines provide service. Order No. 636
changed the manner in which the Company obtains its gas supplies by unbundling
the transportation, storage and supply services offered by interstate gas
pipelines into separate components. During 1993, the Company successfully
completed the process of acquiring its own gas supply and assumed direct
responsibility for its gas acquisition and transportation. While the FERC's
objective is to restructure the industry to promote competition among gas
suppliers to ensure supply at the lowest reasonable cost, there are significant
initial costs associated with the implementation of the restructuring rule.
Specifically, Order No. 636 authorizes pipelines to recover from their customers
certain transition costs resulting from implementation of the rulemaking. The
Company's four principal pipeline suppliers made filings with the FERC since the
implementation of Order No. 636 for approval of a portion of their restructuring
transition costs and allocation procedures to flow the approved costs through to
their customers. Through December 31, 1995, the Company has paid $19.0 million
of transition costs. The Company currently estimates that its remaining
obligation for Order No. 636 transition costs will be approximately $6.1
million. This estimate was determined from information provided in Order No. 636
FERC compliance filings by the Company's pipeline suppliers and from subsequent
transition


                                       29

<PAGE>

cost filings. This estimate is subject to adjustment by the FERC in its
deliberations on these filings and any future filings by the suppliers. The
Company has provided for the unpaid liability as of December 31, 1995 with an
offsetting charge to Deferred Transition Costs. On October 28, 1993, the NYPSC
instituted a generic proceeding to review the issues associated with Order No.
636 restructuring. On December 20, 1994, the NYPSC issued an order establishing
the regulatory and rate-making policies applicable to New York gas distribution
utilities resulting from FERC Order No. 636. The order provides mechanisms for
the full recovery of transition costs. The Company is presently in the process
of recovering these costs from its customers and believes it will be allowed to
fully recover such costs by the end of 2000.

COAL SUPPLY CONTRACTS

 The Company has one long-term contract and one short-term contract for the
supply of coal and two long-term contracts for the transportation of coal. The
Company has the right under the long-term coal purchase contract to suspend the
purchase of coal if an alternative fuel source becomes less expensive.
 The Company's aggregate contract obligations for the supply and transportation
of coal, for each of the five years following 1995 is as follows: 1996--
$33,900,000; 1997--$31,400,000; 1998--$34,600,000; 1999--$36,000,000; 2000--
$28,300,000.

POWER PURCHASE AGREEMENTS

 The Company has three long-term contracts with other utilities for the purchase
of electric generating capacity and energy. The contracts expire in 1998, 2000
and 2015. Total payments under purchase power contracts were $3.9 million, $5.0
million and $4.6 million during 1995, 1994 and 1993, respectively. At December
31, 1995, the estimated future payments for capacity that the Company is
obligated to buy under these contracts for the five years following 1995 are as
follows:

<TABLE>
<CAPTION>
                          Capacity
Year                        (Mw)                        Amount
-----------------------------------------------------------------------
                                                (Thousands of Dollars)
<S>                       <C>                   <C>
1996                         275                         $4,100
1997                         285                          4,300
1998                         305                          4,700
1999                         325                          5,100
2000                         335                          5,500
-----------------------------------------------------------------------
</TABLE>

     The purchase capacities shown in the above table are based on contracts
currently in effect and are exclusive of applicable energy charges.

LEGAL PROCEEDINGS

INVESTIGATION AND RELATED LITIGATION

     On February 7, 1994, the Company commenced an action entitled ORANGE AND
ROCKLAND UTILITIES, INC. V. JAMES F. SMITH (SMITH), in New York State Supreme
Court against its former Chief Executive Officer and Chairman of the Board of
Directors, who was terminated for cause by the Company's independent Directors
in October 1993. The action asserts claims against Mr. Smith for breach of his
fiduciary duties of loyalty and care, waste, conversion, fraud and unjust
enrichment based on misuse of Company assets and personnel and misappropriation
of Company funds for his own benefit or for other improper purposes, and failure
to maintain proper management controls or to properly supervise corporate
affairs and subordinate employees. Mr. Smith counterclaimed for benefits of in
excess of $3 million and filed a motion demanding arbitration under his
employment agreement with the Company. On June 17, 1994, the court issued an
Order granting Mr. Smith's motion to compel arbitration. Under a second Order
dated August 10, 1994, the parties filed demands for arbitration of the claims
asserted by the Company and by Mr. Smith with the American Arbitration
Association. Hearings began in June 1995 and are continuing.

     On March 22, 1994 an indictment was returned by a Rockland County grand
jury charging Mr. Smith with eight felony counts of grand larceny and two
misdemeanor counts of petit larceny. In June 1994, a superseding indictment
charged Mr. Smith with 15 felony counts of grand larceny, seven counts of
falsifying business records and two misdemeanor counts of petit larceny. On
August 15, 1995, Mr. Smith was acquitted of the charges in a non-jury trial.

