<PAGE>   1
Orange and Rockland Utilities, Inc. and Subsidiaries

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

MAJOR DEVELOPMENTS -- 1997

COMPETITION

   Regulatory agencies at the federal level as well as in 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 will become subject to competitive pressures in addition to
regulatory constraints. A discussion of current federal and state competitive
initiatives follows.

FEDERAL INITIATIVE

   On April 24, 1996, the Federal Energy Regulatory Commission (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's open access transmission tariff, as originally filed
with the FERC on July 9, 1996 and amended through August 1997, offers
transmission service and certain ancillary services to wholesale customers on a
basis that is 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, Order 888 is not
expected to materially impact the Company's financial condition or results of
operations.

   On January 31, 1997, the Company, in conjunction with the other members of
the New York Power Pool (NYPP), filed tariffs with the FERC seeking permission
to restructure the NYPP into an Independent System Operator (ISO). On December
19, 1997, the Company and the other members of the NYPP made a supplemental
filing with the FERC which provides for a revised ISO governance structure.
While the Company and the other members of the NYPP have requested that the FERC
act expeditiously on the filing, the Company is unable to predict either the
timetable for, or outcome of, this regulatory proceeding.

NEW YORK COMPETITIVE OPPORTUNITIES PROCEEDING

   On May 20, 1996, the New York Public Service Commission (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.

   On November 26 and December 31, 1997, the NYPSC issued orders approving an
Electric Rate and Restructuring Plan (the Restructuring Plan), which had been
filed on November 6, 1997 by the Company, the New York State Department of
Public Service (the Staff) and other parties in the Company's Competitive
Opportunities Proceeding (Case 96-E-0900). The Restructuring Plan provides for
the sale of all of the Company's generating assets (i.e., all units at the
Lovett Generating Station, the Company's one-third interest in the Bowline
Generating Station, as well as its hydroelectric facilities and gas turbines)
and for lower electric rates.

   Under the terms of the Restructuring Plan, which covers a four-year period
commencing with NYPSC approval, the Company has agreed to immediately commence
the process of auctioning all of its generating assets. The Restructuring Plan
provides that if the Company selects a winning bidder prior to May 1, 1999, the
New York share of any net book gains associated with the sale are to be
allocated between shareholders and customers on a 25%/75% basis, respectively,
and any net book losses are to be allocated between shareholders and customers
on a 5%/95% basis, respectively. If the Company selects a winning bidder on or
after May 1, 1999, the New York share of the net book gains or losses associated
with the sale are to be allocated between shareholders and customers on a
20%/80% basis. The Restructuring Plan further provides for a $20 million cap on
the New York share of net book gains allocable to shareholders from the sale of
generating assets. The NYPSC, in approving the Restructuring Plan, offered


10
<PAGE>   2
Orange and Rockland Utilities, Inc. and Subsidiaries

the Company the opportunity to participate as a bidder in the auction of the
Company's generating assets, subject to the conditions that the auction be
conducted by an independent third party and that the Company renounce the
shareholders' share of any net book gain or net book loss from the sale provided
for in the Restructuring Plan. By letter dated December 10, 1997, the Company
notified the NYPSC that it had elected not to be a bidder in the auction.
Accordingly, the Company will be subject to the terms of the Restructuring Plan
as filed on November 6, 1997. On December 11, 1997, in accordance with the
Restructuring Plan, the Company submitted its Preliminary Divestiture Plan to
the NYPSC Staff and filed its Final Divestiture Plan on February 4, 1998.

   The terms of the Restructuring Plan permit the Company to defer and recover
up to $7.5 million (New York electric share) of prudent and verifiable
non-officer employee costs associated with the divestiture, such as retraining,
outplacement, severance, early retirement and employee retention programs. Under
the terms of the Restructuring Plan, the Company will be authorized to petition
the NYPSC for recovery of employee costs in excess of $7.5 million. In addition,
the Restructuring Plan provides for the recovery of all costs of the sale.

   In addition, the terms of the Restructuring Plan permit the Company to retain
all earnings up to an 11.4% return on equity and provide that earnings in excess
of 11.4% are to be shared, with 75% to be used to offset NYPSC approved
deferrals or otherwise inure to the Company's customers, and 25% to be retained
by the Company's shareholders. The Company's existing PowerPick(TM) Program,
whereby customers can purchase energy (but not capacity) from suppliers other
than the Company, will be expanded to all customers on May 1, 1998. The
Restructuring Plan further provides that full retail access to a competitive
energy and capacity market will be available for all customers by May 1, 1999.

   The Restructuring Plan also provides for electric price reductions of
approximately $32.4 million over its four-year term and for recovery, through a
Competitive Transition Charge (CTC), of above-market generation costs should the
transfer of title to the Company's generating assets not occur before May 1,
1999. Should a CTC be required, the Company would be authorized to recover the
difference between its non-variable costs of generation, including 75% of fixed
production labor expenses and property taxes, and the revenues, net of fuel and
variable operating and maintenance expenses, derived from the operation of the
Company's generating assets in a deregulated competitive market. If title to the
generating assets has not transferred as of May 1, 2000, the CTC would be
modified so as to allow a maximum recovery of 65% of fixed production labor
expenses and property taxes. The modified CTC would remain effective until the
earlier of the date title to the generating assets is transferred or October 31,
2000. In the event title to the generating assets is not to be transferred by
October 31, 2000, the Company would be authorized to petition the NYPSC for
permission to continue a CTC until the date title to the generating assets is
transferred. The CTC does not allow for the recovery of inflationary increases
in non-fuel operating and maintenance production costs, property tax increases,
wage rate increases, or increased costs associated with capital additions or
changes in the costs of capital applicable to production costs.

   The Restructuring Plan also provides that the Company and its utility
subsidiaries may apply to the appropriate regulatory authorities for permission
to form a new holding company, which would be a registered holding company under
the Public Utility Holding Company Act of 1935 (the 1935 Act). The Company
currently is an exempt holding company under the 1935 Act. The new holding
company structure would provide for separate regulated electric distribution
companies in the New York, New Jersey and Pennsylvania service territories, as
well as an unregulated energy services company. The unregulated energy services
company would be able to market electricity and unbundled energy services (e.g.,
metering) to wholesale and retail customers on a competitive basis, using the
Company's name without a royalty payment.

   The formation of the holding company is conditioned upon shareholder and
regulatory approval, including approval of the Securities and Exchange
Commission, the FERC, the NYPSC, the New Jersey Board of Public Utilities
(NJBPU) and the Pennsylvania Public Utility Commission (PPUC). The Company will
consider a filing for the formation of a holding company after the divestiture
process is complete.

   The Restructuring Plan indicates that reciprocity would be required in order
to implement retail access. That is, if utility generators are allowed access to
the Company's retail customers, the Company shall be permitted equal access to
the customers of those utilities within New York State, if we so choose.

   In accordance with the settlement, the Company is required to submit an
Unbundled Rates Filing to the NYPSC. This filing, which will be made no later
than February 13, 1998, separates the components of existing tariffs into
production, transmission, distribution and customer cost categories.

   Additional information on the provisions of the Restructuring Plan is
contained below under "Rate Activities -- New York Electric" and "Electric Sales
and Revenues."

NEW JERSEY -- ENERGY MASTER PLAN

   On April 30, 1997, the NJBPU issued an order "Adopting and Releasing Final
Report in its Energy Master Plan Phase II Proceeding to Investigate the Future
Structure of the Electric Power Industry (Docket No. EX 94120585Y)." The Order
required Rockland Electric Company (RECO), a wholly owned utility subsidiary of
the Company, and other New Jersey investor owned electric utilities each to file
unbundled rates, a stranded cost proposal and a restructuring plan by July 15,
1997. As part of its stranded cost proposal, the NJBPU has recommended that each
utility provide a 5-10% rate reduction.

   RECO's filing was made on July 15, 1997. The filing includes a Restructuring
Plan, a Stranded Costs Filing and an Unbundled Rates Filing.

   On December 8, 1997, RECO submitted an Amended and Restated Restructuring
Plan and Stranded Costs Filing with the NJBPU to reflect the fact that the
Company has committed to divest all its generating assets by auction.

   The Restructuring Plan calls for RECO to remain a regulated transmission and
distribution company within a holding company structure. Standards of Conduct
and Affiliate Rules have been proposed in order to promote effective competition
and ensure that regulated operations do not subsidize unregulated operations.
RECO has proposed to implement full retail competition (energy and capacity) for
all customers by May 1, 1999, the same date approved for retail access in New
York. Under this schedule, full retail access will be achieved 13 months ahead
of the NJBPU's proposed phase-in schedule.

   In its Stranded Costs Filing, RECO has identified two categories of potential
stranded costs: generation investment and power purchase contracts with
non-utility generators (NUGS). Divestiture of the Company's generating assets
will determine their market value and the related stranded costs, if any. RECO
proposes to recover its share of stranded generation investment, if any, through
regulated delivery rates by means of a Market Transition Charge (MTC). The MTC
would be in effect over a period of up to eight years, commencing May 1, 1999.
Stranded NUG contract payments are proposed to be recovered over the remaining
life of the contracts through a non-bypassable wires charge also assessed by the
regulated delivery company. RECO has proposed to reduce its annual net revenue
(revenue net of fuel, purchased power and applicable taxes) by $4.3 million, or
5.1%, effective in October 1998.

   RECO also made an Unbundled Rates Filing which separates the components of
existing tariffs into production, transmission, distribution and customer cost
categories. The Unbundled Rates Filing, which was updated on January 30, 1998,
would serve as the basis to segregate the costs of the generation function from
rates in order to facilitate customer choice. In addition, the MTC mechanism
would be added to the existing rate structure to allow for recovery of stranded
costs, and a non-bypassable societal benefits charge would be created as a
billing mechanism for mandated public policy programs.

   Hearings with respect to RECO's filings are scheduled for the spring of 1998
and the NJBPU has indicated that it will rule on these filings by October 1998.
RECO's 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 or its effect, if any, on the Company's consolidated financial
position or results of operations.


                                                                              11
<PAGE>   3
Orange and Rockland Utilities, Inc. and Subsidiaries

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 Commonwealth
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 in the transmission and distribution systems. The transition plan of
the Act calls for a three-year phase-in of retail access beginning January 1,
1999, 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 above current levels during the
transition period. In addition, the Act permits the refinancing of certain
approved transition costs through the issuance of bonds secured by revenue
streams guaranteed by the PPUC. The savings associated with this financing
mechanism will be used to reduce strandable costs.

   On September 30, 1997, in accordance with the requirements of the Act, Pike
County Light & Power Company (Pike), a wholly owned utility subsidiary of the
Company, submitted its electric restructuring filing to the PPUC. On December
15, 1997, Pike submitted an amended and restated electric restructuring filing
with the PPUC to reflect the fact that the Company has committed to divest all
of its generating assets by auction. In this amended and restated filing, Pike
proposed that full retail competition be implemented for all customers by May 1,
1999. With the implementation of retail competition, Pike proposes to continue
to serve as the "provider of last resort" for those consumers who do not choose
an alternate provider, or whose alternate provider defaults. Pike proposed to
remain a regulated transmission and distribution company within a holding
company structure.

   On September 30, 1997, Pike also submitted proposed unbundled rates which
separate the components of existing tariffs into production, transmission,
distribution and customer cost categories. This filing was updated on January
30, 1998.

   It is expected that the PPUC will rule on Pike's restructuring filing by July
1998. Pike's filing may be accepted or significantly modified by the PPUC before
becoming effective. It is not possible to predict the outcome of the PPUC
proceeding; however, it is not expected that this proceeding will have a
material effect on the Company's consolidated financial position or results of
operations.

RATE ACTIVITIES

NEW YORK -- GAS

   In 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 ability to purchase gas supplies from a variety of sources,
other than the franchised local distribution utility. 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 a three-year period.

   On June 5, 1997, the NYPSC issued an Order Requiring the Filing of Proposals
to Ameliorate Gas Price Volatility and Requesting Comments in Case 97-G-0600, In
the Matter of the Commission's Request for Gas Distribution Companies to Reduce
Gas Cost Volatility and Provide for Alternative Gas Purchasing Mechanisms. Under
the Order, gas utilities in New York were required to submit proposals for
fixed-price gas sales options to be available for use by all customers
during the 1997-1998 heating season.

   The Company's proposal, as approved by the NYPSC in October 1997 provides a
fixed-price commodity cost option to firm sales customers for the 1997-1998
heating season. The option is limited to ten percent of customers in each
eligible customer class. The NYPSC order provided that costs associated with any
variations between gas utilized by customers electing the fixed-price option and
volumes locked in by the Company, to the extent prudently incurred, will be
recoverable. To date, approximately 2,500 customers are participating in this
program.

   On September 4, 1997, the NYPSC issued a Notice Inviting Comments on Staff's
Report in Case 97-G-1380, In the Matter of Issues Associated with the Future of
the Natural Gas Industry and the Role of Local Gas Distribution Companies
(LDCs). The Company is one such LDC.

