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

FINANCIAL PERFORMANCE

    Consolidated earnings per share were $3.17 for 1996, compared to $2.60 in
1995 and $2.50 in 1994. The increase in earnings was largely the result of
higher electric and natural gas sales, reduced customer refunds and decreased
investigation and litigation costs. The Company's continued success in
controlling operating and maintenance expenses, and in lowering interest
charges, also had a positive effect on earnings. While the Company's gas
marketing subsidiary continued to underperform and experienced a net loss for
the year, a new strategic initiative begun in the third quarter of 1996 is
aimed at securing lower-volume, higher-margin customers, and will be fully
implemented during 1997. The 1995 increase in earnings over 1994 is the
result of the impact of the reduced 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, partially
offset by a decline in non-utility subsidiary operating results. Consolidated
earnings available for common stock were $43.3 million in 1996, $35.4 million
in 1995 and $34.0 million in 1994. Earnings per average common share are
summarized as follows:
<TABLE>
<CAPTION>
                                                                                             1996       1995       1994
                                                                                           ---------  ---------  ---------
<S>                                                                                        <C>        <C>        <C>     
Utility operations.......................................................................  $    3.39  $    3.20  $    3.14
Events affecting the Company:
  Investigation & litigation costs.........................................................     (.09)      (.35)      (.42)
  Refunds of misappropriated funds.........................................................       --       (.14)      (.20)
Diversified activities...................................................................       (.13)      (.11)      (.02)
                                                                                           ---------   --------   --------
Consolidated earnings per share..........................................................  $    3.17  $    2.60  $    2.50
                                                                                           ---------   --------   --------
</TABLE>

    The earned return on common equity was 11.3% in 1996, compared to 9.4% in
1995, and 9.0% in 1994. Book value per share at year-end 1996 was $28.41,
compared to $27.82 in 1995 and $27.79 in 1994.

    The Company continued to provide a fair and equitable return on
shareholders' investments. The dividends paid on common stock were $2.58,
$2.57 and $2.54 per share in 1996, 1995 and 1994, respectively. The Company
has maintained a strong capital structure: 46% long-term debt (includes debt
due within one year), 5% preferred stock and 49% common equity.

ARBITRATION PROCEEDINGS

    The Company was party to an arbitration proceeding relating to events
surrounding the termination of James F. Smith, its former Chief Executive
Officer and Chairman of the Board of Directors. On January 29, 1997, the
Company received the decision of the arbitration tribunal awarding Mr. Smith
the net sum of $5.5 million against the Company. Any amounts not previously
provided for will be recorded in the first quarter of 1997. The Company does
not expect the additional provision to have a significant impact on the
overall results of operations in 1997. For more information on this matter,
refer to Note 12 of the Notes to Consolidated Financial Statements.

RESULTS OF OPERATIONS

    The discussion that follows identifies the principal causes of the
significant changes in the amounts of revenues and expenses affecting
earnings applicable to common stock by comparing 1996 to 1995 and 1995 to
1994. 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.

                                       10

    The following is a summary of the changes in earnings applicable to
common stock:
<TABLE>
<CAPTION>

INCREASE (DECREASE) FROM PRIOR YEAR                                            1996       1995
---------------------------------------------------------------------------  ---------  ---------
                                                                                 (MILLIONS OF
                                                                                   DOLLARS)
<S>                                                                           <C>       <C>   
Utility operations:
 Operating revenues.........................................................  $   53.3  $   (36.0)
 Energy and gas costs.......................................................      35.0      (27.2)
                                                                             ---------  ---------
  Net revenues from utility operations.......................................     18.3       (8.8)
Other utility operating expenses and taxes.................................       12.5       (9.6)
                                                                             ---------  ---------
  Operating income from utility operations...................................      5.8        0.8
Diversified revenues.......................................................     (158.1)      49.2
Diversified operating expenses and taxes...................................     (158.4)      53.5
                                                                             ---------  ---------
Income from operations.....................................................        6.1       (3.5)
Other income and deductions................................................         --        4.2
Interest charges...........................................................       (1.6)      (0.7)
                                                                             ---------  ---------
Net income.................................................................        7.7        1.4
Preferred dividends........................................................       (0.1)      (0.1)
                                                                             ---------  ---------
Earnings applicable to common stock........................................  $     7.8  $     1.5
                                                                             ---------  ---------
</TABLE>
 
ELECTRIC OPERATING RESULTS

    Electric operating revenues, net of fuel and purchased power costs,
increased by 3.6% or $12.1 million in 1996 after decreasing by 2.5% or $8.5
million in 1995.

    These changes are attributable to the following factors:
<TABLE>
<CAPTION>

INCREASE (DECREASE) FROM PRIOR YEAR                                            1996       1995
---------------------------------------------------------------------------  ---------  ---------
                                                                                 (MILLIONS OF
                                                                                   DOLLARS)
<S>                                                                           <C>        <C> 
Retail sales:
 Price changes..............................................................  $  (13.5) $   (19.3)
 Sales volume changes.......................................................       6.0        4.8
                                                                             ---------  ---------
  Subtotal...................................................................     (7.5)     (14.5)
Sales for resale...........................................................        1.0       (4.5)
Other operating revenues...................................................       23.6         --
                                                                             ---------  ---------
  Total electric revenues....................................................     17.1      (19.0)
Electric energy costs......................................................        5.0      (10.5)
                                                                             ---------  ---------
  Net electric revenues......................................................  $  12.1  $    (8.5)
                                                                             ---------  ---------
</TABLE>
ELECTRIC SALES AND REVENUES

    Total sales of electric energy to retail customers during 1996 were
4,605,300 Mwh (megawatt hours), compared with 4,525,600 Mwh during 1995 and
4,464,000 Mwh in 1994. Revenues associated with these sales were $465.0
million, $472.5 million and $487.0 million in 1996, 1995 and 1994,
respectively. Electric sales to customers for the last five years are shown
in the accompanying 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>
                                                                            1996        1995
                                                                           ---------    -----
<S>                                                                       <C>          <C>
Residential.........................................................        2.7%        1.5%
Commercial..........................................................       (0.5)%       0.3%
Industrial..........................................................       10.0%        3.6%
Public street lighting..............................................        5.0%        1.0%
Sales to public authorities.........................................      (31.9)%       9.5%
                                                                        ---------     -------
</TABLE>
    Despite cooler summer conditions when compared to 1995, the increase in
customer usage coupled with the increase in the number of customers,
increased electric retail sales in 1996 by 1.7%. Electric retail sales
increased 1.4% in 1995 when compared to 1994, resulting primarily from an
increase in the number of customers coupled with unusually warm weather
during the summer months.

    Through the PowerPick-TM- Program and other initiatives, the
Company continues to meet the needs of its customers by pursuing least-cost
strategies, designed to provide participants from all classes of customers
with the opportunity to select an energy supplier other than the Company. It
is also designed to minimize any potential adverse impacts on
non-participants and to maintain the Company's system reliability. Program
participants will continue to buy capacity and to take delivery from the
Company, thereby protecting the interests of the Company's shareholders and
non-participating customers.

    Other programs have been put into place which are designed to reduce peak
load, encourage efficient energy usage and reduce the need for costly
investments in new generating capacity. These efforts resulted in the Company
achieving an energy-efficiency savings of approximately 240,000 Mwh in 1996,
235,000 Mwh in 1995 and 194,000 Mwh in 1994. Although Demand Side Management
(DSM) incentives were discontinued in 1996, energy-efficiency incentives of
$1.4 million and $0.6 million were earned by the Company in 1995 and 1994,
respectively. In addition to DSM, the Company continues to actively seek cost
effective energy supply options, such as purchased power agreements with
others.

    On May 3, 1996, the Company and the New York Public Service Commission
(NYPSC) eliminated the Revenue Decoupling Mechanism (RDM), which reconciled
actual sales revenues in New York to levels allowed in rates (see Rate
Activities section). As a result of this agreement, the Company's electric
earnings in 1996 were partially affected by changes in sales volume and
weather conditions. The Company's future electric earnings will be affected
by changes in sales volumes resulting from the strength of the economy,
weather conditions and conservation efforts of customers.

    Other operating revenues increased due to regulatory adjustments required
by the May 3, 1996 agreement which were offset in operating expenses.

    Sales for resale increased by $1.0 million to $3.1 million in 1996 when
compared to 1995, after decreasing from $6.6 million in 1994 to $2.1 million
in 1995. 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.


ELECTRIC ENERGY COSTS

    The cost of fuel used in electric generation and purchased power
increased 4.0% or $5.0 million in 1996, after decreasing 7.8% or $10.5
million in 1995. The components of these changes in electric energy costs are
as follows:
<TABLE>
<CAPTION>

INCREASE (DECREASE) FROM PRIOR YEAR                                               1996       1995
------------------------------------------------------------------------------  ---------  ---------
                                                                                    (MILLIONS OF
                                                                                      DOLLARS)
<S>                                                                               <C>      <C>   
Prices paid for fuel and purchased power......................................    $   1.1  $    (2.4)
Changes in Kwh generated or purchased.........................................        2.3       (2.1)
Deferred fuel charges.........................................................        1.6       (6.0)
                                                                                      ---  ---------
  Total.........................................................................  $   5.0  $   (10.5)
                                                                                  -------  ---------
</TABLE>
    The increase in electric energy costs in 1996 when compared to 1995 is
the result of an increase in the cost of fuel as well as increased sales.
Electric energy costs in 1995 reflect the lower costs of fuel used in
generation, somewhat offset by an increase in purchased power costs when
compared to 1994.

    The price paid for fuel and purchased power per kilowatt hour over the
last five years is shown in the accompanying 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 1996, 1995 and 1994,
pre-tax earnings were enhanced by $580,000, $755,000 and $1,241,000,
respectively, as a result of this mechanism. The Company maintains an
aggressive program of managing its sources of fuel and

                                  11


energy purchases to provide its customers with the lowest-cost 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 RESULTS

    Gas operating revenues, net of gas purchased for resale, increased by
9.0%, or $6.2 million in 1996 when compared to 1995, after decreasing by
0.3%, or $0.2 million in 1995.

    These changes are attributable to the following factors:
<TABLE>
<CAPTION>

INCREASE (DECREASE) FROM PRIOR YEAR                                             1996       1995
----------------------------------------------------------------------------  ---------  ---------
                                                                                  (MILLIONS OF
                                                                                    DOLLARS)
<S>                                                                           <C>        <C>  
Sales to firm customers:
  Price changes.............................................................  $    22.6  $   (19.6)
  Sales volume changes......................................................        3.4       (1.9)
                                                                              ---------  ---------
    Subtotal................................................................       26.0      (21.5)
Sales to interruptible customers............................................        8.4        2.7
Sales for resale............................................................     --           (0.1)
Other operating revenues....................................................        1.8        2.0
                                                                              ---------  ---------
    Total gas revenues......................................................       36.2      (16.9)
Gas energy costs............................................................       30.0      (16.7)
                                                                              ---------  ---------
    Net gas revenues........................................................  $     6.2  $    (0.2)
                                                                              ---------  ---------
</TABLE>
 
GAS SALES AND REVENUES

    Firm gas sales amounted to 20,918 million cubic feet (Mmcf) in 1996, an
increase of 5.5% over the 19,825 Mmcf recorded in 1995. Such sales in 1995
decreased by 2.9% from the 1994 level of 20,421 Mmcf. Gas revenues from firm
customers were $153.9 million, $128.0 million and $149.4 million in 1996,
1995 and 1994, respectively.

    Gas sales to firm customers for the last five years are shown in the
accompanying 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>
                                                                                     1996        1995
                                                                                     -----     ---------
<S>                                                                                    <C>         <C>
Residential.....................................................................         6.3%       (2.7%)
Commercial and industrial.......................................................         3.3%       (3.6%)
                                                                                      ------      ------
</TABLE>
    Cooler weather in the first quarter of 1996 when compared to 1995 was the
primary reason for the increase in sales. An increase in the number of
customers in 1996 when compared to 1995 also enhanced sales. In addition,
1995, which also had an increase in the number of customers, was adversely
affected by weather conditions.

    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 may have a minimal impact on
gas operating results.

    The Federal Energy Regulatory Commission's (FERC) Order 636 required
pipeline supply companies to separate or unbundle their charges for providing
natural gas to the Company. The unbundling of charges provided the Company
with the opportunity to put tariffs in place on October 1, 1996, which
allowed the Company to market available pipeline transmission capacity. As
approved, the tariffs granted the Company permission to retain 15% of all
revenues derived from the sale of pipeline capacity during 1996.
Additionally, as part of the Company's rate agreement in Case 92-G-0050, the
Company is allowed to retain 25% of net revenues derived from Order 63
off-system transactions. Revenues retained from Order 636 and Order 63
transactions in 1996 amounted to $0.5 million.