     On September 19, 1995, the Company was served with an Amended Summons and
First Amended Complaint (Complaint) in an action filed in the United States
District Court for the Southern District of New York by Mr. Smith. (An earlier
complaint had been filed which did not name the Company.) Named as defendants in
the Complaint are former Rockland County District Attorney Kenneth Gribetz, the
Office of the Rockland County District Attorney, the Company, "John and Jane
Does" (identified in the Complaint as certain directors of the Company and/or
members of the Special Committee of the Board and referred to in the Complaint
as the "Defendant Directors"), Edwin Stier and Stier, Anderson & Malone.

     The Complaint alleges three causes of action: (1) the violation by Mr.
Gribetz and the District Attorney's office of Mr. Smith's federal constitutional
rights to fair trial and due process of law; (2) malicious prosecution by the
Company, Defendant Directors and Mr. Stier in that these defendants allegedly
caused the arrest and criminal prosecution of Mr. Smith; (3) abuse of process by
the Company, Defendant Directors and Mr. Stier in that these defendants were
allegedly responsible for the arrest, indictment and prosecution of Mr. Smith.
Mr. Smith seeks damages in excess of $25 million, special damages and punitive
damages, attorney fees and other costs on each count.

     On December 22, 1995, the Company, Edwin Stier, and Stier, Anderson &
Malone filed a Motion for Summary Judgment and related papers (Motion) seeking
to terminate this action. The Motion is currently pending; if the Motion is
unsuccessful, the Company intends to defend the action vigorously.

     On November 10, 1994, the Company filed with the NYPSC a quantification of
the rate-making effects of its ongoing investigation into prior financial
improprieties. The Company requested the NYPSC to approve an additional refund
of approximately $3.4 million to its New York electric and gas customers. This
amount would be in addition to the $369,000 already refunded by the Company.
Although the NYPSC has not acted on this request, this amount was charged to
operations in the fourth quarter of 1994. The NYPSC instituted a proceeding
(Case 93-M-0849) to provide the opportunity for other parties, including the
NYPSC Staff, which was conducting an independent investigation of the Company,
to be heard on this matter.

     On June 28, 1995, the NYPSC issued the report of the NYPSC Staff on its
investigation of the Company. While the report did not quantify the total cost
of improper charges borne by the Company's New York ratepayers, the report did
state that the NYPSC Staff believes that, in addition to the $3.8 million
already refunded or proposed to be refunded, the Company should reimburse New
York ratepayers for the "excess costs" incurred since 1983 in several specified
areas, including the areas of compensation for senior management of the Company,
the Company's internal auditing function, the compensation of a former employee
of the Company for the period of time when he was embezzling the Company's funds
and the cost of certain employees' time while they were performing personal work
for the Company's officers or were engaged in political or lobbying activities.

     On July 6, 1995, the NYPSC issued an order stating that the issues of the
amount, timing and allocation of New York rate-payer refunds as a result of the
investigation in Case 93-M-0849


                                       30

<PAGE>

should be considered in the context of the Company's current electric base rate
case (Case 95-E-0491) and ordered the consolidation of the two cases
(Consolidated Case).

     On October 2, 1995, in the Consolidated Case, the Company filed a
settlement agreement with the NYPSC Staff relating to the amount, timing and
allocation of investigation refunds. Under the terms of the settlement
agreement, the Company would (1) return approximately $6.5 million to its
electric customers, (2) forgo a gas rate increase authorized by a previous rate
case, thereby saving gas customers an additional $1.7 million, and (3) reduce
its gas adjustment clause by $0.3 million.  As a result of this settlement, the
Company charged approximately $2.8 million to operations during the third
quarter of 1995.The settlement agreement is being contested by certain parties.
On January 25, 1996 the Administrative Law Judge issued a Recommended Decision
(RD) in the Consolidated Case. The ALJ recommends that the NYPSC approve the
settlement agreement. The ALJ noted that the settlement agreement meets all of
the NYPSC's settlement guidelines and balances the interests of the Company's
customers and shareholders. The settlement agreement and the RD are both subject
to the NYPSC review and approval. The Company anticipates that the NYPSC will
issue its order in the Consolidated Case addressing the settlement agreement by
April 1996. The Company is unable to predict the final result of this proceeding
and what modifications, if any, will be made to the settlement agreement.