   The primary conclusion of the Staff's Position Paper, "The Future of the
Natural Gas Industry," is that over the next five years, LDCs in New York should
transition out of the business of selling gas in order to encourage competition
and provide gas customers with choice in the marketplace. In addition, the Paper
identifies, discusses and requests comments on the following three impediments
to LDCs terminating their gas merchant role: (1) upstream pipeline capacity held
by LDCs; (2) the LDCs' supplier of last resort and obligation to serve
responsibilities; and (3) system reliability and operational integrity issues.

   The Company filed initial comments and reply comments on the Position Paper
in November and December 1997, respectively. The Company opposed Staff's
proposal to require LDCs to auction upstream capacity since it would endanger
the Company's ability to maintain system reliability. The Company advocated that
LDCs be allowed to establish meaningful penalty provisions to prevent diversions
of gas to other markets during the winter months. Finally, all stranded costs
related to upstream pipeline capacity and long-term gas services must be fully
recoverable by LDCs. It is not possible to predict the outcome of this
proceeding or its effect on the Company's consolidated financial position or
results of operations.

NEW YORK -- ELECTRIC

   On April 19, 1995, the NYPSC approved the Company's compliance filing
regarding the operation of the Revenue Decoupling Mechanism (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.

   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 NYPSC.

   On May 3, 1996, the NYPSC approved, subject to modifications required by the
NYPSC decision in the New York Competitive Opportunities Proceeding (as
previously discussed), 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 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 PowerPick(TM) -- an innovative retail access program that
allows participating customers to choose their electric energy supplier. The
PowerPick program was expanded as part of the Restructuring Plan.

   On December 1, 1997, as part of the approved Restructuring Plan, the Company
implemented the first year of the electric rate reduction in the amount of $5.9
million. Additional rate reductions of $8.8 million in each of the next three
years will be implemented as part of this agreement.

   Additional information on New York electric rate activities is contained
in the previous discussion of the New York Competitive Opportunities Proceeding.


12
<PAGE>   4
Orange and Rockland Utilities, Inc. and Subsidiaries

NEW JERSEY

   The NJBPU on January 8, 1997 approved a stipulation among New Jersey
utilities, NJBPU Staff and NJ Division of Ratepayer Advocate which provides a
recovery plan for costs associated with the change in accounting required by
Statement of Financial Accounting Standards No. 106, "Employer Accounting for
Postretirement Benefits Other Than Pensions." The approved plan provides several
alternative recovery mechanisms. RECO received approval from the NJBPU on
December 17, 1997 to begin amortizing these costs effective January 1, 1998.

   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
financial data for 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 alleged lower cost energy is available from other sources. The NJBPU
indicated at its public meeting held on July 30, 1997 that this petition would
be held in abeyance pending the outcome of RECO's Restructuring Plan. RECO
believes that this petition is without merit and intends to contest it
vigorously.

DISCONTINUED OPERATIONS

   In August 1997, Norstar Management, Inc. (NMI), a wholly owned indirect
subsidiary of the Company, sold certain of the assets of NORSTAR Energy Limited
Partnership (NORSTAR), a natural gas services and marketing company of which NMI
is the general partner. The assets sold consist primarily of customer contracts
and accounts receivable. NMI is expected to wind up the remaining portion of
NORSTAR's business in the first quarter of 1998. The Company believes all
liabilities, related to NORSTAR, have been fully provided for in 1997 and that
the Company's future results of operations are not expected to be affected
thereby. In accordance with Accounting Principles Board Opinion No. 30, the
financial results for this segment are reported as "Discontinued Operations."
The total (losses)/gains related to discontinued operations were $(15,432,000),
or $(1.13) per share, for 1997, $(1,844,000), or $(0.13) per share, for 1996,
and $807,000, or $0.06 per share, for 1995.

FINANCIAL PERFORMANCE

   Earnings per share from continuing operations were $3.09 for 1997, compared
to $3.30 in 1996 and $2.54 in 1995. The decrease in continuing operations
earnings between 1997 and 1996 was primarily the result of decreased electric
and gas net revenues, increased investigation and litigation costs and increased
interest charges offset by the Company's continued success in controlling
operating and maintenance expenses. The increase between 1996 and 1995 was the
result of higher electric and gas sales, lower customer refunds and decreased
investigation and litigation costs. Consolidated earnings per share were $1.96,
$3.17 and $2.60 for the years 1997, 1996 and 1995, respectively.

   Earnings per average common share are summarized as follows:

<TABLE>
<CAPTION>
                                                        1997               1996          1995
----------------------------------------------------------------------------------------------
<S>                                                    <C>                 <C>           <C>
Utility operations                                     $3.25               $3.39         $3.20
Events affecting the Company:
   Investigation & litigation costs                    (0.13)              (0.09)        (0.35)
   Refunds of misappropriated funds                       --                  --         (0.14)
Diversified activities                                 (0.03)                 --         (0.17)
----------------------------------------------------------------------------------------------
Earnings per share from continuing operations           3.09                3.30          2.54
Earnings per share from discontinued operations        (1.13)              (0.13)         0.06
----------------------------------------------------------------------------------------------
Consolidated earnings per share                        $1.96               $3.17         $2.60
----------------------------------------------------------------------------------------------
</TABLE>

   The earned return on common equity was 7.1% in 1997, compared to 11.3% in
1996 and 9.4% in 1995. After removing the effect of discontinued operations, the
earned return on common equity was 11.2%, 12.2% and 9.2% in 1997, 1996 and 1995,
respectively. Book value per share at year-end 1997 was $27.69, compared to
$28.41 in 1996 and $27.82 in 1995.

   The dividends paid on common stock were $2.58 in 1997 and 1996, and $2.57 per
share in 1995. The Company has maintained a strong capital structure: 46%
long-term debt, 6% preferred stock and 48% common equity.

RESULTS OF OPERATIONS

   The discussion which follows identifies the principal causes of the
significant changes in the amounts of revenues and expenses affecting income
available for common stock by comparing 1997 to 1996 and 1996 to 1995. This
discussion should be read in conjunction with the Notes to Consolidated
Financial Statements and other financial and statistical information contained
elsewhere in this report.

   The following is a summary of the changes in earnings available for common
stock:

<TABLE>
<CAPTION>
Increase (Decrease) From Prior Year                   1997          1996
--------------------------------------------------------------------------------
                                                     (Millions of Dollars)
<S>                                                  <C>           <C>
Utility operations:
   Operating revenues                                $(5.6)        $53.3
   Energy and gas costs                                3.8          35.0
--------------------------------------------------------------------------------
     Net revenues from utility operations             (9.4)         18.3
Other utility operating expenses and taxes            (5.7)         12.5
--------------------------------------------------------------------------------
     Operating income from utility operations         (3.7)          5.8
Diversified revenues                                  (0.5)         (0.7)
Diversified operating expenses and taxes               1.5          (2.0)
--------------------------------------------------------------------------------
Income from operations                                (5.7)          7.1
Other income and deductions                            3.2           2.0
Interest charges                                       0.7          (1.3)
--------------------------------------------------------------------------------
Income from continuing operations                     (3.2)         10.4
Discontinued operations                              (13.6)         (2.7)
--------------------------------------------------------------------------------
Net income                                           (16.8)          7.7
Preferred dividends                                   (0.2)         (0.1)
--------------------------------------------------------------------------------
Earnings applicable to common stock                 $(16.6)        $ 7.8
--------------------------------------------------------------------------------
</TABLE>

ELECTRIC OPERATING RESULTS

   Electric operating revenues, net of fuel and purchased power costs, decreased
by 1.0%, or $3.7 million, in 1997 after increasing by 3.6%, or $12.1 million, in
1996.

   These changes are attributable to the following factors:

<TABLE>
<CAPTION>
Increase (Decrease) From Prior Year    1997        1996
----------------------------------------------------------
                                     (Millions of Dollars)
<S>                                  <C>          <C>
Retail sales:
   Price changes                     $(5.7)       $(13.5)
   Sales volume changes                6.5           6.0
----------------------------------------------------------
      Subtotal                         0.8          (7.5)
Sales for resale                       4.0           1.0
Other operating revenues              (2.4)         23.6
----------------------------------------------------------
      Total electric revenues          2.4          17.1
Electric energy costs                  6.1           5.0
----------------------------------------------------------
      Net electric revenues          $(3.7)       $ 12.1
----------------------------------------------------------
</TABLE>

ELECTRIC SALES AND REVENUES

   Total sales of electric energy to retail customers during 1997 were 4,691,900
Mwh (megawatt hours), compared with 4,605,300 Mwh during 1996 and 4,525,600 Mwh
in 1995. Revenues associated with these sales were $465.8 million, $465.0
million and $472.5 million in 1997, 1996 and 1995, respectively. Electric sales
to customers for the last five years are shown in the accompanying chart.

ELECTRIC SALES TO CUSTOMERS
Mwh (Millions)

<TABLE>
<CAPTION>
               '93            '94       '95       '96       '97
----------------------------------------------------------------
<S>            <C>            <C>       <C>       <C>       <C>
 5.0                                    4.53      4.61      4.69
----------------------------------------------------------------
 4.5           4.36           4.46                
----------------------------------------------------------------
 4.0                                    
----------------------------------------------------------------
 3.5                          
----------------------------------------------------------------
 3.0           
----------------------------------------------------------------
</TABLE>

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

<TABLE>
<CAPTION>
                                         1997                1996
--------------------------------------------------------------------
<S>                                      <C>                 <C>
Residential                               3.5%                2.7%
Commercial                               (4.2)%              (0.5)%
Industrial                               12.2%                10.0%
Public street lighting                   (8.9)%                5.0%
Sales to public authorities              43.3%               (31.9)%
--------------------------------------------------------------------
</TABLE>

   Despite mild weather conditions in 1997 and 1996 when compared to 1995,
customer usage increased as a result of an increase in the average Kwh used per
customer and an increase in the average number of customers. Electric sales
increased 1.9%, 1.7% and 1.4% in 1997, 1996 and 1995, respectively.

   Under the Restructuring Plan, the Company will remain a regulated
transmission and distribution company that will deliver electricity to its
customers and maintain reliable service. The Company will remain the "provider
of last resort" for those of its customers who do not purchase electricity from
other sources.


                                                                              13
<PAGE>   5
Orange and Rockland Utilities, Inc. and Subsidiaries

   The plan also calls for lower electric rates for all customers, with
potential savings as high as 12 percent for the Company's largest industrial
customers, and approximately five percent for all others. Customers will be able
to select their energy provider no later than May 1998, and will have full
retail choice (energy and capacity) by May 1999.

   The Company will continue to introduce programs which are designed to reduce
peak load and encourage efficient energy usage. 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.

   Sales for resale increased by $4.0 million to $7.1 million in 1997 when
compared to 1996, after increasing $1.0 million in 1996. 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
4.7%, or $6.1 million, in 1997, after increasing 4.0%, or $5.0 million, in 1996.
The components of these changes in electric energy costs are as follows:

<TABLE>
<CAPTION>
Increase (Decrease) From Prior Year                  1997            1996
--------------------------------------------------------------------------------
                                                     (Millions of Dollars)
<S>                                                  <C>             <C>
Prices paid for fuel and purchased power             $--             $1.1
Changes in Kwh generated or purchased                6.3              2.3
Deferred fuel charges                               (0.2)             1.6
--------------------------------------------------------------------------------
   Total                                            $6.1             $5.0
--------------------------------------------------------------------------------
</TABLE>

   The increase in electric energy costs in 1997 when compared to 1996 is the
result of increased sales. The increase in electric energy costs in 1996 when
compared to 1995 is the result of increases in the cost of fuel as well as in
sales.

   The price paid for fuel and purchased power per kilowatt hour over the last
five years is shown in the following chart: 

COST PER KWH
Cents

<TABLE>
<CAPTION>
               '93       '94       '95       '96       '97
------------------------------------------------------------
<S>             <C>       <C>       <C>       <C>       <C>
3.00           2.67
------------------------------------------------------------
2.50                     2.51
------------------------------------------------------------
2.00                               2.48      2.48      2.46
------------------------------------------------------------
1.50                                         
------------------------------------------------------------
1.00                                                   
------------------------------------------------------------
</TABLE>

    The Company maintains an aggressive program of managing its sources of fuel
and energy purchases to provide its customers with the lowest cost of energy
available at any given time. Energy is purchased whenever available at a price
lower than the cost of production at the Company's generating plants. The
Company continues to use the least costly fuel available for generating
electricity.

   As mentioned previously, the Company's Restructuring Plan calls for the sale
of all of its generating assets. Once the sale is completed, electric energy
costs will consist of purchased power costs necessary to meet the needs of
customers under the "provider of last resort" clause contained in the
Restructuring Plan.