    Revenues from interruptible gas customers (customers with alternative
fuel sources) increased by 124.5% in 1996 after increasing by 68.3% in 1995
when compared to the previous year. These sales are dependent upon the
availability and price competitiveness of alternative fuel sources. As a
result of applicable tariff regulations, these interruptible sales do not
have a substantial impact on earnings.

GAS ENERGY COSTS

    Utility gas energy costs increased by 42.0% or $30.0 million in 1996 when
compared to 1995, after decreasing by 19.0%, or $16.7 million in 1995.

    The changes in utility gas energy costs for the years 1996 and 1995 are a
result of the following:
<TABLE>
<CAPTION>

INCREASE (DECREASE) FROM PRIOR YEAR                                             1996       1995
----------------------------------------------------------------------------  ---------  ---------
                                                                                  (MILLIONS OF
                                                                                    DOLLARS)
<S>                                                                           <C>        <C>
Prices paid to gas suppliers*...............................................  $    15.7  $   (10.1)
Firm and interruptible Mcf sendout..........................................        9.1        3.1
Deferred fuel charges.......................................................        5.2       (9.7)
                                                                              ---------  ---------
  Total....................................................................   $    30.0  $   (16.7)
                                                                              ---------  ---------
 </TABLE>

*   Net of refunds received from gas suppliers.

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

    The price paid for purchased gas per thousand cubic feet (Mcf) over the
last five years is shown in the accompanying chart. [Graphics Chart, See
Appendix A of Exhibit 13]

    Gas costs from 1990-1993 were adversely affected by the actions of the
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, 1996, $2.1 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 by March 1999.

    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 636, has
authorized pipelines to recover certain transition costs from their
customers. The Company currently estimates that its obligations for Order 636
transition costs will total approximately $36.7 million. Approximately $25.1
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 636. The NYPSC 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 the year 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                                               1996       1995
------------------------------------------------------------------------------  ---------  ---------
                                                                                    (MILLIONS OF
                                                                                      DOLLARS)
<S>                                                                             <C>        <C>
Other operating expenses......................................................  $    17.1  $    (8.7)
Maintenance...................................................................       (4.6)      (2.8)
Depreciation and amortization.................................................       (5.2)       2.1
Taxes.........................................................................        5.2       (0.2)
                                                                                ---------  ---------
  Total.......................................................................  $    12.5  $    (9.6)
                                                                                ---------  ---------
</TABLE>
                                           12



    The primary reason for the increase in utility operating expenses is the
amortization of previously deferred Independent Power Producer costs of $16.2
million offset by a decrease in the costs of DSM programs, which decreased by
$4.0 million in 1996. These costs are recovered in revenues on a current
basis. The remaining increase in 1996 is the result of increased transmission
and distribution activities during the current year. The primary reason for
the decrease in operating expenses in 1995 was the decrease in DSM programs
of $8.1 million from 1994. Additionally, the Company's cost containment
program reduced 1996 and 1995 costs through operating efficiencies and lower
labor costs realized by attrition.

    Maintenance costs decreased 11.1% in 1996 after decreasing by 6.4% in
1995. The decrease in 1996, when compared to 1995, is primarily a result of
improvements to the Company's distribution and transmission systems during
the year. The 1995 decrease was primarily the result of reduced distribution
plant maintenance.

    Depreciation and amortization expenses decreased by $5.2 million in 1996
when compared to 1995, primarily as a result of the most recent rate decision
in New York, after increasing by $2.1 million in 1995. The increases in 1995
were the result of normal plant additions.

    Taxes other than income taxes increased by $5.0 million in 1996 when
compared to the $93.7 million recorded in 1995. This increase reflects the
amounts previously deferred under the Company's RDM agreement. Exclusive of
the RDM adjustment, the 1996 increase was less than two percent. The increase
in 1995 was the result of taxes associated with revenues. Federal income tax
expense increased $0.2 million in 1996, after increasing $1.7 million in
1995. 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 and land development businesses conducted by its wholly owned
non-utility subsidiaries.

    Revenues from diversified activities decreased by $158.1 million in 1996,
after increasing by $49.2 million in 1995. The 1996 revenue decline reflects
the gas marketing subsidiary's strategy to focus on securing lower-volume,
higher-margin customers.

    Operating expenses incurred by the non-utility subsidiaries decreased by
$158.4 million in 1996 after increasing by $53.5 million in 1995. These
changes are directly related to gas marketing purchases which decreased by
$155.4 million in 1996, after increasing by $53.6 million in 1995. Other
expenses of operation, maintenance, depreciation and taxes decreased $3.0
million in 1996, after decreasing by $0.1 million in 1995.

    Earnings from diversified activities decreased by $0.2 million and $1.3
million in 1996 and 1995, respectively. The declines were primarily due to
the gas marketing subsidiary which continues to underperform, resulting in
lower margins and a net loss for the second consecutive year. A new strategic
initiative (NORSTAR 2000), which began in the third quarter of 1996, aimed at
increasing customers, sales and margin, will be fully implemented during
1997. Earnings in 1995 were further reduced by the recognition of the market
value of properties held by an affiliate of the gas marketing subsidiary.
However, 1995 diversified earnings were enhanced by a $2.9 million gain
realized as a result of the formation of the NORSTAR Energy Limited
Partnership.

OTHER INCOME AND DEDUCTIONS

    Other income and deductions remained virtually unchanged in 1996 when
compared to 1995. The increase from 1995 to 1994 was $4.2 million. The change
was the result of lower investigation and litigation costs entirely offset by
the gain realized in 1995 from the formation of the NORSTAR partnership.

INTEREST CHARGES

    Interest charges decreased $1.6 million in 1996 when compared to 1995,
after decreasing $0.7 million in 1995. The 1996 and 1995 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.

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
1994-1996 were as follows:

<TABLE>
<CAPTION>
                                                                                             1996       1995       1994
                                                                                           ---------  ---------  ---------
                                                                                                (MILLIONS OF DOLLARS)
<S>                                                                                        <C>        <C>        <C>   
Construction expenditures................................................................  $    60.9  $    56.8  $    62.5
Retirement of long-term debt & preferred stock...........................................        1.6       20.8        4.1
                                                                                           ---------  ---------  ---------
  Total..................................................................................  $    62.5  $    77.6  $    66.6
                                                                                           ---------  ---------  ---------
</TABLE>
 
    At December 31, 1996, the Company estimated the cost of its construction
program in 1997 to be $57.7 million and retirement of long-term debt and
preferred stock to be $79.6 million. It is expected that the Company's
capital requirements for 1997, with the exception of $78.0 million in
long-term debt maturities which the Company expects to refinance, will be met
primarily with funds from operations, supplemented by the issuance of
short-term borrowings.

    On February 4, 1997, Rockland Electric Company (RECO), a wholly owned
utility subsidiary of the Company, issued $20 million of First Mortgage 7 1/8%
Bonds, Series J due February 1, 2007 (Series J Bonds). The proceeds from the
issuance of the Series J Bonds, together with other RECO funds will be used to
refund, in March 1997, RECO's $20 million First Mortgage 9.59% Bonds, Series
H. Neither the Company nor its utility subsidiaries have any plans at the
present time for external additional financing other than securities issued
for refunding purposes.

    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 issues of common stock 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, 1996.

    The Company and its utility subsidiaries have unsecured bank lines of
credit totaling $100 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, 1996, and the non-utility subsidiaries may undertake short-term
borrowings or make short-term investments.

                                          13


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 NYPSC's investigation of alleged
financial improprieties of certain former officers and former employees of
the Company (the NYPSC Investigation), the implementation of 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 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 NYPSC's
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 New York State
Consumer Protection Board (CPB) and the Industrial Energy Users Association
(IEUA) reached a settlement which resolved all outstanding issues relating to
the NYPSC Investigation. The settlement provided for, among other things, the
cancellation of the second-stage gas base rate increase scheduled for
December 31, 1994. All deferred balances resulting from expense
reconciliations and deferral of the second-stage rate adjustment were offset
with an equal amount of deferred credits approved as part of the rate
decision dated May 3, 1996, discussed below. 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 (SFAS No.
106), "Employer Accounting for Postretirement Benefits Other Than Pensions."
The annual cost increase due to gas operations as a result of SFAS No. 106
will be offset by an equal amount of previously deferred credits. On May 3,
1996, the NYPSC issued an order approving the settlement.

    By orders issued March 28, 1996 and September 13, 1996, the NYPSC
approved utility restructuring plans designed to open up the local natural
gas market to competition and allow residential and small commercial users
the same ability to purchase gas supplies from a variety of sources, other
than the franchised local distribution utility, that large industrial
customers have enjoyed for several years. Small customers' usage volumes will
be aggregated for purposes of obtaining access to alternative sources of
natural gas. The Company revised tariffs for the transportation and delivery
of third-party gas supplies for customers consistent with the NYPSC orders
effective October 1, 1996. The NYPSC orders provide for a phase-in of the new
service to ease potential implementation problems and the recovery of
stranded costs which are incurred over the next three years. In recognition
of the accelerating movement by customers to purchase natural gas supplies
from alternate sources, the Company has restructured its gas supply and
transportation contracts to reflect reduced requirements for
Company-furnished gas and has been actively marketing available pipeline
transportation capacity.

NEW YORK--ELECTRIC

    On April 19, 1995, the NYPSC approved the Company's compliance filing
regarding the operation of the RDM. The filing included a proposal to
eliminate the RDM Adjustment Factor of $7.7 million effective May 1, 1995,
reflecting the completion of the recovery of an RDM under-collection
applicable to the year 1993. This equated to a 2.3% annual reduction in
revenues. In addition, the filing requested that a net RDM over-collection of
$0.7 million for the year 1994 be retained by the Company as a future rate
moderator, subject to NYPSC verification.

    On May 25, 1995, the Company filed with the NYPSC for a decrease in
electric revenues of $6.1 million to be effective April 1, 1996 (Case
95-E-0491). This equated to an overall reduction of 1.8% in annual retail
revenues. 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 years of the plan. The Company proposed an overall
return on capital of 9.17% with a sharing mechanism governing any return on
common equity above 11.2%.

    On August 1, 1995, the NYPSC approved a stipulation among the parties
which provided for the early implementation of the Company's proposed annual
rate reduction of $6.1 million. As a result, reduced rates became effective
August 1, 1995 producing a revenue reduction of approximately $3.8 million
for the period August 1, 1995 to March 31, 1996. The revenue reduction was
offset by the recognition of deferred revenue for 1994 and 1995 related to
sharing mechanisms previously approved by the Commission .

    On May 3, 1996, the NYPSC approved, subject to modifications required by
the NYPSC decision in the Competitive Opportunities Proceeding (discussed
below), a Settlement Agreement (1996 Agreement) among the Company, NYPSC
Staff and other parties which resolved all remaining revenue requirement
issues in the proceeding for a three-year period commencing May 1, 1996 and
concluding April 30, 1999. Under the 1996 Agreement, the Company reduced its
annual electric retail revenues in New York by an additional $7.75 million,
or 2.3%, effective May 1, 1996. The agreement also provides for the recovery
over a four-year period of the buyout costs associated with three non-utility
generator contracts entered into by the Company and applicable to New York
electric operations. In addition, the settlement provides for several
performance mechanisms related to service reliability and customer service,
and the elimination of all revenue and most expense reconciliation provisions
of the RDM. The 1996 Agreement provides the Company with the opportunity to
retain all New York electric earnings up to a 10.9% return on equity annually
for each of the next three years. Earnings in excess of 10.9% will be shared
equally between customers and shareholders.

    The 1996 Agreement implements several competitive initiatives sought by
the Company. These include price reductions, the offering of service
guarantees and the introduction of customer choice of energy providers. Since
April 1995, the Company has reduced its overall electric rates by 6.4%, and
through changes in rate design and revenue allocations, provided reductions
to our largest commercial and industrial customers of up to 16%. The Company
recognizes the critical need to retain and encourage the growth of existing
businesses as well as attract new industry and jobs to the area served by
Orange and Rockland Utilities, Inc. (O&R) and has successfully adjusted its
prices and cost structure to achieve this vital objective. O&R now offers the
second lowest electric rates for large industrial customers in New York. In
addition, the settlement permits the Company to initiate its plan to achieve
h higher consumer satisfaction through a new program that offers cash or
credit rebates to customers if O&R does not meet specified service
guarantees, such as keeping service appointments.