     Under an agreement with the NJBPU to return to customers any funds found to
be misappropriated or otherwise questionable as a result of its investigation of
certain former Company officers and former employees, in December 1994, a filing
was made with the NJBPU proposing to refund approximately $704,000 to RECO's
customers. These amounts were charged to operations in the fourth quarter of
1994. By order dated January 27, 1995, the NJBPU approved the Company's
proposal. In January 1996, the Company proposed to refund an additional $482,000
to its New Jersey customers.  These amounts were charged to operations in the
third quarter of 1995. The NJBPU has not acted on this proposal. The Company is
unable to predict what modifications, if any, will be made to the amount
proposed to be refunded in New Jersey.

OTHER LEGAL PROCEEDINGS

     On May 11, 1993, an action was commenced against the Company by Hudson
Riverkeeper Fund, Inc. (Riverkeeper) in the United States District Court for the
Southern District of New York. In its complaint, Riverkeeper alleged that the
Company violated and continues to violate its SPDES Permit for its Lovett
Generating Station (Lovett Plant) by failing to maintain cooling water intake
structures that reflect the best technology available for minimizing adverse
environmental impact. An amended complaint was filed May 18, 1993. The
complaint, as amended, requested that the Court assess civil penalties
aggregating $11 million and order the Company to take steps to ensure that the
cooling water intake structures at Lovett reflect the best technology available
for minimizing adverse environmental impact. On June 30, 1993, the Company filed
its answer to Riverkeeper's allegations, reflecting the Company's belief that
Riverkeeper's allegations have no legal merit. Subsequently, the New York State
Department of Environmental Conservation (DEC) intervened in this litigation as
a designated plaintiff. In April 1994, the parties agreed to have engineers
enter into discussions regarding modifications to the Lovett Plant's cooling
water intake structures. From June to August 1995, the Company conducted a
demonstration project to assess the effectiveness of a barrier known as a
"Gunderboom", at the cooling water intake structure for  Lovett Plant Unit No.
3. The Company, Riverkeeper and DEC have agreed that the "Gunderboom" is worthy
of further study. The Company will install the Gunderboom at the cooling water
intake structure for Lovett Plant Units Nos. 4 and/or 5 in the spring of 1996.
The parties have agreed to postpone all further discovery and motion practice in
this litigation until at least June 1996.

     On September 25, 1991, the Company was named as one of several hundred
third party defendants in the UNITED STATES V. KRAMER, ET AL. and STATE OF NEW
JERSEY DEPARTMENT OF ENVIRONMENTAL PROTECTION V. ALMO ANTI-POLLUTION SERVICES,
ET AL., which cases have been consolidated in the United States District Court
for the District of New Jersey, Camden Vicinage. The allegations in this action
concern the Helen Kramer Landfill site in Mantua, New Jersey, which operated
from 1963 to 1981. Suit in this case was brought under Superfund laws. It is
presently unclear if any hazardous waste generated by the Company was
transported to the Helen Kramer Landfill site. At this time the Company does not
believe this action will have a material effect on the financial condition of
the Company.

     On March 29, 1989 the New Jersey Department of Environmental Protection
(NJDEP) issued a directive under the New Jersey Spill and Control Act to various
potentially responsible parties (PRPs) including the Company, with respect to a
site  formerly owned and operated by Borne Chemical Company in Elizabeth, Union
County, New Jersey, ordering certain interim actions directed at both site
security and the off-site removal of certain hazardous substances. Certain PRPs,
including the Company, signed an administrative consent order with NJDEP
requiring them to remove and dispose of the hazardous substances located above
ground at the Borne site, which removal and disposal was completed on June 22,
1992. In October 1995, the PRPs entered into an additional administrative
consent  order with the NJDEP which obligated the PRPs, including the Company,
to perform a remedial investigation to determine what, if any, subsurface
remediation at the Borne site is required. The Company does not believe that
this matter will have a material effect on the financial condition of the
Company.

     On August 2, 1994, the Company entered into a Consent Order with the DEC in
which the Company agreed to conduct a remedial investigation of certain property
it owns in West Nyack, New York. Polychlorinated biphenyls (PCBs) have been
discovered at the West Nyack site. Petroleum contamination related to a leaking
underground storage tank has been found as well.  The results of the
investigation to be conducted by the Company will determine what remediation
will be required at the  West Nyack site. The Company does not believe that this
matter will have a material effect on the financial condition of the Company.

     The Company has identified six former Manufactured Gas Plant (MGP) sites
which were owned and operated by the Company or its predecessors. The Company
may be named as a potentially responsible party for these sites under relevant
environmental laws, which may require the Company to clean up these sites. To
date, no claims have been asserted against the Company. The Company is unable at
this time to estimate what, if any, costs it will incur at these sites.

     The Company and the DEC have executed a Consent Order which provides for
preliminary site assessments of these six MGPsites, dated as of January 8, 1996.