GAS OPERATING RESULTS

   Gas operating revenues, net of gas purchased for resale, decreased by 7.6%,
or $5.7 million, in 1997 when compared to 1996, after increasing by 9.0%, or
$6.2 million, in 1996.

   These changes are attributable to the following factors:

<TABLE>
<CAPTION>
Increase (Decrease) From Prior Year          1997             1996
------------------------------------------------------------------
                                             (Millions of Dollars)
<S>                                         <C>              <C>
Sales to firm customers:
   Price changes                            $(2.0)           $22.6
   Sales volume changes                      (1.8)             3.4
------------------------------------------------------------------
      Subtotal                               (3.8)            26.0
Sales to interruptible customers             (1.2)             8.4
Sales for resale                               --               --
Other operating revenues                     (3.0)             1.8
------------------------------------------------------------------
      Total gas revenues                     (8.0)            36.2
Gas energy costs                             (2.3)            30.0
------------------------------------------------------------------
      Net gas revenues                      $(5.7)           $ 6.2
------------------------------------------------------------------
</TABLE>

GAS SALES AND REVENUES

   Firm gas sales amounted to 20,321 million cubic feet (Mmcf) in 1997, a
decrease of 2.9% from the 20,918 Mmcf recorded in 1996. The increase in sales in
1996 was 5.5% from the 1995 level of 19,825 Mmcf. Gas revenues from firm
customers were $150.1 million, $153.9 million and $128.0 million in 1997, 1996
and 1995, respectively.

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

FIRM GAS SALES
Mmcf (Thousands)

<TABLE>
<CAPTION>
               '93            '94            '95            '96            '97
--------------------------------------------------------------------------------
<S>            <C>            <C>            <C>            <C>            <C>
25
--------------------------------------------------------------------------------
20             20.6           20.4           19.8           20.9           20.3
--------------------------------------------------------------------------------
15
--------------------------------------------------------------------------------
10
--------------------------------------------------------------------------------
</TABLE>

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

<TABLE>
<CAPTION>
                                                       1997      1996
---------------------------------------------------------------------
<S>                                                   <C>        <C>
Residential                                           (4.4)%     6.3%
Commercial and industrial                              1.7 %     3.3%
---------------------------------------------------------------------
</TABLE>

   The decrease in 1997 and 1996 was primarily the result of milder weather
conditions offset somewhat by increases in the average number of customers.

   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 an impact on gas operating
results.

   The FERC's Order 636 required pipeline supply companies to separate or
unbundle their charges for providing natural gas to the LDCs. 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
capacity. As approved, the tariffs granted the Company permission to retain 15%
of all revenues derived from the sale of the 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 the FERC's Order
63 off-system transactions. Revenues retained from Order 636 and Order 63
transactions in 1997 amounted to $0.3 million.

   Revenues from interruptible gas customers (customers with alternative fuel
sources) decreased by 7.9% in 1997 after increasing by 124.5% in 1996 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 decreased by 2.3%, or $2.3 million, in 1997 after an
increase of 42.0%, or $30.0 million, in 1996.

   The changes in utility gas energy costs for the years 1997 and 1996 are
a result of the following:

<TABLE>
<CAPTION>
Increase (Decrease) From Prior Year             1997             1996
----------------------------------------------------------------------
                                                 (Millions of Dollars)

<S>                                           <C>              <C>
Prices paid to gas suppliers*                 $  0.5           $  15.7
Firm and interruptible Mcf sendout              (5.8)              9.1
Deferred fuel charges                            3.0               5.2
----------------------------------------------------------------------
   Total                                      $ (2.3)          $  30.0
----------------------------------------------------------------------
</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 following chart:

COST PER MCF
Dollars

<TABLE>
<CAPTION>
               '93       '94       '95       '96       '97
------------------------------------------------------------
<S>            <C>       <C>       <C>       <C>       <C>
5                                            4.05      4.07
------------------------------------------------------------
4              3.63      3.52      3.43                              
------------------------------------------------------------
3                                  
------------------------------------------------------------
2                        
------------------------------------------------------------
1              
------------------------------------------------------------
</TABLE>

   As a result of the FERC's restructuring the gas transportation industry, to
promote competition among gas suppliers and to ensure supply at the lowest
reasonable costs, Order 636 authorizes pipelines to recover certain transition
costs from their customers. The Company


14
<PAGE>   6
Orange and Rockland Utilities, Inc. and Subsidiaries

currently estimates that its obligations for Order 636 transition costs will
total approximately $28.6 million. Approximately $27.3 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 in the process of recovering these
costs from its customers and believes that it will be allowed to recover all
such costs by the end of the year 2000.

    As previously mentioned in the New York Gas Rate Activities section, the
Company submitted and received approval for a fixed-price gas option that will
lock in the price that participating customers will pay for the commodity cost
of gas used during the 1997-1998 heating season (December 1-April 30) regardless
of changes in the market price of gas. Approximately 2,500 customers are
participating. The Company has contracted to acquire such gas. To the extent
actual volumes differ from the contracted volumes, the Company will refund to or
collect such differences from customers through the Gas Adjustment Clause.

   The NYPSC, in its effort to promote competition, has required the Company to
provide firm transportation service for those customers who elect to purchase
their gas supply from a marketer rather than the Company. Marketers are
permitted to aggregate customers and the Company is required to release
interstate pipeline capacity and storage to the marketers to serve these
customers until 1999. After 1999, marketers are not obligated to use capacity
released by the Company to serve these customers and may use whatever capacity
is available in the marketplace. As the transition to a competitive retail
market develops, the Company will determine what supply capacity and storage
contracts it maintains. As the Company moves to a competitive market,
traditional cost recovery mechanisms may be replaced by market-based methods.

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       1997              1996
-----------------------------------------------------------------
                                           (Millions of Dollars)
<S>                                      <C>               <C>
Other operating expenses                 $(5.8)            $17.1
Maintenance                               (1.4)             (4.6)
Depreciation and amortization              3.7              (5.2)
Taxes                                     (2.2)              5.2
-----------------------------------------------------------------
   Total                                 $(5.7)            $12.5
-----------------------------------------------------------------
</TABLE>

   The primary reason for the change in utility operating expense for 1997 and
1996 is the amortization of Independent Power Producer costs of $9.8 million in
1997 compared to the $16.2 million amortized in 1996 and the costs of Demand
Side Management programs, which were $5.2 million, $4.7 million and $8.6 million
in 1997, 1996 and 1995, respectively. These costs are recovered in revenues on a
current basis. The remaining increase in 1996 was the result of increased
transmission and distribution activities when compared to 1995.

   Maintenance costs decreased 3.7% in 1997 after decreasing by 11.1% in 1996.
The decrease in 1997 is primarily the result of lower scheduled plant
maintenance costs when compared to 1996. In 1996, the decrease is primarily the
result of improvements to the Company's distribution system during the year.

   Depreciation and amortization expenses increased by $3.7 million in 1997 as a
result of plant additions, after decreasing by $5.2 million in 1996 as a result
of the 1996 New York rate decision.

   Taxes other than income taxes decreased $0.1 million in 1997, after
increasing by $5.0 million in 1996. The 1996 increase was also a result of the
1996 New York rate decision. Federal income tax decreased by $2.1 million in
1997, after increasing $0.2 million in 1996. 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 energy
services and land development businesses conducted by its wholly owned
non-utility subsidiaries.

   Revenues from diversified activities, excluding the discontinued gas
marketing operations, decreased by $0.5 million in 1997, after decreasing by
$0.7 million in 1996.

   Operating expenses incurred by the non-utility subsidiaries, increased by
$1.5 million in 1997 after decreasing by $2.0 million in 1996.

   Earnings from diversified activities decreased by $0.6 million in 1997 after
increasing by $2.4 million in 1996. 

     The reduction in 1997 earnings is primarily related to the start-up costs 
for Palisades Energy Services, Inc., an indirect subsidiary of the Company.

   As mentioned previously, the Company has discontinued its gas marketing
operations. Diversified operations in the future will focus on promoting energy
services related operations.

OTHER INCOME AND DEDUCTIONS AND INTEREST CHARGES

   Other income and deductions increased by $3.2 million in 1997 after
increasing by $2.0 million in 1996. The increase in 1997 was the result of the
1996 New York rate decision offset by increased investigation charges. The
increase in 1996 was enhanced by decreased investigation charges offset by the
results of the 1996 New York rate decision.

   Interest charges increased $0.7 million in 1997 when compared to 1996, after
decreasing $1.3 million in 1996. The 1997 increase is the result of increased
short-term debt. The 1996 decrease is 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 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 1995-1997 were
as follows:

<TABLE>
<CAPTION>
                                                                1997             1996             1995
-------------------------------------------------------------------------------------------------------
                                                                          (Millions of Dollars)

<S>                                                             <C>              <C>              <C>
Construction expenditures                                       $73.1            $60.9            $56.8
Retirement of long-term debt & preferred stock - net              4.6              1.6             20.8
-------------------------------------------------------------------------------------------------------
   Total                                                        $77.7            $62.5            $77.6
-------------------------------------------------------------------------------------------------------
</TABLE>

   At December 31, 1997, the Company estimated the cost of its construction
program in 1998 to be $51.0 million. It is expected that the Company's capital
requirements for 1998 will be met primarily with funds from operations,
supplemented by short-term borrowings.

   The financing activities of the Company and its utility subsidiaries during
1997 consisted of the redemption of one series of preferred stock, a
refinancing, refunding of certain debt maturities and the repurchase of common
stock.

   With regard to the preferred stock redemption, on January 6, 1997, the
Company redeemed the remaining 13,896 shares of its Redeemable Preferred Stock,
Series I, 8 1/8% then outstanding at $100 per share. The stock was subject to
mandatory redemption on December 31, 1997.

   With regard to long-term debt refinancing, on February 4, 1997, RECO issued
$20 million of First Mortgage 7 1/8% Bonds, Series J due February 1, 2007 (the
Series J Bonds). The proceeds of the Series J Bonds, together with other RECO
funds, were used to repay, on March 6, 1997, RECO's $20 million First Mortgage
9.59% Bonds, Series H.

   On October 1, 1997, the Company's First Mortgage Bonds, Series I, 6 1/2% (the
Series I Bonds) in the principal amount of $23 million were repaid at maturity.
The Series I Bonds were the final series of bonds outstanding under the Orange
and Rockland Utilities, Inc. First Mortgage Indenture and the Company has
canceled its First Mortgage and discharged the lien thereon. In addition, on
October 15, 1997, the Company's Debentures, Series B, 6 1/2% (the Series B
Debentures) in the principal amount of $55 million were repaid at maturity.
Funds required for the repayment of the


                                                                              15
<PAGE>   7
Orange and Rockland Utilities, Inc. and Subsidiaries

Series I Bonds and the Series B Debentures, which totaled $78 million, were
provided by the issuance of promissory notes pending the issuance by the
Company, on December 18, 1997, of $80 million of 6 1/2% Debentures, due 2027
(Series E) (the Series E Debentures), the proceeds of which were used to repay
such promissory notes.

   The Series E Debentures were not registered under the Securities Act of 1933
(the 1933 Act) and were offered to qualified institutional buyers pursuant to
Rule 144A of the 1933 Act. Pursuant to an agreement with the initial purchasers
of the Series E Debentures, the Company in January 1998, registered the Series F
Debentures under the Act. The Series F Debentures are substantially identical to
the Series E Debentures and will be offered to purchasers of the Series E
Debentures in exchange for the Series E Debentures. The combined amount
outstanding at any time of the Series E Debentures and Series F Debentures will
not exceed $80 million.

   During December 1997, the Company initiated a Common Stock Repurchase
Program. Pursuant to an Order of the NYPSC, the Company plans to repurchase up
to 700,000 shares of its common stock from time to time, but not later than
December 31, 1999, in the open market or through privately negotiated
transactions. Pursuant to a Credit Agreement between the Company and Mellon
Bank, N.A., the funds required for the common stock repurchase will be provided
by a revolving line of credit of up to $25 million which will be converted to a
term loan at the completion of the common stock repurchase program.

   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 the original issue 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 had the authority to issue up to 750,000 shares of
its common stock under the DRP and ESPP through December 31, 1997, of which
693,000 shares were unissued at that date. The Company did not request that the
NYPSC extend the authority to issue common stock to satisfy the requirements of
these plans.

   Neither the Company nor its utility subsidiaries have any plans at the
present time for additional external financing other than securities issued for
debt refunding purposes and for the common stock repurchase program, as
described above.

   Pursuant to an order of the FERC, the Company has authority to issue up to
$200 million of short-term debt through September 30, 1999 and RECO has
authority to issue up to $15 million of short-term debt through December 31,
1999. At December 31, 1997, the Company and its utility subsidiaries had
unsecured bank lines of credit totaling $167 million. At January 1, 1998, the
Company reduced such lines of credit to $140 million. The Company may borrow
under the lines of credit through the issuance of promissory notes to the banks.
The Company, however, primarily 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. The non-utility subsidiaries of the Company and of RECO had no
bank lines of credit at December 31, 1997.