                                    14


    The NYPSC, in approving the 1996 Agreement, also authorized the Company
to launch an innovative retail access pilot program --PowerPick-TM-
--which, for the first time, allows customers participating in the
experimental program to choose their electric energy supplier.
PowerPick-TM- is the first pilot program of its kind in New York, New
Jersey and Pennsylvania and represents a significant step in the transition
to a competitive electric industry. PowerPick-TM- is designed to provide
participants from all classes of customers with the choice of selecting an
energy supplier other than O&R. The amount of energy available to
participating customers from alternate suppliers is limited to 40 megawatts
of off-peak usage, and O&R continues to provide capacity and to deliver the
energy to program customers, thereby protecting the interests of shareholders
and non-participating customers. The program was first opened to the
Company's largest industrial customers in July 1996. Eighteen industrial
customers have participated in the program to purchase a total of 30
megawatts of energy from six marketers and others, and achieved a savings of
approximately 3-5% on their total electric costs. On January 1, 1997, an
additional 10 megawatts of energy was made available to the Company's
commercial and residential customers. Over 400 commercial and residential
customers have agreed to participate in the second phase of the pilot
program, with total electric price savings anticipated to range between 1 and
2%. The PowerPick-TM- program will provide both regulators and the
Company with valuable information about customer needs and power
deliverability as the industry is restructured to a more competitive market.

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 the Company's investigation of alleged financial
improprieties of certain former Company officers and former employees, RECO,
a wholly owned utility subsidiary of the Company, refunded $93,000 through
reductions in the applicable fuel adjustment charges in February and March
1994. In December 1994, RECO submitted a proposal 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.

    On February 21, 1996, the NJBPU approved RECO's 1996 Levelized Energy
Adjustment Clause (LEAC) filing whereby RECO passed back an additional
$482,000 of refunds related to the investigation of the alleged financial
improprieties referred to above, making the total amount refunded to RECO
customers $1,279,000. In addition, as part of this LEAC filing, RECO was
granted full recovery over a three-year period of its share of buyout costs
associated with three non-utility generator contracts entered into by the
Company.

    The NJBPU on January 8, 1997 approved a stipulation among New Jersey
utilities, NJBPU Staff and the NJ Division of Ratepayer Advocate which
provides a recovery plan for costs associated with the change in accounting
required by SFAS No. 106. The approved plan provides several alternative
recovery mechanisms for the recognition of SFAS No. 106 costs in a utility's
cost of service. Each utility must choose the recovery procedure it believes
most appropriate for its circumstances and file with the NJBPU for approval
of implementation. RECO is reviewing the recovery mechanisms provided by the
plan and will file for approval with the NJBPU in the first quarter of 1997.

    On January 23, 1997 a residential customer of RECO filed a petition with
the NJBPU requesting a lowering of RECO's rates by $21.2 million or 16% based
on the twelve months ended December 31, 1995 as adjusted. A central issue
raised by the petition is whether RECO's continued purchase of all of its
power supply requirement from the Company continues to be appropriate when
lower cost energy is available from other sources. RECO believes that this
petition is without merit and intends to contest it vigorously.

COMPETITION

    Regulatory agencies at the federal level as well as the three states in
which the Company has retail electric franchises are currently evaluating
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. A discussion of the current federal and state
competitive initiatives follows.

FEDERAL INITIATIVE

    On April 24, 1996, the FERC issued its final order (FERC Order 888)
requiring electric utilities to file non-discriminatory open access
transmission tariffs that would be available to wholesale sellers and buyers
of electric energy. The order also provided for the recovery of related
legitimate and verifiable strandable costs subject to FERC's jurisdiction.
The Company filed the required open access transmission tariff on July 9,
1996 offering transmission service and certain ancillary services to
wholesale customers on a basis comparable to that which it provides itself.
The Company is operating under the filed tariff, subject to refund, pending
final FERC approval of the Company's filing. The Company participates in the
wholesale electric market primarily as a buyer of energy and, as a result,
Ord er 888 is not expected to materially impact the Company's financial
condition or results of operations.

    On January 31, 1997, O&R, in conjunction with the other members of the
New York Power Pool (NYPP), filed tariffs with the FERC seeking permission to
restructure the NYPPinto an independent system operator.

NEW YORK COMPETITIVE OPPORTUNITIES PROCEEDING

    On May 20, 1996, the NYPSC issued an order setting forth its vision and
goals for the future of the electric industry in New York. The order endorsed
a fundamental restructuring of the industry based on competition in the
generation and energy services sectors of the industry. Introduction of
retail access for all electric customers is envisioned to begin in early
1998. In addition, the order calls for lowering rates to consumers,
increasing customer choice, continued reliability of service, continuation of
programs that are in the public interest and continuing customer protections
and the obligation to serve. While the Company supports the NYPSC's goal of
establishing a competitive electricity market in New York State, the Company
believes that the May 20, 1996 Order was deficient in certain areas. On
September 18, 1996, the Company, the six other New York investor-owned
electric utilities and the Energy Association of New York State filed a suit
in New York State Supreme Court challenging the May 20, 1996 Order. This
litigation is discussed further in the Legal Proceedings section of Note 12
of Notes to Consolidated Financial Statements.

    On October 1, 1996, the Company, in response to the May 20, 1996 Order,
filed a rate and restructuring plan (the Plan) with the NYPSC. The Company's
filing presented a comprehensive plan for the functional separation of
generation, a schedule for retail access with reciprocity, base rate freeze
and stranded cost recovery.

    The Company intends to functionally separate its generation from the
remainder of its operations. This functional separation is scheduled to be
completed in 1998. The Company has no present plans to divest its generation.

    The Company's Plan sets forth a two-phase approach for implementing
retail access. For the first phase, the Company proposes to expand its
PowerPick-TM- program to all customers. This first phase would commence
12 months after a wholesale electric market is fully operational in New York
state. A second phase, in which the Company's customers would be allowed a
choice of capacity as well as energy providers, would become effective 24
months after the beginning of the first phase.

                                   15


    The Company's filing indicated that reciprocity would be required in
order to implement retail access. By reciprocity, the Company means that if
other generators are allowed access to the Company's retail customers, the
Company should be permitted equal access to the customers of those utilities
within New York state and regionally.

    The Company's current three-year electric rate settlement is effective
until April 30, 1999. For those low-income, demand side management, research
and development, and other public policy programs which the NYPSC continues
to mandate, the Company proposes that the costs of these programs be
recovered through a non-bypassable systems benefit charge.

    The Company proposes that it have a reasonable opportunity to recover its
strandable costs from customers. Strandable costs are investments and
expenditures made by utilities pursuant to their obligation under the
existing regulatory framework to provide electric service to the public,
whose continued recovery through electric rates may be jeopardized by the
transition from traditional regulation and exclusive retail franchises to a
different form of regulation and a more competitive marketplace. Three broad
categories of potentially strandable costs are utility generation investment,
purchase power contracts and regulatory assets. In its filing, the Company
does not attempt to quantify the amount of its strandable costs since these
costs are dependent on future market conditions. The Company's proposal is to
recover strandable costs through the implementation of a non-bypassable
competition transition charge (CTC). Under the Plan, the CTC would be
recoverable during a transition period of eight years starting when the
second phase of retail competition becomes effective.

    On October 9, 1996, the NYPSC issued an order establishing procedures and
a schedule for considering the rate restructuring plans filed on October 1,
1996 in the Competitive Opportunities Proceeding. The NYPSC has established a
separate proceeding for each of the five utilities (including the Company)
which filed these plans. The utility, the NYPSC Staff and other interested
parties have until February 14, 1997 to complete discovery, engage in
settlement negotiations and submit testimony on any contested issues. Any
responsive testimony must be submitted by February 24, 1997. If a settlement
agreement is negotiated in a proceeding, it will be submitted to the
Commission for approval. If a settlement agreement is not reached in a
proceeding by February 14, 1997, the parties will have an additional 60-day
period to submit any necessary briefs or other submissions to an
administrative law judge. At the end of the 60-day period, the record in a
proceeding will be closed and the matter will be submitted to the Commission
for decision.

    Given the uncertainties regarding the Competitive Opportunities
Proceeding, the Company is unable to predict the outcome of this regulatory
proceeding and the ultimate effect on the Company's financial position or
results of operations.

NEW JERSEY--ENERGY MASTER PLAN

    On January 16, 1997, the NJBPU issued Proposed Findings and
Recommendations for restructuring the electric power industry in New Jersey
and introducing competition into the generation sector of the utility
business (the Preliminary Report). The preliminary findings and
recommendations contained in the Preliminary Report have been issued for
public comment. The final report is scheduled to be issued in March 1997. The
Preliminary Report calls for each of the state's utilities to file proposals
for NJBPU review and approval by July 15, 1997 to implement retail
competition, functionally separate generation from the utility's other
operations, unbundle its current rate structure to accommodate customer
choice, and propose a stranded cost recovery plan. The Preliminary Report
proposes that retail choice be phased-in encompassing a cross-section of all
customer classes over a two and one-half year period beginning in October
1998 and concluding April 2001. In addition, the Preliminary Report calls for
regulatory assets and non-utility generator purchased power contracts to
continue to be fully recoverable in rates. With respect to above market
generation costs, the NJBPU has endorsed the creation of a Market Transition
Charge (MTC) as a non-bypassable component of the delivery price of
electricity which would be assessed for a period of four to eight years in
order to provide utilities with the opportunity for recovery of stranded
costs associated with generation capacity commitments made prior to the
advent of competition. The amount of the MTC authorized and the length of
time assessed is to be determined by the NJBPU on a case by case basis
following a review of the July 15, 1997 filings made by each utility and will
be contingent upon a number of conditions, including achievement of near-term
rate reduction goals and cost mitigation measures instituted. The filings may
be accepted or significantly modified by the NJBPU before becoming effective.
It is not possible to predict the outcome of the NJBPU proceeding regarding
the filings or its impact on the Company's consolidated financial position or
results of operations at this time.

PENNSYLVANIA--COMPETITION LEGISLATION

    On December 3, 1996, the "Electricity Generation Customer Choice and
Competition Act" (Act) was signed into law by the Governor of the State of
Pennsylvania. The Act provides for a transition of the Pennsylvania electric
industry from a vertically integrated structure to a functionally separated
model that permits direct access by customers to a competitive electric
generation market while retaining the existing regulation and customer
protections for the transmission and distribution systems. The transition
plan of the Act calls for a three-year phase-in of retail access beginning
January 1, 1998 and concluding January 1, 2001. The Act also provides for the
opportunity for recovery of prudent and verifiable costs resulting from the
restructuring through the implementation of a Competitive Transition Charge
(CTC) for a period of up to nine years and the imposition of rate caps
designed to prevent a customer's total electric costs from increasing during
the transition period above current levels. In addition, the Act permits the
refinancing of certain approved transition costs through the issuance of
bonds secured by revenue streams guaranteed by the Pennsylvania Public
Utility Commission (PPUC). The savings associated with this financing
mechanism will be used to reduce strandable costs. The Act requires all
Pennsylvania utilities to file restructuring plans with the PPUC no later
than September 30, 1997. The PPUC is required to issue an order accepting,
rejecting or modifying the plan within nine months of the filing. Pike County
Light & Power Company (Pike), a wholly owned utility subsidiary of the
Company, is reviewing the Act and will submit its restructuring plan to the
PPUC no later than September 30, 1997. The Company's plan could be accepted
or significantly modified before it becomes effective. It is not possible to
predict the outcome of the PPUC proceeding required by the Act or its impact
on the Company's consolidated financial position or results of operations at
this time.

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.