                                       31

<PAGE>


     On May 29, 1991, a group of ten electric utilities (Metal Bank Group)
entered into an Administrative Consent Order with the United States
Environmental Protection Agency (EPA) to perform a remedial investigation and
feasibility study (RIFS) at the Cottman Avenue/Metal Bank Superfund site in
Philadelphia, Pennsylvania. PCBs have been discharged at the Cottman Avenue site
from an underground storage tank and the handling of transformers and other
electrical equipment. On May 25, 1994 the Company entered into a tolling
agreement by which the Metal Bank Group reserved its right to file suit against
the Company, while the Metal Bank Group and the Company entered into discussions
to determine the Company's involvement with the Cottman Avenue site. These
discussions continue. The RIFS has been completed and submitted to the EPA for
determination of what remedial measures will be required at the Cottman Avenue
site. The Company is unable at this time to estimate the Company's share, if
any, of past or future costs at this site.

ENVIRONMENTAL

     The Federal Comprehensive Environmental Response, Compensation and
Liability Act of 1980 and certain similar state statutes authorize various
governmental authorities to issue orders compelling responsible parties to take
cleanup action at sites determined to present an imminent and substantial danger
to the public and to the environment because of an actual or threatened release
of hazardous substances. The Company is a party to a number of administrative
proceedings involving potential impact on the environment. Such proceedings
arise out of, without limitation, the operation and maintenance of facilities
for the generation, transmission and distribution of electricity and natural
gas. Such proceedings are not, in the aggregate, material to the business or
financial condition of the Company.

     Pursuant to the Clean Air Act Amendments of 1990, which became law on
November 15, 1990, a permanent nationwide reduction of 10 million tons in sulfur
dioxide emissions from 1980 levels, as well as a permanent nationwide reduction
of 2 million tons of nitrogen oxide emissions from 1980 levels, must be achieved
by January 1, 2000. In addition, continuous emission monitoring systems were
required at all affected facilities effective January 1, 1995. Pursuant to New
York State attainment of ozone standards, NOx reductions were achieved effective
May 31, 1995.

     The Company has two base load generating stations that burn fossil fuels
that will be impacted by this legislation. These generating facilities already
burn low sulfur fuels, so additional capital costs are not anticipated for
compliance with the sulfur dioxide emission requirements. The Company installed
low nitrogen oxide burners at Lovett Plant and made operational modifications at
Bowline Plant to meet NOx reduction levels for ozone attainment. Additional
emission monitoring systems were installed at both facilities. Beginning with
calendar year 1994, Title V sources (Bowline Point and Lovett) are required to
pay an emission fee. Each facility's fees are based upon actual air emissions
reported to DEC for the preceding calendar year. For 1995, ORU paid an emission
rate of approximately $26 per ton. The emission fee will be reevaluated by New
York State annually. The Company will continue to assess the impact of the Clean
Air Act Amendments of 1990 on its power generating operations as additional
regulations implementing these Amendments are promulgated.

NOTE 13. SEGMENTS OF BUSINESS.

     The Company defines its principal business segments as utility (electric
and gas) and diversified activities. The diversified segment includes gas
production, gas marketing and land development.

     Total utility revenue as reported in the Consolidated Statements of Income
and Retained Earnings include both sales to unaffiliated customers and
intersegment sales which are billed at tariff rates. Income from operations is
total revenue less operating expenses. General corporate expenses were allocated
in the manner used in the rate-making process.

     Identifiable assets by segment are those assets that are used in the
production, distribution and sales operations in each segment. Allocations were
made in a manner consistent with the rate-making process. Corporate assets are
principally property, cash, sundry receivables and unamortized debt expense.