OTHER DEVELOPMENTS

YEAR 2000 COMPLIANCE

   In 1996, the Emerging Issues Task Force of the Financial Accounting Standards
Board reached a consensus, EITF Issue No. 96-14, that internal and external
costs specifically associated with modifying internal-use computer software for
the upcoming century date change should be charged to expense as incurred.

   The Company recognizes that this is one of the most critical problems facing
data processing today and has taken measures to ensure that it identifies and
addresses all Year 2000 compliance issues. The four major areas of concern are
Mainframe Systems, Desktop Systems, Embedded Systems and Vendor Supply Chain.
The Company has developed a conversion strategy and established a schedule in an
effort to ensure that its Mainframe, Desktop and Embedded systems are Year 2000
compliant by the end of the first quarter of 1999. The Vendor Supply Chain issue
requires that a plan be established to mitigate the risk of potential business
disruptions by communicating compliance concerns to suppliers who are critical
to the business. The Company is in the process of communicating its Year 2000
compliance concerns to all its key suppliers and vendors. The Company will react
according to the information it receives and expects this process to continue
into 1999. The Company does not expect Year 2000 compliance remediation to have
a material effect on the Company's results of operations.

SFAS NO. 88

   The proposed sale of the Company's generating assets may result in workforce
reductions. The Company plans to provide, where appropriate, termination
benefits that include pension protection, severance, and outplacement services
to affected employees. Statement of Financial Accounting Standards No. 88 (SFAS
No. 88), "Employers Accounting for Settlements and Curtailments of Defined
Benefit Pension Plans and for Termination Benefits," applies to any employer
that offers benefits to employees in connection with their termination of
employment. The Restructuring Plan includes provisions to recover such costs.
Therefore, they are not expected to have a material impact on the Company's
results of operations.

NEW FINANCIAL ACCOUNTING STANDARDS

   During 1997, the Financial Accounting Standards Board issued the following
accounting standards: Statement of Financial Accounting Standards No. 128 (SFAS
No. 128), "Earnings Per Share;" Statement of Financial Accounting Standards No.
130 (SFAS No. 130), "Reporting Comprehensive Income;" and Statement of Financial
Accounting Standards No. 131 (SFAS No. 131), "Disclosures about Segments of an
Enterprise and Related Information." Basic Earnings per Share as it relates to
SFAS No. 128 would not be affected by the conversion of the Non-Redeemable $1.52
Convertible Cumulative Preference Stock, Series A. The Company has adopted these
standards for the year ended December 31, 1997. Adoption of these standards had
no effect on the results of operations of the Company.

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
historical costs and do not generally recognize the impact of inflation.


16
<PAGE>   8
Orange and Rockland Utilities, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF INCOME

<TABLE>
<CAPTION>
                                                                                         Year Ended December 31,
                                                                             1997                  1996                  1995
-------------------------------------------------------------------------------------------------------------------------------
                                                                                          (Thousands of Dollars)
<S>                                                                       <C>                   <C>                   <C>
OPERATING REVENUES:
         Electric (Note 1)                                                $ 472,364             $ 473,936             $ 457,833
         Gas (Note 1)                                                       168,450               176,442               140,224
         Electric sales to other utilities                                    7,109                 3,106                 2,150
-------------------------------------------------------------------------------------------------------------------------------
           Total Utility Revenues                                           647,923               653,484               600,207
         Diversified activities                                                 851                 1,405                 2,103
-------------------------------------------------------------------------------------------------------------------------------
           Total Operating Revenues                                         648,774               654,889               602,310
-------------------------------------------------------------------------------------------------------------------------------
OPERATING EXPENSES:
         Operations:
           Fuel used in electric production (Note 1)                         69,261                54,917                69,042
           Electricity purchased for resale (Note 1)                         65,500                73,776                54,700
           Gas purchased for resale (Note 1)                                 99,321               101,614                71,566
           Other expenses of operation                                      143,675               147,819               132,080
         Maintenance                                                         35,285                36,652                41,190
         Depreciation and amortization (Note 1)                              35,861                32,272                37,524
         Taxes other than income taxes                                       98,996                98,829                93,959
         Federal income taxes (Notes 1 and 2)                                23,878                26,366                26,680
-------------------------------------------------------------------------------------------------------------------------------
           Total Operating Expenses                                         571,777               572,245               526,741
-------------------------------------------------------------------------------------------------------------------------------
INCOME FROM OPERATIONS                                                       76,997                82,644                75,569
-------------------------------------------------------------------------------------------------------------------------------
OTHER INCOME AND DEDUCTIONS:
         Allowance for other funds used during construction                      40                    20                    28
         Investigation and litigation costs                                  (2,761)               (1,800)               (7,218)
         Other - net                                                            949                (2,268)               (1,636)
         Taxes other than income taxes                                         (270)                 (246)                 (163)
         Federal income taxes (Notes 1 and 2)                                 1,562                   662                 3,308
-------------------------------------------------------------------------------------------------------------------------------
           Total Other Income and Deductions                                   (480)               (3,632)               (5,681)
-------------------------------------------------------------------------------------------------------------------------------
INCOME BEFORE INTEREST CHARGES                                               76,517                79,012                69,888
-------------------------------------------------------------------------------------------------------------------------------
INTEREST CHARGES:
         Interest on long-term debt                                          23,215                24,221                26,620
         Other interest                                                       8,233                 5,748                 4,908
         Amortization of debt premium and expense - net                       1,521                 1,462                 1,394
         Allowance for borrowed funds used during construction               (1,390)                 (566)                 (800)
-------------------------------------------------------------------------------------------------------------------------------
           Total Interest Charges                                            31,579                30,865                32,122
-------------------------------------------------------------------------------------------------------------------------------
INCOME FROM CONTINUING OPERATIONS                                            44,938                48,147                37,766
-------------------------------------------------------------------------------------------------------------------------------
DISCONTINUED OPERATIONS: (Note 3)
         Operating income (loss) - net of taxes                              (6,738)               (1,844)                  807
         Estimated loss on disposal                                          (8,694)                   --                    --
-------------------------------------------------------------------------------------------------------------------------------
           Income (Loss) from Discontinued Operations                       (15,432)               (1,844)                  807
-------------------------------------------------------------------------------------------------------------------------------
NET INCOME                                                                   29,506                46,303                38,573
Dividends on preferred and preference stock, at required rates                2,800                 3,024                 3,135
-------------------------------------------------------------------------------------------------------------------------------
Earnings applicable to common stock                                       $  26,706             $  43,279             $  35,438
-------------------------------------------------------------------------------------------------------------------------------
Average number of common shares outstanding (000's)                          13,649                13,654                13,653
-------------------------------------------------------------------------------------------------------------------------------
EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING:
         Continuing Operations                                            $    3.09             $    3.30             $    2.54
         Discontinued Operations                                              (0.49)                (0.13)                 0.06
         Estimated loss on disposal                                           (0.64)                   --                    --
-------------------------------------------------------------------------------------------------------------------------------
TOTAL EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING                       $    1.96             $    3.17             $    2.60
-------------------------------------------------------------------------------------------------------------------------------

The accompanying notes are an integral part of these statements.


                                                                           
                                                                                                                             17
</TABLE>
<PAGE>   9
Orange and Rockland Utilities, Inc. and Subsidiaries

CONSOLIDATED BALANCE SHEETS

<TABLE>
<CAPTION>
                                                                                                December 31,
                                                                                          1997                 1996
-----------------------------------------------------------------------------------------------------------------------
                                                                                           (Thousands of Dollars)
<S>                                                                                    <C>                   <C>
ASSETS:
UTILITY PLANT:
         Electric                                                                      $1,047,857            $1,023,796
         Gas                                                                              232,206               219,712
         Common                                                                            64,570                59,589
-----------------------------------------------------------------------------------------------------------------------
           Utility Plant in Service                                                     1,344,633             1,303,097
         Less accumulated depreciation                                                    471,865               440,333
-----------------------------------------------------------------------------------------------------------------------
           Net Utility Plant in Service                                                   872,768               862,764
         Construction work in progress                                                     63,445                36,879
-----------------------------------------------------------------------------------------------------------------------
           Net Utility Plant (Notes 1, 7 and 12)                                          936,213               899,643
-----------------------------------------------------------------------------------------------------------------------
NON-UTILITY PROPERTY:
         Non-utility property                                                              11,651                17,818
         Less accumulated depreciation and amortization                                     1,109                 2,344
-----------------------------------------------------------------------------------------------------------------------
           Net Non-utility Property (Notes 1 and 7)                                        10,542                15,474
-----------------------------------------------------------------------------------------------------------------------
CURRENT ASSETS:
         Cash and cash equivalents (Notes 8 and 9)                                          3,513                 3,321
         Temporary cash investments (Note 9)                                                  518                 1,289
         Customer accounts receivable, less allowance for uncollectible
           accounts of $2,530 and $2,391, respectively                                     61,817                60,992
         Accrued utility revenue (Note 1)                                                  22,869                22,773
         Other accounts receivable, less allowance for uncollectible
           accounts of $258 and $258, respectively                                         20,450                 7,648
         Materials and supplies (at average cost):
           Fuel for electric generation                                                     8,875                 7,201
           Gas in storage                                                                  11,103                12,819
           Construction and other supplies                                                 15,291                15,575
         Prepaid property taxes                                                            21,575                20,051
         Prepayments and other current assets                                              21,469                21,540
-----------------------------------------------------------------------------------------------------------------------
           Total Current Assets                                                           187,480               173,209
-----------------------------------------------------------------------------------------------------------------------
DEFERRED DEBITS:
         Income tax recoverable in future rates(Notes 1 and 2)                             74,731                74,198
         Deferred Order 636 transition costs(Note 1)                                        1,476                11,732
         Deferred revenue taxes(Note 1)                                                    10,923                14,271
         Deferred pension and other postretirement benefits(Notes 1 and 10)                 9,334                 9,922
         IPP settlement agreements(Note 1)                                                 14,238                24,065
         Unamortized debt expense(amortized over term of securities)                       11,153                10,046
         Other deferred debits                                                             30,274                27,236
-----------------------------------------------------------------------------------------------------------------------
           Total Deferred Debits                                                          152,129               171,470
-----------------------------------------------------------------------------------------------------------------------
NET ASSETS OF DISCONTINUED OPERATIONS (Note 3):                                             1,645                 6,336
-----------------------------------------------------------------------------------------------------------------------
           TOTAL ASSETS                                                                $1,288,009            $1,266,132
-----------------------------------------------------------------------------------------------------------------------

The accompanying notes are an integral part of these statements.

18
</TABLE>
<PAGE>   10
Orange and Rockland Utilities, Inc. and Subsidiaries

<TABLE>
<CAPTION>
                                                                               December 31,
                                                                        1997                   1996
--------------------------------------------------------------------------------------------------------
                                                                          (Thousands of Dollars)
<S>                                                                 <C>                     <C>
CAPITALIZATION AND LIABILITIES:
CAPITALIZATION:
         Common stock (Note 6)                                      $    67,945             $    68,271
         Premium on capital stock (Note 6)                              132,985                 133,616
         Capital stock expense                                           (6,084)                 (6,097)
         Retained earnings (Note 5)                                     181,473                 192,060
--------------------------------------------------------------------------------------------------------
           Total Common Stock Equity                                    376,319                 387,850
--------------------------------------------------------------------------------------------------------
         Non-redeemable preferred stock                                  42,844                  42,844
         Non-redeemable cumulative preference stock                         379                     397
--------------------------------------------------------------------------------------------------------
           Total Non-Redeemable Stock (Note 6)                           43,223                  43,241
--------------------------------------------------------------------------------------------------------
         Long-term debt (Notes 7 and 9)                                 356,637                 281,622
--------------------------------------------------------------------------------------------------------
           Total Capitalization                                         776,179                 712,713
--------------------------------------------------------------------------------------------------------
NON-CURRENT LIABILITIES:
         Reserve for claims and damages (Note 1)                          4,591                   3,843
         Postretirement benefits (Note 10)                               15,334                  15,213
         Pension costs (Note 10)                                         43,618                  37,421
         Obligations under capital leases (Note 11)                       1,646                      --
--------------------------------------------------------------------------------------------------------
           Total Non-current Liabilities                                 65,189                  56,477
--------------------------------------------------------------------------------------------------------
CURRENT LIABILITIES:
         Long-term debt and capital lease obligations
           due within one year (Notes 7 and 11)                             209                  78,203
         Preferred stock to be redeemed within one year                      --                   1,390
         Commercial paper (Notes 8 and 9)                               130,400                  82,370
         Accounts payable                                                57,630                  67,449
         Dividends payable                                                  637                     665
         Customer deposits                                                4,639                   4,865
         Accrued Federal income and other taxes                           2,929                   1,024
         Accrued interest                                                 6,011                   7,039
         Refundable gas costs (Note 1)                                    5,893                   6,839
         Refunds to customers                                               986                   1,816
         Other current liabilities                                       19,391                  23,231
--------------------------------------------------------------------------------------------------------
           Total Current Liabilities                                    228,725                 274,891
--------------------------------------------------------------------------------------------------------
DEFERRED TAXES AND OTHER:
         Deferred Federal income taxes (Notes 1 and 2)                  192,514                 185,156
         Deferred investment tax credits (Notes 1 and 2)                 14,482                  15,292
         Accrued Order 636 transition costs                               1,340                  11,620
         Accrued IPP settlement agreements (Note 1)                          --                   2,000
         Other deferred credits                                           9,580                   7,983
--------------------------------------------------------------------------------------------------------
           Total Deferred Taxes and Other                               217,916                 222,051
--------------------------------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES (NOTE 12):                                     --                      --
--------------------------------------------------------------------------------------------------------
           TOTAL CAPITALIZATION AND LIABILITIES                     $ 1,288,009             $ 1,266,132
--------------------------------------------------------------------------------------------------------