                                        16


<TABLE>
    Consolidated Statements of Income and Retained Earnings
<CAPTION>

                                                                                   YEAR ENDED DECEMBER 31,
                                                                                 1996        1995        1994
                                                                              ----------  ----------  ----------
                                                                                    (THOUSANDS OF DOLLARS)
<S>                                                                           <C>         <C>          <C>
Operating Revenues:
 Electric (Note 1)..........................................................  $  473,936  $  457,833  $  472,393
 Gas (Note 1)...............................................................     176,442     140,224     157,168
 Electric sales to other utilities..........................................       3,106       2,150       6,636
                                                                              ----------  ----------  ----------
  Total Utility Revenues....................................................     653,484     600,207     636,197

 Diversified activities (Note 1)............................................     271,566     429,625     380,470
                                                                              ----------  ----------  ----------
Total Operating Revenues....................................................     925,050   1,029,832   1,016,667
                                                                              ----------  ----------  ----------
Operating Expenses:
 Operations:
  Fuel used in electric production (Note 1).................................      54,917      69,042      84,860
  Electricity purchased for resale (Note 1).................................      73,776      54,700      49,391
  Gas purchased for resale(Note 1)..........................................     101,614      71,566      88,304
  Non-utility gas marketing purchases.......................................     264,100     419,485     365,902
  Other expenses of operation...............................................     158,880     143,009     151,918
 Maintenance................................................................      36,652      41,190      44,011
 Depreciation and amortization (Note 1).....................................      33,613      38,547      35,683
 Taxes other than income taxes..............................................      98,037      93,887      95,962
 Federal income taxes (Notes 1 and 2).......................................      24,820      25,902      24,629
                                                                              ----------  ----------  ----------
  Total Operating Expenses..................................................     846,409     957,328     940,660
                                                                              ----------  ----------  ----------
Income from Operations......................................................      78,641      72,504      76,007
                                                                              ----------  ----------  ----------
Other Income and Deductions:
 Allowance for other funds used during construction.........................          20          28          69
 Investigation and litigation costs (Note 12)...............................      (1,800)     (7,218)     (8,795)
 Other--net.................................................................         297       4,721        (754)
 Taxes other than income taxes..............................................        (281)       (581)       (123)
 Federal income taxes (Notes 1 and 2).......................................         520       1,828       4,250
                                                                              ----------  ----------  ----------
  Total Other Income and Deductions.........................................      (1,244)     (1,222)     (5,353)
                                                                              ----------  ----------  ----------
Income Before Interest Charges..............................................      77,397      71,282      70,654
                                                                              ----------  ----------  ----------
Interest Charges:
 Interest on long-term debt.................................................      24,221      26,620      29,553
 Other interest.............................................................       5,977       5,495       3,088
 Amortization of debt premium and expense--net..............................       1,462       1,394       1,244
 Allowance for borrowed funds used during construction......................        (566)       (800)       (448)
                                                                              ----------  ----------  ----------
  Total Interest Charges....................................................      31,094      32,709      33,437
                                                                              ----------  ----------  ----------
Net Income..................................................................      46,303      38,573      37,217
Dividends on preferred and preference stock, at required rates..............       3,024       3,135       3,251
                                                                              ----------  ----------  ----------
Earnings applicable to common stock.........................................      43,279      35,438      33,966
Cash dividends on common stock: $2.58, $2.57 and $2.54, respectively........      35,227      35,089      34,486
                                                                              ----------  ----------  ----------
Balance to retained earnings................................................       8,052         349        (520)
Retained earnings, beginning of year........................................     184,008     183,659     184,179
                                                                              ----------  ----------  ----------
Retained earnings, end of year..............................................  $  192,060  $  184,008  $  183,659
                                                                              ----------  ----------  ----------
Average number of common shares outstanding (000's).........................      13,654      13,653      13,594
                                                                              ----------  ----------  ----------
Earnings per average common share outstanding...............................  $     3.17  $     2.60  $     2.50
                                                                              ----------  ----------  ----------
 
    The accompanying notes are an integral part of these statements.
</TABLE>
                                       17

<TABLE>
                                      CONSOLIDATED BALANCE SHEETS
<CAPTION>


                                                                           DECEMBER 31,
                                                                        1996          1995
                                                                    ------------  ------------
                                                                      (THOUSANDS OF DOLLARS)
<S>                                                                 <C>           <C>         
Assets:
Utility Plant:
 Electric.........................................................  $  1,023,796  $    993,926
 Gas..............................................................       219,712       211,135
 Common...........................................................        59,589        56,796
                                                                    ------------  ------------
  Utility Plant in Service........................................     1,303,097     1,261,857
 Less accumulated depreciation....................................       440,333       419,844
                                                                    ------------  ------------
  Net Utility Plant in Service....................................       862,764       842,013
 Construction work in progress....................................        36,879        31,655
                                                                    ------------  ------------
  Net Utility Plant (Notes 1, 7 and 12)...........................       899,643       873,668
                                                                    ------------  ------------
Non-utility Property:
 Non-utility property.............................................        20,784        34,376
 Less accumulated depreciation, depletion and amortization........         3,778        12,945
                                                                    ------------  ------------
  Net Non-utility Property (Notes 1 and 7)........................        17,006        21,431
                                                                    ------------  ------------
Current Assets:
 Cash and cash equivalents (Notes 8 and 9)........................         3,485         5,164
 Temporary cash investments (Note 9)..............................         1,289         1,335
 Customer accounts receivable, less allowance for uncollectible
  accounts of $2,391 and $2,307, respectively.....................        60,992        61,653
 Accrued utility revenue (Note 1).................................        22,773        22,198
 Other accounts receivable, less allowance for uncollectible
  accounts of $258 and $169, respectively.........................        10,473         9,752
 Gas marketing accounts receivable, less allowance for
  uncollectible accounts of $606 and $133, respectively...........        45,589        51,198
 Materials and supplies (at average cost):
  Fuel for electric generation....................................         7,201         8,290
  Gas in storage..................................................        12,819         8,627
  Construction and other supplies.................................        15,575        15,751
 Prepaid property taxes...........................................        20,051        20,687
 Prepayments and other current assets.............................        22,478        26,463
                                                                    ------------  ------------
  Total Current Assets............................................       222,725       231,118
                                                                    ------------  ------------
Deferred Debits:
 Income tax recoverable in future rates (Notes 1 and 2)...........        74,198        72,631
 Extraordinary property loss--Sterling Nuclear Project (Notes 1 and
  3)..............................................................         2,849         4,250
 Deferred Order 636 transition costs (Notes 1 and 12).............        11,732         6,064
 Deferred revenue taxes (Note 1)..................................        14,271        15,596
 Deferred pension and other postretirement benefits (Notes 1 and
  10).............................................................         9,922        10,422
 IPP settlement agreements (Note 1)...............................        24,065        40,034
 Unamortized debt expense (amortized over term of securities).....        10,046        11,417
 Other deferred debits............................................        27,173        20,239
                                                                    ------------  ------------
  Total Deferred Debits...........................................       174,256       180,653
                                                                    ------------  ------------
  Total Assets....................................................  $  1,313,630  $  1,306,870
                                                                    ------------  ------------
 
        The accompanying notes are an integral part of these statements.
</TABLE>
                                       18
<TABLE>
<CAPTION>
                                                                           DECEMBER 31
                                                                        1996          1995
                                                                    ------------  ------------
                                                                      (THOUSANDS OF DOLLARS)
<S>                                                                 <C>           <C>          
Capitalization and Liabilities:
Capitalization:
 Common stock (Note 5)............................................  $     68,271  $     68,268
 Premium on capital stock (Note 5)................................       133,616       133,607
 Capital stock expense............................................        (6,097)       (6,107)
 Retained earnings (Note 4).......................................       192,060       184,008
                                                                    ------------  ------------
  Total Common Stock Equity.......................................       387,850       379,776
                                                                    ------------  ------------
 Non-redeemable preferred stock...................................        42,844        42,844
 Non-redeemable cumulative preference stock.......................           397           409
                                                                    ------------  ------------
  Total Non-Redeemable Stock (Note 5).............................        43,241        43,253
                                                                    ------------  ------------
 Redeemable preferred stock (Note 6)..............................       --              1,390
                                                                    ------------  ------------
 Long-term debt (Notes 7 and 9)...................................       281,622       359,736
                                                                    ------------  ------------
  Total Capitalization............................................       712,713       784,155
                                                                    ------------  ------------
Non-current Liabilities:
 Reserve for claims and damages (Note 1)..........................         3,843         3,848
 Postretirement benefits (Note 10)................................        15,213        13,756
 Pension costs (Note 10)..........................................        37,421        38,740
                                                                    ------------  ------------
  Total Non-current Liabilities...................................        56,477        56,344
                                                                    ------------  ------------
Current Liabilities:
 Long-term debt due within one year (Note 7)......................        78,203           466
 Preferred stock to be redeemed within one year (Note 6)..........         1,390         1,384
 Notes payable (Notes 8 and 9)....................................         1,005         7,300
 Commercial paper (Notes 8 and 9).................................        82,370        61,250
 Accounts payable.................................................        67,036        62,082
 Gas marketing accounts payable...................................        42,295        44,630
 Dividends payable................................................           665           693
 Customer deposits................................................         4,865         5,455
 Accrued Federal income and other taxes...........................         1,268         2,050
 Accrued interest.................................................         7,039         7,252
 Refundable gas costs (Note 1)....................................         6,839        10,111
 Refunds to customers.............................................         1,816        13,903
 Other current liabilities........................................        26,400        22,942
                                                                    ------------  ------------
  Total Current Liabilities.......................................       321,191       239,518
                                                                    ------------  ------------
Deferred Taxes and Other:
 Deferred Federal income taxes (Notes 1 and 2)....................       186,354       183,396
 Deferred investment tax credits (Notes 1 and 2)..................        15,292        16,217
 Accrued Order 636 transition costs (Note 12).....................        11,620         5,980
 Accrued IPP settlement agreements (Note 1).......................         2,000        17,500
 Other deferred credits...........................................         7,983         3,760
                                                                    ------------  ------------
  Total Deferred Taxes and Other..................................       223,249       226,853
                                                                    ------------  ------------
Commitments and Contingencies (Note 12):..........................       --            --
                                                                    ------------  ------------
  Total Capitalization and Liabilities............................  $  1,313,630  $  1,306,870
                                                                    ------------  ------------
 
                                       19
</TABLE>
<TABLE>

Consolidated Cash Flow Statements
<CAPTION>

                                                                                       YEAR ENDED DECEMBER 31,
                                                                                     1996       1995       1994
                                                                                   ---------  ---------  ---------
                                                                                       (THOUSANDS OF DOLLARS)
<S>                                                                                <C>        <C>        <C>
Cash Flow from Operations:
 Net income......................................................................  $  46,303  $  38,573  $  37,217
 Adjustments to reconcile net income to net cash provided by operating activities:
  Depreciation and amortization..................................................     34,150     37,131     35,938
  Deferred Federal income taxes..................................................      5,545      9,924       (188)
  Amortization of investment tax credit..........................................       (924)      (892)      (895)
  Deferred and refundable fuel and gas costs.....................................     (6,371)    (6,606)     4,548
  Allowance for funds used during construction...................................       (586)      (828)      (517)
  Other non-cash changes.........................................................      3,759      8,682      6,042
 Changes in certain current assets and liabilities:
    Accounts and gas marketing receivables, net and accrued utility revenue......      4,974      2,431     (3,101)
    Materials and supplies.......................................................     (2,927)     4,941      1,226
    Prepaid property taxes.......................................................        636     (1,360)      (913)
    Prepayments and other current assets.........................................      3,985      2,414     (6,665)
    Operating and gas marketing accounts payable.................................      2,619    (29,056)    24,162
    Accrued Federal income and other taxes.......................................       (782)    (3,899)    (3,637)
    Accrued interest.............................................................       (213)    (1,356)    (1,269)
    Refunds to customers.........................................................    (12,087)     3,638      9,472
    Other current liabilities....................................................      2,868      6,601       (332)
  Other--net.....................................................................      1,380     (7,123)    16,402
                                                                                   ---------  ---------  ---------
   Net Cash Provided by Operations...............................................     82,329     63,215    117,490
                                                                                   ---------  ---------  ---------
Cash Flow from Investing Activities:
 Additions to plant..............................................................    (59,357)   (55,030)   (60,542)
 Temporary cash investments......................................................         46        504       (392)
 Allowance for funds used during construction....................................        586        828        517
                                                                                   ---------  ---------  ---------
   Net Cash Used in Investing Activities.........................................    (58,725)   (53,698)   (60,417)
                                                                                   ---------  ---------  ---------
Cash Flow from Financing Activities:
 Proceeds from:
  Issuance of common stock........................................................    --         --          3,868
  Issuance of long-term debt......................................................        26     44,048     55,000
 Retirement of:
  Preference and preferred stock.................................................     (1,384)    (1,384)    (1,384)
  Long-term debt.................................................................       (195)   (63,471)   (57,688)
  Capital lease obligations--net.................................................       (275)      (518)      (479)
 Net borrowings (repayments) under short-term debt arrangements..................     14,825     39,150    (16,800)
 Dividends on preferred and common stock.........................................    (38,280)   (38,259)   (37,765)
                                                                                   ---------  ---------  ---------
   Net Cash Used in Financing Activities.........................................    (25,283)   (20,434)   (55,248)
                                                                                   ---------  ---------  ---------
Net Change in Cash and Cash Equivalents..........................................     (1,679)   (10,917)     1,825
Cash and Cash Equivalents at Beginning of Year...................................      5,164     16,081     14,256
                                                                                   ---------  ---------  ---------
Cash and Cash Equivalents at End of Year.........................................  $   3,485  $   5,164  $  16,081
                                                                                   ---------  ---------  ---------
Supplemental Disclosure of Cash Flow Information
 Cash paid during the year for:
  Interest, net of amounts capitalized...........................................  $  29,438  $  31,782  $  33,134
  Federal income taxes...........................................................  $  17,982  $  15,575  $  21,558
                                                                                   ---------  ---------  ---------

        The accompanying notes are an integral part of these statements.