<TABLE>
<CAPTION>
SEGMENTS OF BUSINESS
YEAR ENDED DECEMBER 31,                      1995         1994          1993
--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
                                                 (Thousands of Dollars)
<S>                                    <C>           <C>           <C>
Operating Information:
Operating revenues:
  Sales to unaffiliated customers:
    Electric                            $   459,876  $   478,909   $   486,842
    Gas                                     140,177      157,045       157,185
 Intersegment sales:
   Electric                                     107          120           125
   Gas                                           47          123            72
--------------------------------------------------------------------------------
     Total Utility
       Operating Revenues                   600,207      636,197       644,224
   Diversified activities                   429,906      380,705       322,925
--------------------------------------------------------------------------------
     Total Operating Revenues           $ 1,030,113  $ 1,016,902   $   967,149
--------------------------------------------------------------------------------
Operating income before
 income taxes:
   Electric                             $    85,156  $    80,355   $    89,243
   Gas                                       17,467       19,724        19,147
   Diversified activities                    (4,565)         313           729
--------------------------------------------------------------------------------
     Total Operating Income
        Before Income Taxes                  98,058      100,392       109,119
--------------------------------------------------------------------------------
Income Taxes:
   Electric                                  22,406       19,894        21,380
   Gas                                        3,859        4,644         4,679
   Diversified activities                      (486)           2           167
--------------------------------------------------------------------------------
     Total Income Taxes                      25,779       24,540        26,226
--------------------------------------------------------------------------------
     Total Income From
       Operations                       $    72,279  $    75,852   $    82,893
--------------------------------------------------------------------------------
Other Information:
Identifiable assets:
   Electric                             $ 1,003,598  $   988,149   $   970,117
   Gas                                      224,590      221,374       225,006
   Diversified activities                    81,653       96,043        84,571
--------------------------------------------------------------------------------
     Total Identifiable Assets            1,309,841    1,305,566     1,279,694
Corporate assets                             29,928       42,073        32,142
--------------------------------------------------------------------------------
     Total Assets                       $ 1,339,769  $ 1,347,639   $ 1,311,836
--------------------------------------------------------------------------------
Depreciation expense:
   Electric                             $    30,594  $    29,161   $    28,049
   Gas                                        6,646        5,940         5,349
   Diversified activities                     1,697          761           658
--------------------------------------------------------------------------------
     Total                              $    38,937  $    35,862   $    34,056
--------------------------------------------------------------------------------
Additions to plant:
   Electric                             $    43,225  $    44,832   $    39,441
   Gas                                       10,894       15,242        13,955
   Diversified activities                       911          468           912
--------------------------------------------------------------------------------
     Total                              $    55,030  $    60,542   $    54,308
--------------------------------------------------------------------------------
</TABLE>


                                       32

<PAGE>


NOTE 14. SUMMARY OF QUARTERLY RESULTS OF
OPERATIONS (UNAUDITED).

<TABLE>
<CAPTION>
                                                           Earnings    Earnings
                                                          Applicable      Per
                                      Income                  To        Average
                       Operating       From        Net      Common      Common
                       Revenues     Operations   Income      Stock       Share
--------------------------------------------------------------------------------
QUARTER ENDED                            (Thousands of Dollars)
 1995
<S>                    <C>          <C>         <C>         <C>         <C>
March 31               $311,847       $20,515   $15,321     $14,537     $1.06
June 30                 245,359        12,356     3,722       2,937       .22
September 30            231,906        23,754    14,792      14,008      1.03
December 31             241,001        15,654     4,738       3,956       .29
--------------------------------------------------------------------------------
 1994
March 31               $292,675       $24,165   $14,068     $13,255    $  .98
June 30                 229,735        13,380     3,380       2,567       .19
September 30            239,214        25,615    16,382      15,570      1.14
December 31             255,278        12,692     3,387       2,574       .19
--------------------------------------------------------------------------------
</TABLE>

REPORT OF INDEPENDENT
PUBLIC ACCOUNTANTS
ARTHUR ANDERSEN LLP

TO THE BOARD OF DIRECTORS AND SHAREHOLDERS OF
ORANGE AND ROCKLAND UTILITIES, INC.:

     We have audited the accompanying consolidated balance sheets of Orange and
Rockland Utilities, Inc. and Subsidiaries (a New York Corporation) as of
December 31, 1995 and 1994, and the related consolidated statements of income
and retained earnings and cash flows for the years then ended. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.

     We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.

     In our opinion, the financial statements referred to above present fairly,
in all material respects, the consolidated financial position of Orange and
Rockland Utilities, Inc. and Subsidiaries as of December 31, 1995 and 1994, and
the consolidated results of its operations and its cash flows for the two years
then ended, in conformity with generally accepted accounting principles.

/s/ Arthur Andersen LLP
New York, New York
February 1, 1996

REPORT OF INDEPENDENT CERTIFIED
PUBLIC ACCOUNTANTS
GRANT THORNTON LLP

TO THE BOARD OF DIRECTORS AND SHAREHOLDERS OF
ORANGE AND ROCKLAND UTILITIES, INC. AND SUBSIDIARIES:

     We have audited the accompanying consolidated statements of income and
retained earnings and cash flows of Orange and Rockland Utilities, Inc. and
Subsidiaries for the year December 31, 1993. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audit.

     We conducted our audit in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the  financial statements. An audit also includes
assessing the accounting principles used and significant estimates made  by
management, as well as evaluating the overall financial statement presentation.
We believe that our audit provides  a reasonable basis for our opinion.

     In our opinion, the financial statements referred to above present fairly,
in all material respects, the consolidated results of operations and cash flows
of Orange and Rockland Utilities, Inc. and Subsidiaries for the year ended
December 31, 1993, in conformity with generally accepted accounting principles.