                                                                                                      19
</TABLE>
<PAGE>   11
Orange and Rockland Utilities, Inc. and Subsidiaries

CONSOLIDATED CASH FLOW STATEMENTS

<TABLE>
<CAPTION>
                                                                                               Year Ended December 31,
                                                                                  1997                  1996                  1995
----------------------------------------------------------------------------------------------------------------------------------
                                                                                               (Thousands of Dollars)
<S>                                                                          <C>                   <C>                   <C>
CASH FLOW FROM OPERATIONS:
         Net income                                                          $  29,506             $  46,303             $  38,573
         Adjustments to reconcile net income to
         net cash provided by operating activities:
           Depreciation and amortization                                        35,415                33,765                37,786
           Deferred Federal income taxes                                         7,280                 5,353                 8,531
           Amortization of investment tax credit                                  (810)                 (925)                 (892)
           Deferred and refundable fuel and gas costs                           (1,096)               (6,371)               (6,606)
           Allowance for funds used during construction                         (1,430)                 (586)                 (828)
           Other non-cash changes                                                5,021                 3,759                 8,682
           Changes in certain current assets and liabilities:
             Accounts receivable, net and accrued utility revenue              (13,723)                  (26)               (3,547)
             Materials and supplies                                                326                (2,927)                4,941
             Prepaid property taxes                                             (1,524)                  636                (1,360)
             Prepayments and other current assets                                   71                 2,708                 1,319
             Accounts payable                                                   (9,819)                5,367                (1,773)
             Accrued Federal income and other taxes                              1,905                  (800)               (4,125)
             Accrued interest                                                   (1,028)                 (213)               (1,356)
             Refunds to customers                                                 (830)              (12,087)                3,638
             Other current liabilities                                          (4,066)                1,478                 4,822
           Discontinued operations -- non-cash                                   4,691                 3,978               (10,520)
           Other -- net                                                         17,874                (2,090)               (1,791)
----------------------------------------------------------------------------------------------------------------------------------
             Net Cash Provided by Operations                                    67,763                77,322                75,494
----------------------------------------------------------------------------------------------------------------------------------
CASH FLOW FROM INVESTING ACTIVITIES:
         Additions to plant                                                    (73,986)              (58,834)              (54,203)
         Temporary cash investments                                                771                    46                   504
         Allowance for funds used during construction                            1,430                   586                   828
----------------------------------------------------------------------------------------------------------------------------------
             Net Cash Used in Investing Activities                             (71,785)              (58,202)              (52,871)
----------------------------------------------------------------------------------------------------------------------------------
CASH FLOW FROM FINANCING ACTIVITIES:
         Proceeds from:
           Issuance of long-term debt                                          100,088                    26                44,048
           Issuance of capital lease obligation                                  2,020                    --                    --
         Retirement of:
           Common stock                                                         (3,012)                   --                    --
           Preference and preferred stock                                       (1,390)               (1,384)               (1,384)
           Long-term debt                                                     (103,261)                 (195)              (63,471)
           Capital lease obligations                                              (204)                 (275)                 (518)
         Net borrowings (repayments) under short-term
           debt arrangements                                                    48,030                21,120                31,850
         Dividends on preferred and common stock                               (38,057)              (38,280)              (38,259)
----------------------------------------------------------------------------------------------------------------------------------
             Net Cash Used in Financing Activities                               4,214               (18,988)              (27,734)
----------------------------------------------------------------------------------------------------------------------------------
NET CHANGE IN CASH AND CASH EQUIVALENTS                                            192                   132                (5,111)
Cash and Cash Equivalents at Beginning of Year                                   3,321                 3,189                 8,300
----------------------------------------------------------------------------------------------------------------------------------
CASH AND CASH EQUIVALENTS AT END OF YEAR                                     $   3,513             $   3,321             $   3,189
----------------------------------------------------------------------------------------------------------------------------------
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
         Cash paid during the year for:
           Interest, net of amounts capitalized                              $  32,313             $  29,209             $  30,186
           Federal income taxes                                              $  10,000             $  17,982             $  15,575
----------------------------------------------------------------------------------------------------------------------------------

The accompanying notes are an integral part of these statements.

20
</TABLE>
<PAGE>   12
Orange and Rockland Utilities, Inc. and Subsidiaries

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 ongoing diversified activities, at year end, consisted of
energy services and land development businesses conducted by its wholly owned
non-utility subsidiaries.

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 Utilities
(NJBPU), and the Pennsylvania Public Utility Commission (PPUC), respectively,
and the FERC. The consolidated financial statements of the Company are based on
generally accepted accounting principles, including the provisions of Statement
of Financial Accounting Standards No. 71 (SFAS No. 71), "Accounting for the
Effects of Certain Types of Regulation," which gives recognition to the
rate-making and accounting practices of the regulatory agencies. The principal
effect of the rate-making process on the Company's consolidated financial
statements is that of the timing of the recognition of incurred costs. If rate
regulation provides 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, 1997 and 1996:

<TABLE>
<CAPTION>
                                                     1997                 1996
--------------------------------------------------------------------------------
                                                       (Thousands of Dollars)
<S>                                                <C>                 <C>
Deferred Income Taxes (Note 1)                     $  74,731           $  74,198
FERC Order 636 Costs                                   1,476              11,732
Deferred Revenue Taxes (Note 1)                       10,923              14,271
Deferred Pension and Other
   Postretirement Benefits (Note 10)                   9,334               9,922
Gas Take-or-Pay Costs                                  1,473               2,117
Deferred Plant Maintenance Costs (Note 1)              4,251               4,244
Demand Side Management Costs                           3,047               1,181
Deferred Fuel and Gas Costs (Note 1)                  (3,848)             (4,943)
IPP Settlement Agreements (Note 1)                    14,238              24,065
Other                                                  7,663               8,834
--------------------------------------------------------------------------------
   Total                                           $ 123,288           $ 145,621
--------------------------------------------------------------------------------
</TABLE>

   The Company's Restructuring Plan, as approved by the NYPSC, provides for full
recovery of all regulatory assets. The Company will continue application of SFAS
No. 71 for the generation portion of the business until the divestiture is
complete (see Note 4).

   In March 1995, the Financial Accounting Standards Board issued SFAS No. 121,
"Accounting for Impairment of Long-Lived Assets and Long-Lived Assets to be
Disposed Of." This Statement imposes criteria for the continued recognition of
regulatory assets by requiring that such assets be probable of future recovery
at each balance sheet date. The Company adopted this standard on January 1,
1996. The adoption did not have any impact on the financial position or results
of operations of the Company.

UTILITY REVENUES

   Utility revenues are recorded on the basis of cycle billings rendered to
customers monthly. Prior to the fourth quarter of 1997, the Company rendered
bills 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.

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

FUEL COSTS

   The tariff schedules for electric and gas services in New York include
adjustment clauses under which fuel, purchased gas and certain purchased power
costs, above or below levels allowed in approved rate schedules, are billed or
credited to customers up to approximately 60 days after the costs are incurred.
In accordance with regulatory commission policy, such costs, along with the
related income tax effects, are deferred until billed 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 twelve-month period. The NYPSC
provides for a modified electric fuel adjustment clause requiring an 80%/20%
sharing between customers and shareholders of variations between actual and
forecasted fuel costs annually. The 20% portion of fluctuations from forecasted
costs is limited to a maximum of $1,762,000 annually. The fuel costs targets are
approved by the NYPSC for each calendar year following the Company's filing of
forecasted fuel costs. Tariffs for electric and gas service in Pennsylvania and
electric service in New Jersey contain adjustment clauses which utilize
estimated prospective energy costs on an annual basis. The recovery of such
estimated costs is made through equal monthly charges over the year of
projection. Any over- or under-recoveries are deferred and refunded or charged
to customers during the subsequent twelve-month period.

                                                                              21
<PAGE>   13
Orange and Rockland Utilities, Inc. and Subsidiaries

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

<TABLE>
<CAPTION>
Year Ended December 31,             1997              1996              1995
--------------------------------------------------------------------------------
<S>                                 <C>               <C>               <C>
Plant Classification:
   Electric                         3.03%             2.88%             3.07%
   Gas                              2.90%             2.91%             2.95%
   Common                           7.21%             5.93%             6.64%
--------------------------------------------------------------------------------
</TABLE>

   The composite gas depreciation rate in 1997 and 1996 excludes the effects of
adjustments provided for in a 1996 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,                      1997              1996
---------------------------------------------------------------------
                                             (Thousands of Dollars)
<S>                                        <C>               <C>
Electric Utility Plant in Service          $103,217          $102,309
Construction Work in Progress              $    739          $  1,317
---------------------------------------------------------------------
</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 requires the recording of
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 ten-year period. In addition,
certain New York State revenue taxes included in rate base are deferred and
amortized over a twelve-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, 1997, the remaining $14.2 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 ten-year amortization for rate purposes. 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.

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 1993 and 1994. The Company and IRS have agreed to an
assessment for tax deficiency and interest, which had a minimal effect on the
operating results of the Company.

   The components of federal income taxes are as follows:

<TABLE>
<CAPTION>
Year Ended December 31,                             1997               1996               1995
-------------------------------------------------------------------------------------------------
                                                               (Thousands of Dollars)
<S>                                               <C>                <C>                <C>
Charged to operations:
   Current                                        $ 17,517           $ 21,120           $ 18,888
   Deferred - net                                    6,482              5,374              7,914
   Amortization of investment tax credit              (121)              (128)              (122)
-------------------------------------------------------------------------------------------------
      Total charged to operations                   23,878             26,366             26,680
-------------------------------------------------------------------------------------------------
Charged to other income:
   Current                                          (1,671)               155             (3,160)
   Deferred - net                                      798                (21)               617
   Amortization of investment tax credit              (689)              (796)              (765)
-------------------------------------------------------------------------------------------------
      Total charged to other income                 (1,562)              (662)            (3,308)
-------------------------------------------------------------------------------------------------
Total                                             $ 22,316           $ 25,704           $ 23,372
-------------------------------------------------------------------------------------------------
</TABLE>

22
<PAGE>   14
Orange and Rockland Utilities, Inc. and Subsidiaries

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

<TABLE>
<CAPTION>
As of December 31,                      1997               1996
------------------------------------------------------------------
                                        (Thousands of Dollars)
<S>                                  <C>                 <C>
Liabilities:
   Accelerated depreciation          $ 191,438           $ 188,039
   Other                                39,305              30,887
------------------------------------------------------------------
      Total liabilities                230,743             218,926
------------------------------------------------------------------
Assets:
   Employee benefits                   (19,650)            (17,136)
   Deferred fuel costs                    (442)               (404)
   Other                               (18,137)            (16,230)
------------------------------------------------------------------
      Total assets                     (38,229)            (33,770)
------------------------------------------------------------------
Net Liability                        $ 192,514           $ 185,156
------------------------------------------------------------------
</TABLE>

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

<TABLE>
<CAPTION>
Year Ended December 31,                                        1997           1996          1995
-------------------------------------------------------------------------------------------------
                                                                     (% of Pre-tax Income)

<S>                                                            <C>            <C>            <C>
Statutory tax rate                                              35%            35%            35%
Changes in computed taxes resulting from:
   Amortization of investment tax credits                       (1)            (1)            (1)
   Cost of removal                                              (1)            (1)            (2)
   Additional depreciation deducted for book purposes            3              4              5
   Other                                                        (3)            (3)            --
-------------------------------------------------------------------------------------------------
Effective Tax Rate                                              33%            34%            37%
-------------------------------------------------------------------------------------------------
</TABLE>

NOTE 3. DISCONTINUED OPERATIONS.