                                       20
</TABLE>
                   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 gas marketing and
land development companies.

RATE REGULATION

    The Company, RECO and Pike are subject to rate regulation by the New York
Public Service Commission (NYPSC), the New Jersey Board of Public Utiliti es
(NJBPU), the Pennsylvania Public Utility Commission (PPUC) and the FERC. The
consolidated financial statements of the Company are based on generally
accepted accounting principles, including the provisions of Statement of
Finan cial 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,
1996 and 1995:
<TABLE>
<CAPTION>
                                                                           1996        1995
                                                                        ----------  ----------
                                                                        (THOUSANDS OF DOLLARS)
<S>                                                                     <C>         <C>
Deferred Income Taxes (Note 2)........................................  $   74,198  $   72,631
Extraordinary Property Loss (Note 3)..................................       2,849       4,250
FERC Order 636 Costs (Note 12)........................................      11,732       6,064
Deferred Revenue Taxes (Note 1).......................................      14,271      15,596
Deferred Pension and Other Postretirement Benefits (Note 10)..........       9,922      10,422
Gas Take-or-Pay Costs (Note 12).......................................       2,117       1,640
Revenue Decoupling Mechanism (Note 1).................................      --          (2,485)
Deferred Plant Maintenance Costs (Note 1).............................       4,244       4,944
Demand-Side Management Costs (Note 1).................................       1,181        (445)
Deferred Fuel and Gas Costs (Note 1)..................................      (4,943)    (11,314)
IPP Settlement Agreements (Note 1)....................................      24,065      40,034
Other.................................................................       5,985       5,778
                                                                        ----------  ----------
  Total...............................................................  $  145,621  $  147,115
                                                                        ----------  ----------
</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 Com pany adopted this
standard on January 1, 1996. Based on the current regulatory structure in
which the Company operates, the adoption did 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. Effective May 1, 1996, as part of an agreement with the NYPSC, the
Company eliminated its Revenue Decoupling Mechanism (RDM) for New York's
electric revenues. Therefore, the electric revenues effective May 3, 1996 are
based on actual sales. Previously, New York electric revenues were recognized
in the accompanying consolidated financial statements based on amounts
included in rates.

    The level of revenues from gas sales in New York is subject to a weather
normalization clause that required recovery from or refund to firm customers
for 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 or
credited 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 12-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 12-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.

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

                                21


following composite rates based on the average depreciable plant balances at
the beginning and end of the year:
<TABLE>
<CAPTION>

YEAR ENDED DECEMBER 31,                                                                         1996       1995       1994
--------------------------------------------------------------------------------------------  ---------  ---------  ---------
<S>                                                                                                <C>        <C>        <C> 
Plant Classification:
 Electric...................................................................................       2.88%      3.07%      3.05%
 Gas........................................................................................       2.91%      2.95%      2.80%
 Common.....................................................................................       5.93%      6.64%      6.37%
                                                                                                   ----       ----       ----
</TABLE>
 
    The composite gas depreciation rate in 1996 excludes the effects of
adjustments provided for in the gas rate agreement with the NYPSC.

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.
Energy is allocated to the participants based on an agreement dated May 31,
1996. This agreement entitles each company to a certain amount of energy at
different periods during the year. The operation and maintenance expenses of
the facility are allocated to the Company on a one-third basis, except for
major maintenance which is allocated 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,                                                    1996        1995
----------------------------------------------------------------------  ----------  ----------
                                                                        (THOUSANDS OF DOLLARS)
<S>                                                                     <C>         <C>       
Electric Utility Plant in Service.....................................  $  102,309  $  101,747
Construction Work in Progress.........................................  $    1,317  $    1,038
                                                                        ----------  ----------
</TABLE>
FEDERAL INCOME TAXES

    The Company and its subsidiaries file a consolidated federal income tax
return, and income taxes are allocated based on the taxable income or loss of
each company. 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 prepared
pursuant to the provisions of Statement of Financial Accounting Standards No.
109 (SFAS No. 109) "Accounting for Income Taxes," which requires 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 or liability, as
appropriate.

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 10-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 and 1995, the Company negotiated termination agreements with
Independent Power Producers (IPP) scheduled to provide electric generating
capacity and energy services to the Company in the late 1990's.

    At December 31, 1996, $24.1 million of termination costs associated with
these settlement agreements are being recovered 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 10-year
amortization. On January 12, 1996, the NJBPU authorized RECO to capitalize
these costs 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

    The Company sold the six radio broadcasting properties operated by a
wholly owned indirect subsidiary, Atlantic Morris Broadcasting, Inc. (AMB),
during 1995.

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

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) has completed its examination of the
Company's tax returns for 1990, 1991 and 1992. The Company and IRS have
agreed to an assessment for a tax deficiency of approximately $1.7 million
plus interest, which primarily relates to the misuse and misappropriation of
Company funds during this period. After offsetting the assessment with
established reserves and other related items, this action had a minimal
effect on the operating results of the Company.

    The IRS has recently commenced its examination of the Company's tax
returns for 1993 and 1994.

    The components of federal income taxes are as follows:
<TABLE>
<CAPTION>

YEAR ENDED DECEMBER 31,                                                              1996       1995       1994
---------------------------------------------------------------------------------  ---------  ---------  ---------
                                                                                       (THOUSANDS OF DOLLARS)
<S>                                                                                <C>        <C>        <C>
Charged to operations:
 Current.........................................................................  $  19,588  $  18,048  $  24,439
 Deferred-net....................................................................      5,360      7,976        322
 Amortization of investment tax credit...........................................       (128)      (122)      (132)
                                                                                   ---------  ---------  ---------
  Total charged to operations....................................................     24,820     25,902     24,629
                                                                                   ---------  ---------  ---------
Charged to other income:
 Current.........................................................................         92     (3,160)    (3,042)
 Deferred-net....................................................................        184      2,097       (450)
 Amortization of investment tax credit...........................................       (796)      (765)      (758)
                                                                                   ---------  ---------  ---------
  Total charged to other income..................................................       (520)    (1,828)    (4,250)
                                                                                   ---------  ---------  ---------
Total............................................................................  $  24,300  $  24,074  $  20,379
                                                                                   ---------  ---------  ---------
 </TABLE>

    The tax effect of temporary differences which gave rise to deferred tax
assets and liabilities is as follows:
<TABLE>
<CAPTION>

AS OF DECEMBER 31,                                                         1996        1995
----------------------------------------------------------------------  ----------  ----------
                                                                        (THOUSANDS OF DOLLARS)
<S>                                                                     <C>         <C>       
Liabilities:
 Accelerated depreciation.............................................  $  188,039  $  180,954
 Other................................................................      30,887      33,073
                                                                        ----------  ----------
  Total liabilities...................................................     218,926     214,027
                                                                        ----------  ----------
Assets:
 Employee benefits....................................................     (17,136)    (14,902)
 Deferred fuel costs..................................................        (404)     (1,601)
 Other................................................................     (15,032)    (14,128)
                                                                        ----------  ----------
  Total assets........................................................     (32,572)    (30,631)
                                                                        ----------  ----------
Net Liability.........................................................  $  186,354  $  183,396
                                                                        ----------  ----------
</TABLE>
 
                                       22

    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,                                                                           1996         1995         1994
---------------------------------------------------------------------------------------------     -----        -----        -----
                                                                                               (% 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)          (1)          (2)
 Cost of removal.............................................................................      (1)          (2)          (1)
 Additional depreciation deducted for book purposes..........................................       4            5            5
 Other.......................................................................................      (3)           --          (2)
                                                                                                 -----         -----        ----
Effective Tax Rate...........................................................................      34%          37%          35%
                                                                                                 -----         -----        ----
</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 recovered all of its share of costs associated with the
Sterling Nuclear Project. The NJBPU had approved a 20-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, 1996 and 1995, the unamortized Sterling Project costs
which have been approved for amortization and recovery, before reduction for
deferred taxes, amounted to $3.0 million and $4.6 million, respectively. All
of the $3.0 million in 1996 and $3.9 million of the 1995 costs 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, 1996 and 1995 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 1994, 1995 and 1996.
<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 12/31/93:........................    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
 Conversions.............................           508          3                              (359)        (12)           9
                                           ------------  ---------  ---------  ---------  ----------       -----   ----------
Balance 12/31/96:........................    13,654,121  $  68,271    428,443  $  42,844      12,180   $     397   $  133,616
                                           ------------  ---------  ---------  ---------  ----------       -----   ----------
Shares Authorized........................    50,000,000               820,000              1,500,000
                                           ------------  ---------  ---------  ---------  ----------       -----   ----------


*(in thousands)

    (A) At December 31, 1996, 17,905 shares of common stock were reserved for
conversion of preference stock.

    (B) Non-Redeemable Preferred Stock (cumulative):
</TABLE>
<TABLE>
<CAPTION>
                                                                                  Par Value
                                                                                  ---------          CALLABLE
                                                                                 DECEMBER 31,       REDEMPTION
                                                                   SHARES       1994, 1995 AND      PRICE PER
SERIES                                                           OUTSTANDING         1996             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.

NOTE 6. REDEEMABLE PREFERRED STOCK

    The table below summarizes the changes in Redeemable Cumulative Preferred
Stock, issued and outstanding, for the years 1994, 1995 and 1996.
<TABLE>
<CAPTION>
                                                                              ($100 PAR VALUE)
                                                                           ----------------------
                                                                            SHARES      AMOUNT*
                                                                           ---------  -----------
<S>                                                                          <C>       <C>      
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
 Redemptions.............................................................    (13,842)     (1,384)
                                                                           ---------  -----------
Balance 12/31/96:........................................................     13,896   $   1,390
                                                                           ---------  -----------
Shares Authorized........................................................    180,000
                                                                           ---------
</TABLE>
 
    On January 6, 1997, the Company redeemed the remaining 13,896 shares of
Redeemable Cumulative Preferred Stock, Series I, 8 1/8% then outstanding, at
$100 per share.

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 1996 by allocating an amount of additional property. The Company has
one remaining series of First Mortgage Bonds outstanding, the Series I,
6 1/2%, due October 1, 1997, in the principal amount of $23.0 million. The
indenture under which the Company's debentures are issued contains a covenant
restricting the issuance by the Company of secured indebtedness while any
securities are outstanding under the debenture indenture. The covenant
prohibits the Company from issuing additional bonds under the First Mortgage
Indenture. 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 1996 were satisfied by the allocation of an amount of additional
property

                                     23


and Pike expects to continue such practice in succeeding years. Details of
long-term debt at December 31, 1996 and 1995 are as follows:
<TABLE>
<CAPTION>

DECEMBER 31,                                                                                    1996       1995
-------------------------------------------------------------------------------------------  ----------  ---------
                                                                                                 (THOUSANDS OF
                                                                                                   DOLLARS)
<S>                                                                                          <C>         <C>   
Orange and Rockland Utilities, Inc.:
 First Mortgage Bonds:
  Series I, 6 1/2% due Oct. 1, 1997........................................................  $   23,000  $  23,000
 Promissory Notes (unsecured)
  6.9%--6.96% due through July 15, 2000....................................................          56         48
  6.09% due Oct. 1, 2014 (a)...............................................................      55,000     55,000
  Variable due Aug. 1, 2015 (b)............................................................      44,000     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 H, 9.59% due July 1, 2020 (c).....................................................      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.........................................................       5,228      5,405
                                                                                             ----------  ---------
                                                                                                359,968    360,137
  Less: Amount due within one year.........................................................      78,203        192
                                                                                             ----------  ---------
                                                                                                281,765    359,945
  Unamortized discount on long-term debt...................................................        (143)      (209)
                                                                                             ----------  ---------
  Total Long-Term Debt.....................................................................  $  281,622  $ 359,736
                                                                                             ----------  ---------
</TABLE>
    (a) The Company's $55 million Promissory Note was issued in connection
with the New York State Energy Research and Development Authority (NYSERDA)
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 counter party 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 NYSERDA's $44 million variable rate Pollution Control Refunding
Bonds due August 1, 2015 (the 1995 Bonds). The average interest rate on the
1995 Bonds was 3.18% in 1996 and 3.63% in 1995. The interest rate is adjusted
weekly, unless converted to a fixed rate.