     As more fully discussed in Note 12 (Legal Proceedings) to the consolidated
1993 financial statements, the Company and various state regulatory authorities
are currently investigating misappropriations of Company funds by certain former
employees and the impact on ratepayers. As a result of these improprieties,
several class action and derivative complaints were filed against the Company
and others. Although the Company has refunded certain amounts to ratepayers as
of December 31, 1993, the ultimate outcome of the investigations and litigation
cannot presently be determined. Accordingly, no provision for any additional
liability that may result from  these matters has been made in the accompanying
1993  financial statements.

/s/ Grant Thornton LLP
New York, New York
February 16, 1994


                                       33

<PAGE>

OPERATING STATISTICS -- ELECTRIC

<TABLE>
<CAPTION>

                                                                Year Ended December 31,
                                                  1995        1994         1993        1992         1991
--------------------------------------------------------------------------------------------------------
--------------------------------------------------------------------------------------------------------
<S>                                          <C>         <C>          <C>         <C>         <C>
SOURCE OF ELECTRICITY (Mwh):
 Generation -- net
 Steam                                       2,864,595   3,282,416    2,720,897   3,083,852    3,506,037
 Hydro                                         143,076     168,149      164,378     143,871      172,752
 Gas Turbine                                    21,909      10,448        7,557       3,938       15,217
--------------------------------------------------------------------------------------------------------
  Total Net Generation                       3,029,580   3,461,013    2,892,832   3,231,661    3,694,006
 Purchases                                   1,941,637   1,574,015    2,054,253   1,532,105    1,150,460
 Company Use and Unaccounted For              (326,901)   (305,747)    (354,806)   (298,806)    (316,748)
--------------------------------------------------------------------------------------------------------
  Net Electricity Sold                       4,644,316   4,729,281    4,592,279   4,464,960    4,527,718
--------------------------------------------------------------------------------------------------------
SOURCE OF ELECTRICITY SOLD:
 Oil                                              6.7%        6.5%         5.2%        9.9%        14.0%
 Natural Gas                                     23.4%       22.7%        16.2%       21.2%        21.8%
 Coal                                            27.3%       35.5%        33.2%       33.1%        36.1%
 Hydro                                            2.8%        3.3%         3.3%        3.0%         3.5%
 Purchased Power                                 39.8%       32.0%        42.1%       32.8%        24.6%
--------------------------------------------------------------------------------------------------------
SALES (Mwh):
 Residential                                 1,685,110   1,660,755    1,611,602   1,532,915    1,597,571
 Commercial                                  2,056,185   2,049,265    2,018,240   1,986,048    1,955,851
 Industrial                                    680,678     657,142      627,944     594,912      576,046
 Public Street Lighting                         28,107      27,836       27,705      27,538       26,780
 Public Authorities                             75,506      68,972       72,037      70,257       73,455
--------------------------------------------------------------------------------------------------------

  Total Sales to Customers                   4,525,586   4,463,970    4,357,528   4,211,670    4,229,703
 Other Utilities for Resale                    118,730     265,311      234,751     253,290      298,015
--------------------------------------------------------------------------------------------------------
  Total Sales of Electricity                 4,644,316   4,729,281    4,592,279   4,464,960    4,527,718
--------------------------------------------------------------------------------------------------------
REVENUES (000's):
 Residential                                  $208,862    $214,439     $211,082    $193,124     $196,031
 Commercial                                    204,240     212,214      212,240     202,523      196,409
 Industrial                                     50,205      51,316       50,983      47,128       44,724
 Public Street Lighting                          4,930       4,939        4,967       4,880        4,732
 Public Authorities                              4,257       4,051        4,344       4,212        4,419
--------------------------------------------------------------------------------------------------------
  Total Revenues from Sales to Customers       472,494     486,959      483,616     451,867      446,315
 Other Utilities for Resale                      2,150       6,636        6,414       6,965        9,575
--------------------------------------------------------------------------------------------------------
  Total Revenues from Sales of Electricity     474,644     493,595      490,030     458,832      455,890
 Other Electric Operating Revenues             (14,661)    (14,566)      (3,063)      4,901        1,265
--------------------------------------------------------------------------------------------------------
  Total Electric Operating Revenues           $459,983    $479,029     $486,967    $463,733     $457,155
--------------------------------------------------------------------------------------------------------
ELECTRIC CUSTOMERS -- Year End                 263,156     259,708      256,897     254,192      251,724

RESIDENTIAL CUSTOMER STATISTICS:
 Average Annual Kwh Use                          7,376       7,357        7,214       6,928        7,286
 Average Annual Revenue per Kwh                  12.39CENTS  12.91CENTS   13.10CENTS  12.60CENTS   12.27CENTS
 Average Annual Bill Including Fuel            $914.27     $949.89      $944.82     $872.77      $894.11
 Average Annual Fuel Cost Recovery             $176.71     $188.74      $194.90     $192.76      $207.01
--------------------------------------------------------------------------------------------------------
--------------------------------------------------------------------------------------------------------
</TABLE>