   In August 1997, Norstar Management, Inc. (NMI), a wholly owned indirect
subsidiary of the Company, sold certain of the assets of NORSTAR Energy Limited
Partnership (NORSTAR), a natural gas services and marketing company of which NMI
is the general partner. The assets sold consist primarily of customer contracts
and accounts receivable. NMI is expected to wind up the remaining portion of the
NORSTAR business in the first quarter of 1998. In accordance with Accounting
Principles Board Opinion No. 30, the financial results for this segment are
reported as "Discontinued Operations." The total (losses)/gains related to
discontinued operations were $(15,432,000), or $(1.13) per share, for 1997,
$(1,844,000), or $(0.13) per share, for 1996 and $807,000, or $0.06 per share,
for 1995. The net assets of these operations at December 31, 1997 consist of
cash of $1.7 million, net accounts receivable of $0.6 million, other current
assets of $1.0 million offset by accounts payable of $1.7 million.

NOTE 4. DIVESTITURE OF POWER PLANTS.

   The Company's Electric Rate and Restructuring Plan (the Restructuring Plan),
which was approved by the NYPSC by its Orders dated November 26 and December 31,
1997, provides for the sale of all of the Company's electric generating assets
by means of auction. On December 10, 1997, the Company notified the NYPSC that
it will not participate as a bidder in the auction, and on December 11, 1997, in
accordance with the Restructuring Plan, the Company submitted its Preliminary
Divestiture Plan to the NYPSC staff and other parties.

   The Company filed its final Divestiture Plan on February 4, 1998, with final
approval by the NYPSC expected in the spring of 1998. Upon receipt of NYPSC
approval, bids would be solicited shortly thereafter, with a winning bidder to
be selected by the end of the third quarter of 1998. Under the proposed
schedule, the sale of the generating facilities is anticipated to be completed
by mid-1999.

   The generating assets held for sale include the fossil units at the Lovett
Generating Station and the Company's one-third interest in the Bowline Point
Generating Station; the two gas turbine units located at Hillburn and
Middletown; and the hydroelectric stations located at Mongaup, Rio, Swinging
Bridge and Grahamsville. The total net book value of the plant assets at
December 31, 1997 is approximately $269 million. In addition, fuel and material
and supplies inventories, with a carrying value of $20 million at December 31,
1997, will be included in the sale.

   Under the Restructuring Plan approved by the NYPSC, the Company will remain a
regulated transmission and distribution company that will deliver electricity to
its customers and maintain reliable service. The Company will remain the
"provider of last resort" for those of its customers who do not purchase
electricity from other sources.

   The plan also calls for lower electric rates for all customers, with
potential savings as high as 12 percent for the Company's largest industrial
customers, and approximately five percent for all others. In addition, the
Restructuring Plan, as approved, provides that the Company's PowerPick(TM)
program, under which certain customers select an energy supplier other than the
Company, will be available to all customers no later than May 1998 and all
customers will have full retail choice (energy and capacity) by May 1999.

   Consistent with the recent interpretation by the Financial Accounting
Standards Board's Emerging Issues Task Force regarding the application of SFAS
No. 71, the Company will continue application of this standard to the generation
portion of the business.

NOTE 5. RETAINED EARNINGS.

Consolidated Statements of Retained Earnings:

<TABLE>
<CAPTION>
Year Ended December 31,                  1997               1996                1995
--------------------------------------------------------------------------------------
                                                    (Thousands of Dollars)
<S>                                   <C>                 <C>                <C>
Balance at beginning of year          $ 192,060           $ 184,008          $ 183,659
Net income before dividends              29,506              46,303             38,573
--------------------------------------------------------------------------------------
                                        221,566             230,311            222,232
--------------------------------------------------------------------------------------
Less: Dividends
   Preferred stock                        2,800               3,024              3,135
   Common stock                          35,229              35,227             35,089
--------------------------------------------------------------------------------------
                                         38,029              38,251             38,224
--------------------------------------------------------------------------------------
Capital stock repurchase                 (2,064)                 --                 --
--------------------------------------------------------------------------------------
Balance at end of year                $ 181,473           $ 192,060          $ 184,008
--------------------------------------------------------------------------------------
</TABLE>

   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, 1997 and 1996 was so restricted.

                                                                              23
<PAGE>   15
[Orange and Rockland Utilities, Inc. and Subsidiaries

NOTE 6. CAPITAL STOCK.

   The table below summarizes the changes in Capital Stock, issued and
outstanding, for the years 1995, 1996 and 1997.

<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 12/31/94:        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
  Reacquired Stock          (65,900)           (330)                                            --              --            (644)
  Conversions                   790               4                                            (541)            (18)             13
------------------------------------------------------------------------------------------------------------------------------------
Balance 12/31/97:        13,589,011     $     67,945        428,443     $    42,844          11,639     $       379    $    132,985
------------------------------------------------------------------------------------------------------------------------------------
Shares Authorized        50,000,000                         820,000                       1,500,000
------------------------------------------------------------------------------------------------------------------------------------
*(in thousands)
</TABLE>

   (A) Pursuant to a December 1997 Order of the NYPSC, the Company has authority
to repurchase up to 700,000 shares of its common stock and to issue up to $25
million of long-term debt to provide funds for the common stock repurchase.
Through December 31, 1997, the Company has repurchased 65,900 shares of its
common stock at an average market price of $45.69 per share.

   At December 31, 1997, 17,109 shares of common stock were reserved for
conversion of preference stock.

   (B) Non-Redeemable Preferred Stock (cumulative):

<TABLE>
<CAPTION>
                                  Par Value            Callable
              Shares            December 31,          Redemption
Series      Outstanding      1995, 1996 and 1997    Price Per Share
-------------------------------------------------------------------
                       (Thousands of Dollars)

<S>          <C>                <C>                    <C>
A, 4.65%      50,000            $ 5,000                $104.25
B, 4.75%      40,000              4,000                $102.00
D, 4.00%       3,443                344                $100.00
F, 4.68%      75,000              7,500                $102.00
G, 7.10%     110,000             11,000                $101.00
H, 8.08%     150,000             15,000                $102.43
-------------------------------------------------------------------
             428,443            $42,844
-------------------------------------------------------------------
</TABLE>

   This stock is 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 7. LONG-TERM DEBT.

   On October 1, 1997, the Company's First Mortgage Bonds, Series I, 6 1/2% (the
Series I Bonds) were redeemed at maturity. The Series I Bonds were the final
series of bonds outstanding under the Orange and Rockland Utilities, Inc. First
Mortgage Indenture, and the Company has canceled its First Mortgage and
discharged the lien thereon. 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. 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
1997 were satisfied by the allocation of an amount of additional property and
Pike expects to continue such practice in succeeding years.

   Details of long-term debt at December 31, 1997 and 1996 are
as follows:

<TABLE>
<CAPTION>
December 31,                                                                1997               1996
-----------------------------------------------------------------------------------------------------
                                                                             (Thousands of Dollars)
<S>                                                                       <C>               <C>
Orange and Rockland Utilities, Inc.:
   First Mortgage Bonds:
     Series I, 6 1/2% due Oct. 1, 1997 (a)                                $      --         $  23,000
   Promissory Notes (unsecured):
     6.9% - 6.97% due through April 15, 2001                                    106                56
     6.09% due Oct. 1, 2014 (b)                                              55,000            55,000
     Variable due Aug. 1, 2015 (c)                                           44,000            44,000
   Debentures:
     Series A, 93/8% due Mar. 15, 2000                                       80,000            80,000
     Series B, 6 1/2% due Oct. 15, 1997 (a)                                      --            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
     Series E/F, 6 1/2% due Dec. 1, 2027 (a)                                 80,000                --
Rockland Electric Company:
   First Mortgage Bonds:
     Series H, 9.59% due July 1, 2020 (d)                                        --            20,000
     Series I, 6% due July 1, 2000                                           20,000            20,000
     Series J, 7 1/8% due Feb. 1, 2007 (d)                                   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%                                                     --             5,228
-----------------------------------------------------------------------------------------------------
                                                                            356,790           359,968
     Less: Amount due within one year                                            39            78,203
-----------------------------------------------------------------------------------------------------
                                                                            356,751           281,765
     Unamortized discount on long-term debt                                    (114)             (143)
-----------------------------------------------------------------------------------------------------
     Total Long-Term Debt                                                 $ 356,637         $ 281,622
-----------------------------------------------------------------------------------------------------
</TABLE>

   (a) On October 1, 1997 and October 15, 1997, the Company's Series I Bonds in
the principal amount of $23 million and the Company's Debentures, Series B,
6 1/2% (the Series B Debentures) in the principal amount of $55 million,
respectively, were repaid at maturity. Funds required for the repayment of the
Series I Bonds and the Series B Debentures, which totaled $78 million, were
provided by the issuance of promissory notes pending the issuance by the
Company, on December 18, 1997, of $80 million of 6 1/2% Debentures, Series E, 
due December 1, 2027, the proceeds of which were used to repay such
promissory notes.

   The Series E Debentures are not redeemable prior to their stated maturity.
However, the holders may elect to have their Series E Debentures repaid on
December 1, 2004, at 100% of the principal amount of such debentures. The Series
E Debentures, which were not registered under the Securities Act of 1933 (the
1933 Act) in reliance upon an exemption under the 1933 Act, were issued for sale
to qualified institutional buyers pursuant to Rule 144A under the 1933 Act.
Pursuant to the terms of a Registration Rights Agreement, in January 1998, the
Company filed a registration statement with respect to an offer to exchange the
Series E Debentures for a new issue registered under the 1933 Act (the Series F
Debentures) with terms substantially identical to the Series E Debentures.

24
<PAGE>   16
Orange and Rockland Utilities, Inc. and Subsidiaries

   (b) 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%.

   (c) 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
3.54% in 1997 and 3.18% in 1996. The interest rate is adjusted weekly, unless
converted to a fixed rate.

   (d) 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 were used to
repay, in March 1997, RECO's $20 million First Mortgage 9.59% Bonds, Series H.

   In January 1998, the Company entered into a Credit Agreement with Mellon
Bank, N.A., the proceeds of which will be used to provide funds for the
Company's Common Stock Repurchase Program. The Credit Agreement provides for a
revolving line of credit of up to $25 million which may, at the option of the
Company, be converted to a five year term loan at the completion of the Common
Stock Repurchase Program. The Company intends to exercise this option. The rate
of interest on each draw down under the revolving line of credit will be
selected by the Company from among certain available rate options and the rate
of interest on the term loan will be a fixed rate which will be set at the time
of conversion to a term loan and will be based on U.S. Government treasury
notes, including spread and margin.

   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 1997 is as follows: 1998 -- $49,000; 1999 --
$46,000; 2000 -- $120,037,000; 2001 -- $887,000; 2002 -- $-0-.

   Substantially all of the utility plant and other physical property of the
Company's utility subsidiaries, RECO and Pike, are subject to the liens of the
indentures securing the First Mortgage Bonds of the utility subsidiaries.

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, 1997, the Company and its utility subsidiaries had unsecured
bank lines of credit totaling $167 million. Effective January 1, 1998, such
lines of credit were reduced to $140 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,
primarily 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. All borrowings for 1997, 1996 and 1995 had maturity dates of three
months or less. Information regarding short-term borrowings during the past
three years is as follows:

<TABLE>
<CAPTION>
                                                             1997           1996           1995
------------------------------------------------------------------------------------------------
                                                                     (Millions of Dollars)
<S>                                                         <C>            <C>           <C>
Weighted average interest rate at year-end                     7.0%           6.5%          6.1%
Amount outstanding at year-end                              $130.4         $ 82.4        $ 68.6
Average amount outstanding for the year                     $119.9         $ 66.6        $ 37.1
Daily weighted average interest rate during the year           5.9%           5.7%          6.1%
Maximum amount outstanding at any month-end*                $204.5         $ 97.5        $ 69.6
------------------------------------------------------------------------------------------------
*Includes $78.0 million of promissory notes as discussed in Note 7 (a).
</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, temporary cash investments, short-term debt, commercial
paper and long-term debt. 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.

   Commercial paper: The carrying amount reasonably approximates fair value
because of the short maturity of those instruments.

<TABLE>
<CAPTION>
                                             1997                          1996
------------------------------------------------------------------------------------------
                                  Carrying          Fair          Carrying          Fair
                                   Amount          Amount          Amount          Amount
------------------------------------------------------------------------------------------
                                                   (Thousands of Dollars)
<S>                               <C>             <C>             <C>             <C>
Cash and cash equivalents         $  3,513        $  3,513        $  3,321        $  3,321
Temporary cash investments             518             518           1,289           1,289
Long-term debt                     356,790         362,908         359,968         366,509
Commercial paper                   130,400         130,400          82,370          82,370
------------------------------------------------------------------------------------------
</TABLE>

OFF BALANCE SHEET AND DERIVATIVE FINANCIAL INSTRUMENTS

   The Company utilizes an interest rate swap derivative financial instrument.
At this time, no energy derivatives for its electric and natural gas operations
are in use. Information regarding the interest rate swap agreement is as
follows:

   Swap Agreement -- In connection with the issuance of the 1994 Bonds, the
Company entered into a single interest rate swap agreement during 1992. 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, 1997, the Company would have been required to make a
payment of approximately $7.4 million to the swap counterparty.