    (c) On February 4, 1997, RECO issued $20 million of First Mortgage 7 1/8%
Bonds, Series J due February 1, 2007 (Series J Bonds). The proceeds from the
issuance of the Series J Bonds, together with other RECO funds will be used to
refund, in March 1997, RECO's $20 million First Mortgage 9.59% Bonds, Series
H.

    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 1996 is as follows: 1997 --$78,212,000;
1998--$139,000; 1999--$4,956,000; 2000--$120,014,000; 2001 --$884,000.

    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.

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, 1996, the Company and its utility subsidiaries had
unsecured bank lines of credit totaling $100 million. 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 diversified operation of RECO, maintains a $20 million line of
credit with one commercial bank under which there were $2.0 million of
letters of credit outstanding at December 31, 1996. Additionally, NORSTAR had
$1.0 million of notes outstanding under this line of credit. 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
1996, 1995 and 1994 had maturity dates of three months or less. Information
regarding short-term borrowings during the past three years is as follows:
<TABLE>
<CAPTION>
                                                                                             1996       1995       1994
                                                                                           ---------  ---------  ---------
                                                                                                (MILLIONS OF DOLLARS)
<S>                                                                                        <C>        <C>        <C>
Weighted average interest rate at year-end...............................................        6.5%       6.1%       6.4%
Amount outstanding at year-end...........................................................  $    84.0  $    68.6  $    29.4
Average amount outstanding for the year..................................................  $    66.6  $    37.1  $    31.3
Daily weighted average interest rate during the year.....................................        5.7%       6.1%       4.5%
Maximum amount outstanding at any month-end..............................................  $    97.5  $    69.6  $    42.9
                                                                                           ---------  ---------  ---------
</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 carrying amount of the Company's
redeemable preferred stock approximates fair value because of the redemption
and retirement of that instrument on January 6, 1997.
<TABLE>
<CAPTION>
                                                                                1996                  1995
                                                                        --------------------  --------------------
                                                                        CARRYING     FAIR     CARRYING     FAIR
                                                                         AMOUNT     AMOUNT     AMOUNT     AMOUNT
                                                                        ---------  ---------  ---------  ---------
                                                                                  (THOUSANDS OF DOLLARS)
<S>                                                                     <C>        <C>        <C>        <C> 
Cash and cash equivalents.............................................  $   3,485  $   3,485  $   5,164  $   5,164
Temporary cash investments............................................      1,289      1,289      1,335      1,335
Long-term debt........................................................    359,968    366,509    360,137    349,694
Notes payable and commercial paper....................................     83,375     83,375     68,550     68,550
Redeemable preferred stock............................................      1,390      1,390      2,774      2,820
                                                                         --------   --------   --------   --------
</TABLE>
 
OFF BALANCE SHEET AND DERIVATIVE FINANCIAL INSTRUMENTS

    The Company and its gas marketing subsidiary utilize 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

                                      24


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. The variable
rate 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, 1996, the Company would have been required to make a payment of
approximately $7.6 million to the Swap counterparty.

    Gas Futures Contracts--Natural Gas Futures Contracts are bought and sold
on the New York Mercantile Exchange (NYMEX) by NORSTAR to hedge the physical
sale and purchase of natural gas. The contracts are generally purchased or
sold at the same time that the physical transaction is executed. The hedges
are liquidated during the last three days of the NYMEX contract settlement
each month which is the same period of time when the physical transaction is
completed.

    When physical supply is sold at a fixed price, the margin on the ultimate
commodity transaction is locked in by buying NYMEX futures contract(s). If
physical supply is purchased at a fixed price, the margin is locked in by
selling NYMEX futures contract(s).

    These NYMEX contracts are managed by executing trades in a timely manner
when the physical transaction occurs and executing the number of contracts in
lots which are close in volume to the physical volume. Also, the futures are
bought and sold at price levels that maximize the value of the physical side
of the transaction.

    Futures contracts outstanding at December 31, 1996 and December 31, 1995,
amounted to 351 contracts purchased and 449 contracts purchased,
respectively. The related margin deposits with brokers at December 31, 1996
and December 31, 1995, amounted to $1,433,221 and $2,202,542, respectively.
The underlying futures contracts as of December 31, 1996 are of varying
durations, none of which extend beyond March 1998. The fair value of the open
futures contracts at December 31, 1996 and the amount NORSTAR would receive
if these were settled on that day was approximately $940,220. Deferred
hedging gains at December 31, 1996 relating to futures contracts were
$3,070,460. Deferred gains at December 31, 1995 relating to futures contracts
were $2,035,000. The January 1997 contracts were settled on December 24,
1996. These gains of $2,130,240 were deferred at December 31, 1996 and will
be recognized in January 1997 when NORSTAR physically delivers the gas in
January 1997 (i.e., the business NORSTAR hedged).

    The Company is exposed to credit risk in the event of nonperfor-mance by
the counterparties of the transaction which they hedge. The Company believes
that the credit risk related to the futures 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 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.

    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, 1996 and 1995. Plan assets are stated at fair
market value and are composed primarily of common stocks and investment grade
debt securities.
<TABLE>
<CAPTION>

DECEMBER 31,                                                             1996         1995
--------------------------------------------------------------------  -----------  -----------
                                                                       (THOUSANDS OF DOLLARS)
<S>                                                                   <C>          <C>        
Actuarial present value of benefit obligations:
 Vested.............................................................  $  (191,499) $  (178,903)
 Nonvested..........................................................      (15,947)     (15,719)
                                                                      -----------  -----------
Accumulated benefit obligation......................................  $  (207,446) $  (194,622)
                                                                      -----------  -----------
Projected benefit obligation........................................  $  (216,821) $  (203,956)
Plan assets at fair market value....................................      225,997      205,342
                                                                      -----------  -----------
Excess of plan assets over projected benefit obligation.............        9,176        1,386
Unamortized net transition asset at adoption of SFAS No. 87 being
  amortized over 15 years...........................................       (5,568)      (6,681)
Unrecognized prior service costs....................................       29,485       32,455
Unrecognized net gain...............................................      (58,497)     (55,649)
                                                                      -----------  -----------
Accrued Pension Cost................................................  $   (25,404) $   (28,489)
                                                                      -----------  -----------
</TABLE>

    Net periodic pension expense calculated pursuant to the requirements of
SFAS No. 87 for the years 1996, 1995 and 1994 includes the following
components:
<TABLE>
<CAPTION>

DECEMBER 31,                                                                          1996       1995       1994
----------------------------------------------------------------------------------  ---------  ---------  ---------
                                                                                        (THOUSANDS OF DOLLARS)
<S>                                                                                 <C>        <C>        <C>
Service cost-benefits earned during year..........................................  $   5,456  $   5,151  $   6,250
Interest cost on projected benefit obligation.....................................     15,135     14,996     14,132
Actual return on plan assets......................................................    (25,293)   (37,863)     2,634
Net deferral and capitalized......................................................      7,579     20,129    (18,426)
                                                                                    ---------  ---------  ---------
Net Pension Expense...............................................................  $   2,877  $   2,413  $   4,590
                                                                                    ---------  ---------  ---------
</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 for 1996 and 1995
were 8.0%, 7.5% and 2.5%, respectively.

    In addition to the pension plan described above, the Company has an
unfunded non-contributory supplemental retirement plan covering certain
management employees. The cost to the Company of the supplemental plan in
1996, 1995 and 1994 was $1.6 million, $0.7 million and $0.8 million,
respectively.

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

                                      25


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. Similar procedures have been adopted by the
NJBPU and PPUC for the operations in those states. The NYPSC and PPUC allow
the Company to recover SFAS No. 106 costs applicable to electric operations
and gas operations currently in rates. New Jersey electric operations will be
addressed in future rate filings.

    In order to provide funding for active employees' postretirement
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 1996, the
Company contributed $5.4 million to the VEBA trust. Rate recoveries and
billings to others totaled $5.1 million in 1996 and $3.9 million in 1995. As
permitted by SFAS No. 106, the Company has elected to amortize the
accumulated postretirement benefit obligation at 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, 1996 and December 31, 1995:
<TABLE>
<CAPTION>
                                                                           1996        1995
                                                                        ----------  ----------
                                                                        (THOUSANDS OF DOLLARS)
<S>                                                                     <C>         <C>       
Accumulated postretirement benefit obligation:
 Fully eligible active employees......................................  $  (13,765) $  (18,989)
 Other active employees...............................................     (34,902)    (31,644)
 Retirees.............................................................     (34,332)    (26,976)
                                                                        ----------  ----------
  Total benefit obligation............................................     (82,999)    (77,609)
Plan assets at fair value.............................................      14,822       8,926
                                                                        ----------  ----------
Accumulated postretirement obligation in excess of plan assets........     (68,177)    (68,683)
Unrecognized transition obligation....................................      44,409      47,185
Prior service cost....................................................       2,174      --
Unrecognized experience net loss......................................       6,881       8,639
                                                                        ----------  ----------
Accrued Postretirement Benefit Cost...................................  $  (14,713) $  (12,859)
                                                                        ----------  ----------
</TABLE>
    The components of net periodic postretirement benefit cost for the years
ended December 31, 1996, 1995 and 1994 are as follows:
<TABLE>
<CAPTION>
                                                                                         1996       1995       1994
                                                                                       ---------  ---------  ---------
                                                                                           (THOUSANDS OF DOLLARS)
<S>                                                                                    <C>        <C>        <C>
Service cost.........................................................................  $   2,050  $   1,586  $   1,817
Interest cost........................................................................      5,925      5,622      5,198
Return on plan assets................................................................       (546)      (319)    --
Amortization of transition obligation................................................      2,776      2,790      2,861
Prior service cost...................................................................        202     --         --
Net losses...........................................................................        855        529        553
Deferred and capitalized.............................................................     (2,400)    (3,424)    (4,480)
                                                                                       ---------  ---------  ---------
Net Expense..........................................................................  $   8,862  $   6,784  $   5,949
                                                                                       ---------  ---------  ---------
</TABLE>
 
    The calculation of the actuarial present value of benefit obligations at
December 31, 1996 assumes a discount rate of 7.5% and health care cost trend
rates of 7.5% for medical costs and 10.0% for prescription drugs in 1997,
decreasing through 2002 to a rate of 5.0%. If the health care trend rate
assumptions were increased by one percent, the accumulated postretirement
benefit obligation would be increased by approximately $9.1 million. The
effect of this change on the sum of the service cost and interest cost would
be an increase of $1.1 million. The assumed discount rate for 1995 was 7.5%
and health care cost trend rates were 8.0% for medical costs and 11% for
prescription drugs in 1995, decreasing through 2002 to a rate of 5.0%.

NOTE 11. LEASES

    The Company's aggregate commitments under the Company's non-cancellable
operating leases for the years following 1996 are as follows: 1997
--$4,600,000; 1998--$3,900,000; 1999--$3,600,000; 2000-- $3,200,000; 2001
--$3,500,000 and all years thereafter--$26,600,000.

    Rental expense for 1996, 1995 and 1994 was $6.2 million, $6.0 million and
$5.3 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 receivable. 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, 1996, 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 allowance for funds used during
construction) of approximately $57.7 million will be incurred during 1997.
Construction expenditures, including cost of removal and salvage, amounted to
$60.9 million for 1996.

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 1996 are as follows: 1997-- $73,000,000; 1998--$73,400,000;
1999--$73,200,000; 2000--$71,800,000 and 2001--$54,900,000.

    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 collect from
its customers the remaining deferred amounts plus accrued interest. As of
December 31, 1996, the Company has deferred $2.1 million of these costs
remaining on the books of the Company.