                                       34

<PAGE>

OPERATING STATISTICS -- GAS
<TABLE>
<CAPTION>

                                                                Year Ended December 31,
                                                  1995        1994         1993        1992         1991
--------------------------------------------------------------------------------------------------------
--------------------------------------------------------------------------------------------------------
<S>                                           <C>         <C>          <C>         <C>          <C>
SOURCE OF GAS (Mmcf):
 Purchased                                      49,063      46,712       43,060      46,620       47,928
 Manufactured                                       24          38           21          22           15
 Used in Electric Production                  (26,373)    (24,847)     (21,234)    (24,141)     (26,444)
 Company Use and Unaccounted For                 (558)       (432)        (630)       (549)      (1,176)
--------------------------------------------------------------------------------------------------------
  Net Gas Sold                                  22,156      21,471       21,217      21,952       20,323
--------------------------------------------------------------------------------------------------------



SALES (Mmcf):
 Residential                                    14,759      15,164       15,323      15,212       13,564
 Commercial and Industrial                       5,066       5,257        5,233       5,295        4,766
--------------------------------------------------------------------------------------------------------
  Total Firm Sales                              19,825      20,421       20,556      20,507       18,330
 Interruptible                                   2,327       1,023          653         889        1,325
 Other Utilities for Resale                          4          27            8         556          668
--------------------------------------------------------------------------------------------------------
  Total Sales of Gas                            22,156      21,471       21,217      21,952       20,323
--------------------------------------------------------------------------------------------------------



REVENUES (000's):
 Residential                                 $  96,737   $ 112,759    $ 113,116   $  97,646    $  82,198
 Commercial and Industrial                      31,226      36,676       36,707      32,541       27,811
--------------------------------------------------------------------------------------------------------

  Total Revenues from Firm Sales               127,963     149,435      149,823     130,187      110,009
 Interruptible                                   6,725       3,996        2,605       3,414        5,536
 Other Utilities for Resale                         59         203          105       1,950        1,999
--------------------------------------------------------------------------------------------------------
  Total Revenues from Sales of Gas             134,747     153,634      152,533     135,551      117,544
 Other Gas Revenues                              5,477       3,534        4,724       5,128        5,143
--------------------------------------------------------------------------------------------------------
  Total Gas Operating Revenues               $ 140,224   $ 157,168    $ 157,257   $ 140,679    $ 122,687
--------------------------------------------------------------------------------------------------------



HEATING DEGREE DAYS                              5,494       5,522        5,791       5,771        5,106



GAS CUSTOMERS -- YEAR END                      112,188     110,631      109,464     108,168      106,854



RESIDENTIAL CUSTOMER STATISTICS:
 Average Annual Mcf Use                          145.2       151.0        145.2       145.4        131.0
 Average Annual Revenue per Mcf              $    6.55   $    7.44    $    7.41   $    6.44    $    6.08
 Average Annual Bill Including Fuel          $  951.90   $1,122.89    $1,075.86   $  936.63    $  797.09
 Average Annual Fuel Cost Recovery           $  450.41   $  622.72    $  595.94   $  500.42    $  446.11
--------------------------------------------------------------------------------------------------------
--------------------------------------------------------------------------------------------------------
</TABLE>