                                                                              25
<PAGE>   17
Orange and Rockland Utilities, Inc. and Subsidiaries

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. This
method 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, 1997 and 1996. Plan assets are stated at fair
market value and are composed primarily of common stocks and investment grade
debt securities.

<TABLE>
<CAPTION>
December 31,                                                    1997              1996
-----------------------------------------------------------------------------------------
                                                                 (Thousands of Dollars)
<S>                                                           <C>              <C>       
Actuarial present value of benefit obligations:
   Vested                                                     $(210,364)       $(191,499)
   Nonvested                                                    (20,736)         (15,947)
-----------------------------------------------------------------------------------------
Accumulated benefit obligation                                $(231,100)       $(207,446)
-----------------------------------------------------------------------------------------
Projected benefit obligation                                  $(241,787)       $(216,821)
Plan assets at fair market value                                247,523          225,997
-----------------------------------------------------------------------------------------
Excess of plan assets over projected benefit obligation           5,736            9,176
Unamortized net transition asset at adoption of
   SFAS No. 87 being amortized over 15 years                     (4,454)          (5,568)
Unrecognized prior service costs                                 38,581           29,485
Unrecognized net gain                                           (69,237)         (58,497)
-----------------------------------------------------------------------------------------
Accrued Pension Cost                                          $ (29,374)       $ (25,404)
-----------------------------------------------------------------------------------------
</TABLE>

         Net periodic pension expense calculated pursuant to the requirements of
SFAS No. 87 for the years 1997, 1996 and 1995 includes the following components:

<TABLE>
<CAPTION>
December 31,                                     1997             1996            1995
---------------------------------------------------------------------------------------
                                                       (Thousands of Dollars)
<S>                                            <C>             <C>             <C>     
Service cost-benefits earned during year       $  5,695        $  5,456        $  5,151
Interest cost on projected
   benefit obligation                            16,686          15,135          14,996
Actual return on plan assets                    (33,164)        (25,293)        (37,863)
Net deferred and capitalized                     14,753           7,579          20,129
---------------------------------------------------------------------------------------
Net Pension Expense                            $  3,970        $  2,877        $  2,413
---------------------------------------------------------------------------------------
</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 1997, 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 1997,
1996 and 1995 was $2.1 million, $1.6 million and $0.7 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 and who have rendered at least 10 years of service are entitled to
postretirement health care coverage.

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

         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 1997, the Company contributed
$7.4 million to the VEBA trust. Rate recoveries and billings to others totaled
$6.1 million in 1997 and $5.1 million in 1996. 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, 1997 and
December 31, 1996:

<TABLE>
<CAPTION>
                                                         1997            1996
--------------------------------------------------------------------------------
                                                        (Thousands of Dollars)
<S>                                                    <C>             <C>      
Accumulated postretirement benefit obligation:
   Fully eligible active employees                     $(15,336)       $(13,765)
   Other active employees                               (30,312)        (34,902)
   Retirees                                             (34,977)        (34,332)
--------------------------------------------------------------------------------
      Total benefit obligation                          (80,625)        (82,999)
Plan assets at fair value                                22,238          14,822
--------------------------------------------------------------------------------
Accumulated postretirement obligation in
   excess of plan assets                                (58,387)        (68,177)
Unrecognized transition obligation                       37,027          44,409
Prior service cost                                           --           2,174
Unrecognized experience net loss                          6,393           6,881
--------------------------------------------------------------------------------
Accrued Postretirement Benefit Cost                    $(14,967)       $(14,713)
--------------------------------------------------------------------------------
</TABLE>


26
<PAGE>   18
Orange and Rockland Utilities, Inc. and Subsidiaries

         The components of net periodic postretirement benefit cost for the
years ended December 31, 1997, 1996 and 1995 are as follows:

<TABLE>
<CAPTION>
                                              1997            1996            1995
------------------------------------------------------------------------------------
                                                      (Thousands of Dollars)
<S>                                         <C>             <C>             <C>     
Service cost                                $  1,863        $  2,050        $  1,586
Interest cost                                  6,013           5,925           5,622
Return on plan assets                            (25)           (546)           (319)
Amortization of transition obligation          2,572           2,776           2,790
Prior service cost                                84             202              --
Net losses                                     1,011             855             529
Deferred and capitalized                        (881)         (2,400)         (3,424)
------------------------------------------------------------------------------------
Net Expense                                 $ 10,637        $  8,862        $  6,784
------------------------------------------------------------------------------------
</TABLE>

         The calculation of the actuarial present value of benefit obligations
at December 31, 1997 assumes a discount rate of 7.5% and health care cost trend
rates of 7.0% for medical costs and 9.0% for prescription drugs in 1998,
decreasing through 2002 to a rate of 5.0%. If the health care trend rate
assumptions were increased by 1 percent, the accumulated postretirement benefit
obligation would be increased by approximately $9.3 million. The effect of this
change on the sum of the service cost and interest cost would be an increase of
$1.1 million. The assumed discount rate for 1996 was 7.5%, and health care cost
trend rates were 7.5% for medical costs and 10% for prescription drugs in 1997,
decreasing through 2002 to a rate of 5.0%.

NOTE 11. LEASES.

         The Company maintains leases for certain property and equipment which
meet the accounting criteria for capitalization. As required by Statement of
Financial Accounting Standards No. 71, (SFAS No. 71), "Accounting for the
Effects of Certain Types of Regulation," the Company has recorded such leases on
its balance sheets. The amount of leased property included in the accompanying
Consolidated Balance Sheets, and the obligation associated with such leases at
December 31, 1997 is as follows:

<TABLE>
<CAPTION>
As of December 31,                                                         1997
-----------------------------------------------------------------------------------------
                                                                   (Thousands of Dollars)
<S>                                                                <C>   
Utility plant                                                             $2,020
Less accumulated amortization                                                204
-----------------------------------------------------------------------------------------
   Net Assets Under Capital Leases                                        $1,816
-----------------------------------------------------------------------------------------
Non-current liabilities                                                   $1,646
Current liabilities                                                          170
-----------------------------------------------------------------------------------------
   Total Liabilities                                                      $1,816
-----------------------------------------------------------------------------------------
</TABLE>

         The Company had no capital leases at December 31, 1996.

         Although current rate-making practices treat all leases as operating
leases, SFAS No. 71 provides that regulated utilities shall recognize as a
charge against income an amount equal to the rental expense allowed for
rate-making purposes. Therefore, the rental payments on these leases have no
impact on the Company's Consolidated Statements of Income.

         The future minimum rental commitments under the Company's capital
leases and non-cancellable operating leases are as follows:

<TABLE>
<CAPTION>
                                                                    Non-cancellable
                                                         Capital       Operating
                                                          Leases        Leases
--------------------------------------------------------------------------------
                                                          (Thousands of Dollars)
<S>                                                      <C>        <C>    
1998                                                     $   291         $ 4,600
1999                                                         292           3,800
2000                                                         292           3,600
2001                                                         290           3,200
2002                                                         290           2,100
All years thereafter                                       1,015          25,000
--------------------------------------------------------------------------------
      Total                                                2,470         $42,300
Less amount representing interest                            654             N/A
--------------------------------------------------------------------------------
Present value of net minimum lease payments              $ 1,816             N/A
--------------------------------------------------------------------------------
</TABLE>

         Rental expense for 1997, 1996 and 1995 was $5.8 million, $6.2 million
and $6.0 million, respectively.

NOTE 12. COMMITMENTS AND CONTINGENCIES.

CONCENTRATION OF CREDIT RISK

         Financial instruments which potentially subject the Company to
concentrations of credit risk, as defined by Statement of Financial Accounting
Standards No. 105 "Financial Instruments with Concentrations of Credit Risk,"
consist principally of temporary cash investments and 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. Therefore, as of December 31, 1997, 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 $51.0 million will be incurred during 1998.
Construction expenditures, including cost of removal and salvage, amounted to
$73.1 million for 1997.

GAS SUPPLY AND STORAGE CONTRACTS

         The Company has long-term contracts for firm supply, transportation and
storage of gas. The contracts contain provisions that permit the Company to
extend the contracts beyond their primary term if they are still required to
serve firm customers.

         Approximately 90 percent of the Company's existing contracts will
expire between 2000 and 2004. The Company's obligations under these contracts
for the five years following 1997 are as follows: 1998 -- $61,100,000; 1999 --
$61,500,000; 2000 -- $57,700,000; 2001 -- $44,600,000 and 2002 -- $39,700,000.

         The NYPSC, in its effort to promote competition, has required the
Company to provide firm transportation service for those customers that elect to
purchase their gas supply from a marketer rather than the Company. Marketers are
permitted to aggregate customers and the Company is required to release
interstate pipeline capacity and storage to the marketers to serve these
customers until 1999. After 1999, marketers will be required to obtain their own
capacity, therefore, the Company will be able to reduce its capacity and
commitments. As the transition to a competitive retail market develops, the
Company will determine what supply capacity and storage contracts it maintains.
As the Company moves to a competitive market, traditional cost recovery
mechanisms may be replaced by market-based methods.

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 1997 is as follows:
1998 -- $32,900,000; 1999 -- $33,700,000; 2000 -- $27,600,000; 2001 --
$21,000,000; 2002 -- $21,600,000.

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.


                                                                              27
<PAGE>   19
Orange and Rockland Utilities, Inc. and Subsidiaries

         The Company's aggregate contract obligations for the purchase of
electric capacity and energy for each of the five years following 1997 is as
follows: 1998 -- $11,500,000; 1999 -- $3,100,000; 2000 -- $3,300,000; 2001 --
$700,000; 2002 -- $700,000.

LEGAL PROCEEDINGS

RESTRUCTURING LITIGATION

         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 utilities 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. On
October 31, 1997, the Supreme Court of the State of New York, Appellate
Division, Third Department, granted the petitioners' motion for an extension of
time to perfect the appeal for a period of six months, through and including
March 24, 1998. The Company's Restructuring Plan approved by the NYPSC's Orders
of November 26 and December 31, 1997 requires the Company to petition the
Appellate Division to withdraw its appeal. This petition must be filed
"following final Commission approval of this agreement" (i.e., when any appeals
from such approval are exhausted or the time to appeal has expired). If no party
initiates an Article 78 appeal, this petition will be filed after expiration of
the statute of limitations for challenging the Commission's Final Order. The
Company is unable to predict the final result of this litigation.

ENVIRONMENTAL LITIGATION

         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.
The Company and other PRPs are currently conducting a remedial investigation to
determine what, if any, subsurface remediation at the Borne site is required.
The Company does not believe that this matter will have a material effect on the
financial condition of the Company.

         On August 2, 1994, the Company entered into a Consent Order with the
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. The Company and the DEC have executed a second Consent Order to
implement a Record of Decision (ROD), dated October 20, 1997 issued by the DEC.
The ROD provides for the removal and off-site disposal of soils contaminated
with PCBs and other petroleum-related contaminants and the post-remedial
monitoring of groundwater. Deferred accounting treatment has been approved by
the NYPSC and these costs are expected to be recovered in rates.

         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
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 DEC, for its review and approval, a draft work
plan for the preliminary site assessment of three of the MGP sites. In April
1997, the DEC approved the work plans for these three sites. Field work was
subsequently completed and Preliminary Site Assessment reports for the three
sites were submitted to the DEC on September 1, 1997. These reports showed
varying degrees of contamination at each of the sites which will necessitate
further investigation. The DEC has provided written comments on these reports
and the Company expects to conduct the further investigation in the spring of
1998. In addition, the Company has submitted draft work plans for two additional
sites to the DEC for its review and approval. Although the Company is unable at
this time to estimate the total costs to be incurred at the six MGP sites,
deferred accounting treatment has been approved by the NYPSC and these costs are
expected to be recovered in rates.

         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. The Company entered into a tolling agreement by which the
Metal Bank Group reserved its right to file suit against the Company, and the
Metal Bank Group submitted the RIFS 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, because the
Company is not a member of the Group, the Company has been unable to confirm
this allocation. The EPA has issued a recommended proposed remediation plan
which, if approved, will cost approximately $17 million. In addition, the EPA
has requested information and documentation from the Company and advised the
Company of its opportunity to negotiate a settlement directly with the EPA upon
its issuance of a ROD (which, to date, has not been issued).


28
<PAGE>   20
Orange and Rockland Utilities, Inc. and Subsidiaries

The Company is unable at this time to estimate the Company's share, if any, of
past or future costs at this site.