    On April 8, 1992, the FERC issued Order 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 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. Since 1993, the Company
has assumed responsibility for 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 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 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,

                                         26


1996, the Company has paid $25.1 million of transition costs. The Company
currently estimates that its remaining obligation for FERC Order 636
transition costs will be approximately $11.6 million. This estimate was
determined from information provided in Order 636 FERC compliance filings by
the Company's pipeline suppliers and from subsequent transition 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, 1996 with an offsetting
charge to Deferred Transition Costs. In December 1994, the NYPSC issued an
order establishing the regulatory and rate-making policies applicable to New
York gas distribution utilities resulting from FERC Order 636. The order
provides the 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 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 1996 are as
follows: 1997--$30,800,000; 1998--$33,100,000; 1999--$33,900,000; 2000
--$28,600,000; 2001--$21,500,000.

POWER PURCHASE AGREEMENTS

    The Company has three long-term contracts for the purchase of electric
generating capacity and energy. The contracts expire in 1998, 2000 and 2015.

    The Company's aggregate contract obligations for the purchase of electric
capacity and energy for each of the five years following 1996 are as follows:
1997--$14,400,000; 1998--$11,500,000; 1999--$5,100,000; 2000--$5,400,000;
2001--$700,000.

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 filed a
counterclaim for benefits 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 concluded in October 1996. Post arbitration briefs were submitted in
November 1996 and the arbitrators heard closing arguments in December 1996.
The arbitration panel released a written decision on January 29, 1997. The
arbitrators found that the Company had "successfully proved that over the
years [Mr. Smith] dishonestly and deceptively reported certain expense
account items, listing on expense account documentation names of prominent
persons who were not present, or inventing fictitious business purpose
rationales for social encounters, or pretending to attend business
conventions as a ruse for obtaining company-paid vacations for his family."
The arbitrators charged Mr. Smith with costs and expenses totaling $2,786,643
for "maintaining the expense account fictions..." and "for some of the costs of
unraveling [Mr. Smith's] deceptions." That money was awarded to the Company.
However, the arbitrators also ruled that Mr. Smith's conduct did not result in
"material economic damage" to the Company. As a result, the panel awarded Mr.
Smith $8,309,855, which includes his legal and arbitration fees. The
offsetting costs between his award and what was awarded to the Company
resulted in a net award to Mr. Smith of $5,523,212. The Company is currently
considering its legal options. Any amounts not previously provided for will be
recorded in the first quarter of 1997. The Company does not expect the
additional provisions to have a significant impact on the overall results of
operations in 1997.

    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; and (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.
The Company cannot predict the outcome of this proceeding.

    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 an additional
refund of approximately $3.4 million to its New York electric and gas
customers. This amount was in addition to the $369,000 previously refunded by
the Company. 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 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 then current electric base rate case (Case 95-E-0491) and
ordered the consolidation of the two cases (Consolidated Case).

                                    27


    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 settlem ent
agreement, the Company agreed to (1) return approximately $6.5 million to its
electric customers; (2) forego 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. These amounts were charged
to operations in the second quarter of 1996. On May 3, 1996, the NYPSC issued
an order approving the settlement. 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 Company officers and
former employees, in December 1994, RECO submitted a proposal to the NJBPU to
refund an additional $704,000 to RECO's customers. This amount was in
addition to the $93,000 refunded to the Company's New Jersey customers
through its Levelized Energy Adjustment Clause (LEAC) in February and March
1994. 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 through LEAC. On February 21, 1996, the NJBPU approved
this refund making the total amount refunded to RECO's customers $1,279,000.
In the opinion of the Company, no significant additional refunds will be
required in connection with these proceedings.

OTHER LEGAL PROCEEDINGS

    The Company, the six other New York State investor-owned electric
utilities, and the Energy Association of New York State filed a petition in
New York State Supreme Court on September 18, 1996 challenging the NYPSC's
May 20, 1996 Order in the Competitive Opportunities Proceeding (Case
94-E-0952) under Article 78 of the New York Civil Practice Law and Rules. In
their Article 78 petition, the petitioners alleged that the Order is vague,
ambiguous and procedurally defective, that the May 20, 1996 Order fails to
assure the utilities a reasonable opportunity to recover strandable costs,
and the NYPSC lacks the authority to order retail wheeling or divestiture.

    On November 26, 1996, the Supreme Court issued a ruling denying the
Article 78 petition. In its ruling, the Court determined that because the
Commission has not yet directed retail wheeling, generation deregulation and
asset divestiture, there is no justiciable controversy regarding these
issues. Despite this finding, the Court proceeded to opine that the
Commission is not precluded by state or federal law from ordering retail
wheeling or generation divestiture. The Court also determined that the
utiliti es are not entitled, as a matter of law, to recover from customers
the full amount of the utilities' strandable costs. On December 24, 1996, the
Energy Association and the New York utilities appealed to the Appellate
Division of the Supreme Court for the Third Judicial Department from the
Supreme Court's November 26, 1996 decision. The Company is unable to predict
the final result of this litigation.

    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. Although it is presently unclear whether any hazardous
waste generated by the Company was transported to the Helen Kramer Landfill
site, a final report by an independent waste consultant firm indicates that
no such waste was delivered to the site. On October 2, 1996, the Company
entered into a DE MINIMIS settlement agreement with certain third-party
plaintiffs which, INTER ALIA, provides for (i) dismissal of the claims
asserted against the Company and a bar to future claims against the Company
related to the site, (ii) indemnification of the Company for any future
claims or expenses related to the site, each with certain standard limited
exceptions, and (iii) payment of $15,000 into a fund which will be used to
pay for clean-up costs related to the site.

    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 the 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 remedial investigation is proceeding. 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 New
York State Department of Environmental Conservation (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 Company has
completed this remedial investigation. In November 1996, the Company
submitted to the DEC a Feasibility Study Report which evaluates various
remedial actions to eliminate the contamination discovered at the West Nyack
site. After the DEC approves the Feasibility Study and solicits public
comment, the DEC shall select a final remedial alternative for 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 dated as of
January 8, 1996, which provides for preliminary site assessments of these six
MGP sites. In November 1996, the Company submitted to the DEC, for its review
and approval, a draft work plan for the preliminary site assessment of three
of the MGP sites.

    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 was completed and submitted
to the EPA for determination of what remedial measures will be required at
the Cottman Avenue site. The Metal Bank Group has assigned the Company with a
2.87% share although, to date,

                                       28


because the Company is not a member of the Group, the Company has been unable
to confirm this allocation. In addition, the Company received in November
1996 a letter from the EPA requesting information and documentation
concerning the Company's connection to the site. The EPA has issued a
recommended proposed remediation plan which, if approved, will cost
approximately $17 million. The Company is unable at this time to estimate the
Company's share, if any, of past or future costs at this site.

    On November 19, 1996, the Company was served with a Summons and Complaint
(Summons and Complaint) in a litigation entitled CROSSROADS COGENERATION
CORPORATION V. ORANGE AND ROCKLAND UTILITIES, INC., filed in the United
States District Court for the District of New Jersey. The litigation relates
to a power sales agreement between the Company and Crossroads Cogeneration
Corporation (Crossroads), which requires the Company to purchase electric
capacity and associated energy from a cogeneration facility in Mahwah, New
Jersey. The Complaint alleges damage claims for breach of contract, breach of
the implied covenant of good faith and fair dealing and violations of the
Federal Antitrust laws and seeks a declaration of Crossroads' rights under
the Agreement. In February 1997, the Company expects to file a motion to
dismiss the action. The Company will defend the action vigor ously. The
Company cannot predict the outcome of this proceeding.

    On January 17, 1997, the Company received a Third-Party Summons and
"Additional Third-Party Complaint" in a litigation pending in the United
States District Court for the Southern District of New York entitled TOWN OF
WALLKILL AND STATE OF NEW YORK V. TESA TAPE, INC., ET AL. The Additional
Third-Party Complaint purports to allege claims against the Company and other
third-party defendants for response costs under the Federal Comprehensive
Environmental Response, Compensation and Liability Act of 1980 (CERCLA), and
for contribution and/or indemnity under CERCLA, the New York Contribution
Among Tort-Feasors Act and common law principles of contribution and
indemnity. The Additional Third-Party Complaint alleges that the Company
transported wastes containing hazardous substances and/or generated, disposed
of, and/or arranged for disposal or transport of wastes containing hazardous
substances during the relevant time period (identified as 1965 through on or
about 1974 in a pleading attached to the Additional Third-Party Complaint) at
a landfill site located in the Town of Wallkill, Orange County, New York. On
January 21, 1997, the Company received an Amended Summons and Amended
Complaint of Plaintiff-Intervenor State of New York in the same action (State
Complaint). The State Complaint names the Company as a direct defendant, and
purports to allege claims under CERCLA and the common law of the State of New
York governing public nuisance, restitution, subrogation and implied
indemnities. The State Complaint alleges upon information and belief that the
Company disposed of and/or arranged for the disposal or transport for
disposal of hazardous substances at the Wallkill landfill site. The Company
has insufficient information at this time to predict the outcome of this
proceeding.

    On February 4, 1997, the Company's subsidiary, Rockland Electric Company
(RECO), was served with a Summons and Complaint in a litigation entitled
PHILIP GRIFFIN AND MARJORY GRIFFIN V. ROCKLAND ELECTRIC COMPANY filed in the
Superior Court of New Jersey, Bergen County, Law Division. The Complaint
alleges claims on behalf of owners of real property located in Old Tappan,
New Jersey related to RECO's operation of a substation in Old Tappan. The
Complaint alleges that a September 10, 1996 resolution (Resolution) of the
Board of Adjustment of the Borough of Old Tappan, New Jersey (Board of
Adjustment) orders RECO to abate a nuisance of excessive noise at the
substation, and that RECO has refused and failed to comply with the
Resolution. The Complaint includes nine counts, eight of which claim
compensatory damages of $2 million and exemplary damage of $4 million for
each count (the ninth count does not quantify the damages claimed). By
Petition dated October 11, 1996, RECO petitioned the State of New Jersey
Board of Public Utilities (NJBPU) for relief from the September 10, 1996
resolution, including a judgment finding the ordinance to be void. On or
about December 9, 1996, the Board of Adjustment filed an Answer to the
Petition asserting defenses. The Company intends to pursue the proceedings
before the NJBPU and to defend the court action vigorously. The Company
cannot predict the outcome of either proceeding.

    On July 19, 1996 NORSTAR Energy Limited Partnership (NORSTAR), an indirect
subsidiary of the Company, filed a Complaint in the United States District
Court for the Northern District of Georgia, Atlanta Division against
Petroleum Source and Systems Group, Inc. (PSI), seeking to recover
approximately $700,000 for natural gas delivered to PSI. On or about August
26, 1996, PSI filed an Answer denying its liability and asserting
counterclaims against NORSTAR. The counterclaims seek damages for breach of
contract including an unspecified amount for loss of profits and
approximately $8.0 million for liquidated damages and costs. The case is
currently in the discovery phase, and NORSTAR is vigorously pursuing its
claims and defending against PSI's counterclaims. The Company cannot predict
the outcome of this proceeding.

ENVIRONMENTAL

    The CERCLA and certain similar state statutes authorize various governme
ntal 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. As discussed above, the Company
is a party to a number of administrative and litigation 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. As noted above,
the Company does not believe that certain proceedings will have a material
effect on the Company, while as to others, the Company is unable at this time
to estimate what, if any, costs it will incur. 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, Nitrogen Oxide (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 fee is
based upon actual air emissions reported to the DEC for the preceding
calendar year. For 1996, the Company paid an emission rate of approximately
$27 per ton based upon 1995 emissions. 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.