                                       35

<PAGE>

FINANCIAL STATISTICS
<TABLE>
<CAPTION>
                                                                Year Ended December 31,
                                                  1995        1994         1993        1992         1991
--------------------------------------------------------------------------------------------------------
--------------------------------------------------------------------------------------------------------
<S>                                         <C>         <C>          <C>         <C>          <C>
COMMON STOCK DATA:
 Earnings Per Average Common Share          $     2.60  $     2.50    $    3.06  $     3.15   $     3.12
 Dividends Declared Per Share               $     2.57  $     2.54    $    2.49  $     2.43   $     2.37
 Book Value Per Share (Year End)            $    27.82  $    27.79    $   27.79  $    27.22   $    26.33
 Market Price Range Per Share:
  High                                      $   37 3/8  $   41 1/4   $   47 1/2  $   41 7/8   $   39
  Low                                       $   30 7/8  $   28 3/8   $   38 5/8  $   32 3/8   $   30 7/8
  Year End                                  $   35 3/4  $   32 1/2   $   40 5/8  $   41 5/8   $   38 5/8
 Price Earnings Ratio                            13.75       13.00        13.28       13.21        12.38
 Dividend Payout Ratio                           98.85%     101.60%       81.37%      77.14%       75.96%
 Common Shareholders at Year End                22,916      23,299       24,328      25,696       25,989
 Average Number of Common Shares
  Outstanding (000's)                           13,653      13,594       13,532      13,438       13,238
 Total Common Shares Outstanding at
  Year End (000's)                              13,654      13,653       13,532      13,531       13,327
 Return on Average Common Equity                  9.35%       9.01%       11.16%      11.88%       12.13%
--------------------------------------------------------------------------------------------------------
CAPITALIZATION DATA (000's):
 Common Stock Equity                        $  379,776  $  379,403   $  376,044  $  368,321   $  350,947
 Non-Redeemable Preferred Stock                 43,253      43,268       43,287      43,306       43,334
 Redeemable Preferred Stock                      1,390       2,774        4,158       5,542        6,926
 Long-Term Debt                                359,736     359,622      380,266     380,202      376,839
--------------------------------------------------------------------------------------------------------
  Total Capitalization                      $  784,155  $  785,067   $  803,755  $  797,371   $  778,046
--------------------------------------------------------------------------------------------------------
CAPITALIZATION RATIOS:
 Common Equity                                   48.43%      48.33%       46.79%      46.19%       45.11%
 Non-Redeemable Preferred Stock                   5.51%       5.51%        5.38%       5.43%        5.57%
 Redeemable Preferred Stock                        .18%        .35%         .52%        .70%         .89%
 Long-Term Debt                                  45.88%      45.81%       47.31%      47.68%       48.43%
--------------------------------------------------------------------------------------------------------
SELECTED FINANCIAL DATA  (000'S):
 Operating Revenues                         $1,030,113  $1,016,902   $  967,149  $  840,072   $  727,783
 Operating Expenses                         $  957,834  $  941,050   $  884,256  $  760,320   $  650,707
 Operating Income                           $   72,279  $   75,852   $   82,893  $   79,752   $   77,076
 Net Income                                 $   38,573  $   37,217   $   44,815  $   45,812   $   44,868
 Earnings Applicable to Common Stock        $   35,435  $   33,966   $   41,451  $   42,334   $   41,277
 Net Utility Plant                          $  873,668  $  856,289   $  831,980  $  814,686   $  792,413
 Total Assets                               $1,339,769  $1,347,639   $1,311,836  $1,142,651   $1,099,494
 Long-Term Debt Including
  Redeemable Preferred Stock                $  361,126  $  362,396   $  384,424  $  385,744   $  383,765
 Ratio of Long-Term Debt to Net Plant             41.2%       44.4%        46.0%       47.0%        48.0%
 Ratio of Accumulated Depreciation to
  Utility Plant in Service                        33.3%       33.1%        31.7%       30.7%        30.0%
--------------------------------------------------------------------------------------------------------
--------------------------------------------------------------------------------------------------------
</TABLE>

Orange and Rockland Utilities, Inc. and Subsidiaries
CREDIT RATINGS

<TABLE>
<CAPTION>
                             Duff & Phelps        Fitch         Moody's        Standard &
                             Credit Rating      Investors      Investors         Poor's
                                Company       Service, Inc.     Service           Corp.
--------------------------------------------------------------------------------------------------------
--------------------------------------------------------------------------------------------------------
  <S>                        <C>              <C>              <C>             <C>
  Commercial paper                D-1              F-2            P-2              A-2
  First mortgage bonds            A+               A-             A3               A-
  Pollution control bonds         A                N/R           Baa1              A-
  Unsecured debt                  A                A-            Baa1              A-
  Preferred debt                  A-               A-            baa1             BBB+
--------------------------------------------------------------------------------------------------------
--------------------------------------------------------------------------------------------------------
</TABLE>


                                       36
                      ORANGE AND ROCKLAND UTILITIES, INC.

                           APPENDIX A TO EXHIBIT 13

                          FORM 10-K DECEMBER 31, 1995


      The Review of the Company's Results of Operations and Financial
Condition, which is included in the Company's Annual Report to Shareholders
and is incorporated by reference in this Annual Report on Form 10-K, contains
certain graphic presentations of financial data which are presented in tabular
format as follows:

      1. -  Graph entitled "Electric Sales to Customers" 

                        Year              Mwh (Millions)

                        1991                    4.23
                        1992                    4.21
                        1993                    4.36
                        1994                    4.46
                        1995                    4.53

      2. -  Graph entitled "Cost per Kwh"

                                          
                        Year                    Cents

                        1991                    2.74
                        1992                    2.70
                        1993                    2.67
                        1994                    2.51
                        1995                    2.46

      3. -  Graph entitled "Firm Gas Sales"

                        Year                    Bcf         

                        1991                    18.3
                        1992                    20.5
                        1993                    20.6
                        1994                    20.4
                        1995                    19.8

      4. -  Graph entitled "Cost per Mcf"

                                          
                        Year                    Dollars

                        1991                    2.90
                        1992                    3.52
                        1993                    3.63
                        1994                    3.52  
                        1995                    3.46

appenda.wp