                                       29

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
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>

YEAR ENDED DECEMBER 31,                                                       1996          1995          1994
------------------------------------------------------------------------  ------------  ------------  ------------
                                                                                   (THOUSANDS OF DOLLARS)
<S>                                                                       <C>           <C>           <C>
Operating Information:
 Operating revenues:
 Sales to unaffiliated customers:
  Electric..............................................................  $    477,032  $    459,876  $    478,909
  Gas...................................................................       176,400       140,177       157,045
 Intersegment sales:
  Electric..............................................................            10           107           120
  Gas...................................................................            42            47           123
                                                                          ------------  ------------  ------------
   Total Utility Operating Revenues.....................................       653,484       600,207       636,197
  Diversified activities................................................       271,566       429,625       380,470
                                                                          ------------  ------------  ------------
   Total Operating Revenues.............................................  $    925,050  $  1,029,832  $  1,016,667
                                                                          ------------  ------------  ------------
Operating income before income taxes:
 Electric...............................................................  $     86,161  $     85,156  $     80,355
 Gas....................................................................        22,447        17,467        19,724
 Diversified activities.................................................        (5,147)       (4,217)          557
                                                                          ------------  ------------  ------------
   Total Operating Income Before Income Taxes...........................       103,461        98,406       100,636
                                                                          ------------  ------------  ------------
Income Taxes:
 Electric...............................................................        21,585        22,406        19,894
 Gas....................................................................         4,879         3,859         4,644
 Diversified activities.................................................        (1,644)         (363)           91
                                                                          ------------  ------------  ------------
   Total Income Taxes...................................................        24,820        25,902        24,629
                                                                          ------------  ------------  ------------
   Total Income From Operations.........................................  $     78,641  $     72,504  $     76,007
                                                                          ------------  ------------  ------------
Other Information:
 Identifiable assets:
  Electric..............................................................  $    978,952  $    979,512  $    960,143
  Gas...................................................................       240,471       217,357       214,933
  Diversified activities................................................        71,553        80,073        95,846
                                                                          ------------  ------------  ------------
   Total Identifiable Assets............................................     1,290,976     1,276,942     1,270,922
 Corporate assets.......................................................        22,654        29,928        42,082
                                                                          ------------  ------------  ------------
   Total Assets.........................................................  $  1,313,630  $  1,306,870  $  1,313,004
                                                                          ------------  ------------  ------------
Depreciation expense:
 Electric...............................................................  $     29,430  $     30,594  $     29,161
 Gas....................................................................         2,578         6,646         5,940
 Diversified activities.................................................         1,605         1,307           582
                                                                          ------------  ------------  ------------
   Total Depreciation Expense...........................................  $     33,613  $     38,547  $     35,683
                                                                          ------------  ------------  ------------
Additions to plants:
 Electric...............................................................  $     41,932  $     43,225  $     44,832
 Gas....................................................................        16,766        10,894        15,242
 Diversified activities.................................................           659           911           468
                                                                          ------------  ------------  ------------
   Total Additions......................................................  $     59,357  $     55,030  $     60,542
                                                                          ------------  ------------  ------------
</TABLE>
<TABLE>
 
NOTE 14. SUMMARY OF QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)
<CAPTION>

                                                                                              EARNINGS     EARNINGS
                                                                                             APPLICABLE       PER
                                                                       INCOME                    TO         AVERAGE
                                                         OPERATING      FROM         NET       COMMON       COMMON
                                                          REVENUES   OPERATIONS    INCOME       STOCK        SHARE
                                                         ----------  -----------  ---------  -----------  -----------
                                                                            (THOUSANDS OF DOLLARS)
<S>                                                      <C>          <C>         <C>         <C>          <C>  
Quarter Ended
 1996
March 31...............................................  $  285,672   $  21,526   $  14,555   $  13,799    $    1.01
June 30................................................     212,364      16,609       6,320       5,563          .41
September 30...........................................     215,606      25,687      18,676      17,921         1.31
December 31............................................     211,408      14,819       6,752       5,996          .44
                                                         ----------  -----------  ---------  -----------       -----
 1995
March 31...............................................  $  311,807   $  20,549   $  15,321   $  14,537    $    1.06
June 30................................................     245,298      12,384       3,722       2,937          .22
September 30...........................................     231,867      23,957      14,792      14,008         1.03
December 31............................................     240,860      15,614       4,738       3,953          .29
                                                         ----------  -----------  ---------  -----------       -----
</TABLE>
 
    Quarterly results reflect the seasonal effect of electric and gas sales.

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 sheet of Orange and
Rockland Utilities, Inc. and Subsidiaries (a New York Corporation) as of
December 31, 1996 and 1995, and the related consolidated statements of income
and retained earnings and cash flows for each of the three years in the
period ended December 31, 1996. 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, 1996
and 1995, and the consolidated results of its operations and its cash flows
for the three years ended December 31, 1996, in conformity with generally
accepted accounting principles.

[SIG]

New York, New York
February 6, 1997

                                       30

<TABLE>
OPERATING STATISTICS
<CAPTION>

                                                                    YEAR ENDED DECEMBER 31,
                                                      1996        1995        1994        1993        1992
                                                   ----------  ----------  ----------  ----------  ----------
<S>                                                <C>         <C>         <C>         <C>         <C> 
Electric:
Sales (Mwh):
 Residential.....................................   1,731,105   1,685,110   1,660,755   1,611,602   1,532,915
 Commercial......................................   2,044,759   2,056,185   2,049,265   2,018,240   1,986,048
 Industrial......................................     748,484     680,678     657,142     627,944     594,912
 Public Street Lighting..........................      29,522      28,107      27,836      27,705      27,538
 Public Authorities..............................      51,392      75,506      68,972      72,037      70,257
                                                   ----------  ----------  ----------  ----------  ----------
  Total Sales to Customers.......................   4,605,262   4,525,586   4,463,970   4,357,528   4,211,670
 Other Utilities for Resale......................     190,394     118,730     265,311     234,751     253,290
                                                   ----------  ----------  ----------  ----------  ----------
  Total Sales of Electricity.....................   4,795,656   4,644,316   4,729,281   4,592,279   4,464,960
                                                   ----------  ----------  ----------  ----------  ----------
Revenues (000's):
 Residential.....................................  $  209,706  $  208,862  $  214,439  $  211,082  $  193,124
 Commercial......................................     200,281     204,240     212,214     212,240     202,523
 Industrial......................................      46,663      50,205      51,316      50,983      47,128
 Public Street Lighting..........................       4,903       4,930       4,939       4,967       4,880
 Public Authorities..............................       3,453       4,257       4,051       4,344       4,212
                                                   ----------  ----------  ----------  ----------  ----------
  Total Revenues from Sales to Customers.........     465,006     472,494     486,959     483,616     451,867
 Other Utilities for Resale......................       3,106       2,150       6,636       6,414       6,965
                                                   ----------  ----------  ----------  ----------  ----------
  Total Revenues from Sales of Electricity.......     468,112     474,644     493,595     490,030     458,832
 Other Electric Operating Revenues...............       8,930     (14,661)    (14,566)     (3,063)      4,901
                                                   ----------  ----------  ----------  ----------  ----------
  Total Electric Operating Revenues..............  $  477,042  $  459,983  $  479,029  $  486,967  $  463,733
                                                   ----------  ----------  ----------  ----------  ----------
</TABLE>
<TABLE>
<S>                                         <C>        <C>        <C>        <C>        <C>  
Gas:
Sales (Mmcf):
 Residential..............................     15,685     14,759     15,164     15,323     15,212
 Commercial and Industrial................      5,233      5,066      5,257      5,233      5,295
                                            ---------  ---------  ---------  ---------  ---------
  Total Firm Sales........................     20,918     19,825     20,421     20,556     20,507
 Interruptible............................      3,996      2,327      1,023        653        889
 Other Utilities for Resale...............          4          4         27          8        556
                                            ---------  ---------  ---------  ---------  ---------
  Total Sales of Gas......................     24,918     22,156     21,471     21,217     21,952
                                            ---------  ---------  ---------  ---------  ---------
Revenues (000's):
 Residential..............................  $ 116,981  $  96,737  $ 112,759  $ 113,116  $  97,646
 Commercial and Industrial................     36,954     31,226     36,676     36,707     32,541
                                            ---------  ---------  ---------  ---------  ---------
  Total Revenues from Firm Sales..........    153,935    127,963    149,435    149,823    130,187
 Interruptible............................     15,101      6,725      3,996      2,605      3,414
 Other Utilities for Resale...............         94         59        203        105      1,950
                                            ---------  ---------  ---------  ---------  ---------
  Total Revenues from Sales of Gas........    169,130    134,747    153,634    152,533    135,551
 Other Gas Revenues.......................      7,312      5,477      3,534      4,724      5,128
                                            ---------  ---------  ---------  ---------  ---------
  Total Gas Operating Revenues............  $ 176,442  $ 140,224  $ 157,168  $ 157,257  $ 140,679
                                            ---------  ---------  ---------  ---------  ---------
</TABLE>
 
                                       31

<TABLE>
FINANCIAL STATISTICS
<CAPTION>

                                                                                      YEAR ENDED DECEMBER 31,
                                                                         1996        1995        1994        1993        1992
                                                                       ---------   ---------   ---------   ---------   ---------
<S>                                                                 <C>         <C>         <C>        <C>          <C>     
Common Stock Data:                                                                                                   
 Earnings Per Average Common Share................................       $3.17       $2.60       $2.50       $3.06       $3.15
 Dividends Declared Per Share.....................................       $2.58       $2.57       $2.54       $2.49       $2.43
 Book Value Per Share (Year End)..................................      $28.41      $27.82      $27.79      $27.79      $27.22
 Market Price Range Per Share:
  High............................................................     $37 1/8     $37 3/8     $41 1/4     $47 1/2     $41 7/8
  Low.............................................................     $33 3/8     $30 7/8     $28 3/8     $38 5/8     $32 3/8
  Year End........................................................     $35 7/8     $35 3/4     $32 1/2     $40 5/8     $41 5/8
 Price Earnings Ratio.............................................       11.32       13.75       13.00       13.28       13.21
 Dividend Payout Ratio............................................       81.39%      98.85%     101.60%      81.37%      77.14%
 Common Shareholders at Year End..................................      21,322      22,916      23,299      24,328      25,696
 Average Number of Common Shares Outstanding (000's)..............      13,654      13,653      13,594      13,532      13,438
 Total Common Shares Outstanding at Year End (000's)..............      13,654      13,654      13,653      13,532      13,531
 Return on Average Common Equity..................................       11.33%       9.35%       9.01%      11.16%      11.88%
                                                                      ---------   ---------   ---------   ---------   ---------
Capitalization Data (000's):
 Common Stock Equity..............................................    $387,850    $379,776    $379,403    $376,044    $368,321
 Non-Redeemable Preferred Stock...................................      43,241      43,253      43,268      43,287      43,306
 Redeemable Preferred Stock.......................................           0       1,390       2,774       4,158       5,542
 Long-Term Debt (includes current portion)........................     359,968     360,137     379,561     382,248     382,339
                                                                      ---------   ---------   ---------   ---------   ---------
  Total Capitalization............................................    $791,059    $784,556    $805,006    $805,737    $799,508
                                                                      ---------   ---------   ---------   ---------   ---------
Capitalization Ratios:
 Common Equity....................................................       49.03%      48.41%      47.14%      46.67%      46.07%
 Non-Redeemable Preferred Stock...................................        5.47%       5.51%       5.37%       5.37%       5.42%
 Redeemable Preferred Stock.......................................        0.00%       0.18%       0.34%       0.52%       0.69%
 Long-Term Debt (includes current portion)........................       45.50%      45.90%      47.15%      47.44%      47.82%
                                                                      ---------   ---------   ---------   ---------   ---------
Selected Financial Data (000's   ):
 Operating Revenues...............................................    $925,050  $1,029,832  $1,016,667    $966,864    $839,695
 Operating Expenses...............................................    $846,409    $957,328    $940,660    $883,943    $759,691
 Operating Income.................................................     $78,641     $72,504     $76,007     $82,921     $80,004
 Net Income.......................................................     $46,303     $38,573     $37,217     $44,815     $45,812
 Earnings Applicable to Common Stock..............................     $43,279     $35,438     $33,966     $41,451     $42,334
 Net Utility Plant................................................    $899,643    $873,668    $856,289    $831,980    $814,686
 Total Assets.....................................................  $1,313,630  $1,306,870  $1,313,004  $1,280,973  $1,127,501
 Long-Term Debt Including
 Redeemable Preferred Stock.......................................    $359,968    $361,527    $382,335    $386,406    $387,881
 Ratio of Long-Term Debt to Net Plant.............................        40.0%       41.2%       44.4%       46.0%       47.0%
 Ratio of Accumulated Depreciation to Utility Plant in Service....        33.8%       33.3%       33.1%       31.7%       30.7%
 
                                       32
</TABLE>

               ORANGE AND ROCKLAND UTILITIES, INC.
                                
                    APPENDIX A TO EXHIBIT 13
                                
                   FORM 10-K DECEMBER 31, 1996



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)
        1992          4.21
        1993          4.36
        1994          4.46
        1995          4.53
        1996          4.61

2. Graph entitled "Cost per Kwh"

        Year        Cents
        1992          2.70
        1993          2.67
        1994          2.51
        1995          2.46
        1996          2.48

3. Graph entitled "Firm Gas Sales"

        Year    Mmcf (Thousands)
        1992         20.5
        1993         20.6
        1994         20.4
        1995         19.8
        1996         20.9

4. Graph entitled "Cost per Mcf"

        Year       Dollars
        1992          3.52
        1993          3.63
        1994          3.52
        1995          3.43
        1996          4.05