OTHER LITIGATION

        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 certain 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. By Opinion and Order dated June 30, 1997 (Order), the Court dismissed
Crossroads' Complaint in its entirety with prejudice, and Crossroads' appeal to
the United States Court of Appeals for the Third Circuit is pending. The Company
cannot predict the ultimate outcome of this proceeding.

         On February 4, 1997, the Company's subsidiary, 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 includes nine counts, eight of which
claim compensatory damages of $2 million and exemplary damages of $4 million for
each count, and alleges claims on behalf of property owners in Old Tappan, New
Jersey related to alleged excessive noise at a substation operated by RECO in
Old Tappan. Discovery is at its inception in this case. In addition, hearings
are scheduled for February 1998 before the New Jersey Office of Administrative
Law on two matters: (1) an administrative complaint filed by Mr. Griffin with
the NJBPU; and (2) a Petition filed by RECO with the NJBPU seeking relief from a
September 1996 Resolution of the Old Tappan Board of Adjustment which orders
RECO to abate an alleged nuisance of excessive noise at the substation. 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.

ENVIRONMENTAL

         The Comprehensive Environmental Response, Compensation and Liability
Act of 1980 (CERCLA) and certain similar state statutes authorize various
governmental authorities to issue orders compelling responsible parties to take
cleanup action at sites determined to present an imminent and substantial danger
to the public and to the environment because of an actual or threatened release
of hazardous substances. 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. Additional NOx
reductions will be required effective May, 1999 for the annual ozone season
(May-September).

         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 the 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.

         In compliance with DEC proposed regulations, effective May 1, 1999, the
Company will be allocated NOx emission allowances for the annual ozone season.
The Company does not anticipate incurring additional capital costs to comply
with these proposed regulations.

         Beginning with calendar year 1994, Title V sources (Bowline and Lovett)
are required to pay an emission fee. Each facility's fees are based upon actual
air emissions reported to the DEC for the preceding calendar year. For 1997, the
Company paid an emission rate of approximately $28 per ton based upon 1996
emissions. The emission fee will be reevaluated by New York State annually.

         The EPA finalized in July, 1997 new national ambient air quality
standards for ozone particulate matter.

         The Company will continue to assess the impact of the Clean Air Act
Amendments of 1990 and new ozone and particulate standards on its power
generating operations as additional regulations implementing these Amendments
and standards are promulgated.

NOTE 13. SEGMENTS OF BUSINESS.

         In accordance with the requirements of Statement of Financial
Accounting Standards No. 131 (SFAS No. 131), "Disclosures about Segments of an
Enterprise and Related Information," the Company defines its principal business
segments as utility (electric and gas) and diversified activities. The
diversified segment, at year end, included energy services and land development.
Total utility revenue as reported in the Consolidated Statements of Income
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.


                                                                              29
<PAGE>   21
Orange and Rockland Utilities, Inc. and Subsidiaries

<TABLE>
<CAPTION>
Year Ended December 31,                           1997               1996              1995
-----------------------------------------------------------------------------------------------
                                                             (Thousands of Dollars)
<S>                                           <C>                <C>                <C>        
Operating Information:
   Operating revenues:
   Sales to unaffiliated customers:
     Electric                                 $   479,463        $   477,032        $   459,876
     Gas                                          168,421            176,400            140,177
   Intersegment sales:
     Electric                                          10                 10                107
     Gas                                               29                 42                 47
-----------------------------------------------------------------------------------------------
       Total Utility Operating Revenues           647,923            653,484            600,207
     Diversified activities                           851              1,405              2,103
-----------------------------------------------------------------------------------------------
       Total Operating Revenues               $   648,774        $   654,889        $   602,310
-----------------------------------------------------------------------------------------------
Operating income before income taxes:
     Electric                                 $    87,430        $    86,161        $    85,156
     Gas                                           15,382             22,447             17,467
     Diversified activities                        (1,937)               402               (374)
-----------------------------------------------------------------------------------------------
       Total Operating Income
          Before Income Taxes                     100,875            109,010            102,249
-----------------------------------------------------------------------------------------------
Income Taxes:
     Electric                                      21,837             21,585             22,406
     Gas                                            2,491              4,879              3,859
     Diversified activities                          (450)               (98)               415
-----------------------------------------------------------------------------------------------
       Total Income Taxes                          23,878             26,366             26,680
-----------------------------------------------------------------------------------------------
       Total Income From Operations           $    76,997        $    82,644        $    75,569
-----------------------------------------------------------------------------------------------
Other Information:
Identifiable assets:
     Electric                                 $   996,647        $   978,952        $   979,512
     Gas                                          241,656            240,471            217,357
     Diversified activities                        13,162             24,220             26,719
-----------------------------------------------------------------------------------------------
       Total Identifiable Assets                1,251,465          1,243,643          1,223,588
Corporate assets                                   36,544             22,489             27,953
-----------------------------------------------------------------------------------------------
       Total Assets                           $ 1,288,009        $ 1,266,132        $ 1,251,541
-----------------------------------------------------------------------------------------------
Depreciation expense:
     Electric                                 $    30,597        $    29,430        $    30,594
     Gas                                            5,091              2,578              6,646
     Diversified activities                           173                264                284
-----------------------------------------------------------------------------------------------
       Total Depreciation Expense             $    35,861        $    32,272        $    37,524
-----------------------------------------------------------------------------------------------
Additions to plants:
     Electric                                 $    48,555        $    41,932        $    43,225
     Gas                                           25,257             16,766             10,894
     Diversified activities                           174                136                 84
-----------------------------------------------------------------------------------------------
       Total Additions                        $    73,986        $    58,834        $    54,203
-----------------------------------------------------------------------------------------------
</TABLE>

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

<TABLE>
<CAPTION>
                                                                  Earnings       Earnings
                                                                 Applicable         Per
                                   Income                            To          Average
                   Operating        From          Net              Common         Common
                   Revenues       Operations     Income            Stock           Share
---------------------------------------------------------------------------------------------
                                           (Thousands of Dollars)
<S>                <C>            <C>            <C>             <C>             <C>        
QUARTER ENDED
  1997
March 31           $185,318       $ 21,395       $  6,916        $  6,216        $      0.46
June 30             137,195         13,068           (994)         (1,693)             (0.13)
September 30        159,728         23,741         12,568          11,868               0.87
December 31         166,533         18,793         11,016          10,315               0.76
---------------------------------------------------------------------------------------------
  1996
March 31           $187,305       $ 22,018       $ 14,555        $ 13,799        $      1.01
June 30             152,253         17,464          6,320           5,563               0.41
September 30        160,528         26,826         18,676          17,921               1.31
December 31         154,803         16,336          6,752           5,996               0.44
---------------------------------------------------------------------------------------------
</TABLE>

         Quarterly results reflect the seasonal effect of electric and gas sales
as well as the results of the NORSTAR discontinued operations.

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. (a New York Corporation) and Subsidiaries as of
December 31, 1997 and 1996, 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, 1997. 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, 1997 and 1996,
and the consolidated results of their operations and their cash flows for the
three years ended December 31, 1997, in conformity with generally accepted
accounting principles.

/s/ ARTHUR ANDERSEN LLP

New York, New York
February 5, 1998


30
<PAGE>   22
Orange and Rockland Utilities, Inc. and Subsidiaries

OPERATING STATISTICS

<TABLE>
<CAPTION>
                                                                            Year Ended December 31,
                                                      1997            1996           1995              1994             1993
-------------------------------------------------------------------------------------------------------------------------------
<S>                                               <C>             <C>             <C>              <C>              <C>        
ELECTRIC:
SALES (Mwh):
   Residential                                      1,791,676       1,731,105       1,685,110        1,660,755        1,611,602
   Commercial                                       1,959,862       2,044,759       2,056,185        2,049,265        2,018,240
   Industrial                                         839,851         748,484         680,678          657,142          627,944
   Public Street Lighting                              26,899          29,522          28,107           27,836           27,705
   Public Authorities                                  73,647          51,392          75,506           68,972           72,037
-------------------------------------------------------------------------------------------------------------------------------
     Total Sales to Customers                       4,691,935       4,605,262       4,525,586        4,463,970        4,357,528
   Other Utilities for Resale                         305,445         190,394         118,730          265,311          234,751
-------------------------------------------------------------------------------------------------------------------------------
     Total Sales of Electricity                     4,997,380       4,795,656       4,644,316        4,729,281        4,592,279
-------------------------------------------------------------------------------------------------------------------------------
REVENUES (000's):
   Residential                                    $   218,974     $   209,706     $   208,862      $   214,439      $   211,082
   Commercial                                         194,102         200,281         204,240          212,214          212,240
   Industrial                                          44,936          46,663          50,205           51,316           50,983
   Public Street Lighting                               5,040           4,903           4,930            4,939            4,967
   Public Authorities                                   2,754           3,453           4,257            4,051            4,344
-------------------------------------------------------------------------------------------------------------------------------
     Total Revenues from Sales to Customers           465,806         465,006         472,494          486,959          483,616
   Other Utilities for Resale                           7,109           3,106           2,150            6,636            6,414
-------------------------------------------------------------------------------------------------------------------------------
     Total Revenues from Sales of Electricity         472,915         468,112         474,644          493,595          490,030
   Other Electric Operating Revenues                    6,558           8,930         (14,661)         (14,566)          (3,063)
-------------------------------------------------------------------------------------------------------------------------------
     Total Electric Operating Revenues            $   479,473     $   477,042     $   459,983      $   479,029      $   486,967
-------------------------------------------------------------------------------------------------------------------------------

GAS:
SALES (Mmcf):
   Residential                                         14,997          15,685          14,759           15,164           15,323
   Commercial and Industrial                            5,324           5,233           5,066            5,257            5,233
-------------------------------------------------------------------------------------------------------------------------------
     Total Firm Sales                                  20,321          20,918          19,825           20,421           20,556
   Interruptible                                        3,527           3,996           2,327            1,023              653
   Other Utilities for Resale                               3               4               4               27                8
-------------------------------------------------------------------------------------------------------------------------------
     Total Sales of Gas                                23,851          24,918          22,156           21,471           21,217
-------------------------------------------------------------------------------------------------------------------------------
REVENUES (000's):
   Residential                                    $   115,335     $   116,981     $    96,737      $   112,759      $   113,116
   Commercial and Industrial                           34,771          36,954          31,226           36,676           36,707
-------------------------------------------------------------------------------------------------------------------------------
     Total Revenues from Firm Sales                   150,106         153,935         127,963          149,435          149,823
   Interruptible                                       13,915          15,101           6,725            3,996            2,605
   Other Utilities for Resale                              75              94              59              203              105
-------------------------------------------------------------------------------------------------------------------------------
     Total Revenues from Sales of Gas                 164,096         169,130         134,747          153,634          152,533
   Other Gas Revenues                                   4,354           7,312           5,477            3,534            4,724
-------------------------------------------------------------------------------------------------------------------------------
     Total Gas Operating Revenues                 $   168,450     $   176,442     $   140,224      $   157,168      $   157,257
-------------------------------------------------------------------------------------------------------------------------------
</TABLE>


                                                                              31
<PAGE>   23
Orange and Rockland Utilities, Inc. and Subsidiaries

FINANCIAL STATISTICS

<TABLE>
<CAPTION>
                                                                               Year Ended December 31,
                                                         1997             1996            1995           1994            1993
-------------------------------------------------------------------------------------------------------------------------------
<S>                                                  <C>              <C>              <C>            <C>            <C>       
COMMON STOCK DATA:
   Earnings Per Average Common Share:
     Continuing Operations                           $      3.09      $      3.30      $     2.54     $     2.45     $     3.02
     Discontinued Operations                         $     (1.13)     $     (0.13)     $     0.06     $     0.05     $     0.04
-------------------------------------------------------------------------------------------------------------------------------
   Consolidated Earnings Per Average Common Share    $      1.96      $      3.17      $     2.60     $     2.50     $     3.06
-------------------------------------------------------------------------------------------------------------------------------
   Dividends Declared Per Share                      $      2.58      $      2.58      $     2.57     $     2.54     $     2.49
   Book Value Per Share (Year End)                   $     27.69      $     28.41      $    27.82     $    27.79     $    27.79
   Market Price Range Per Share:
     High                                                $48 5/8          $37 1/8         $37 3/8        $41 1/4        $47 1/2
     Low                                                 $30 1/8          $33 3/8         $30 7/8        $28 3/8        $38 5/8
     Year End                                           $46 9/16          $35 7/8         $35 3/4        $32 1/2        $40 5/8
   Price Earnings Ratio                                    23.76            11.32           13.75          13.00          13.28
   Dividend Payout Ratio                                  131.63%           81.39%          98.85%        101.60%         81.37%
   Common Shareholders at Year End                        19,682           21,322          22,916         23,299         24,328
   Average Number of Common Shares
     Outstanding (000's)                                  13,649           13,654          13,653         13,594         13,532
   Total Common Shares Outstanding
     at Year End (000's)                                  13,589           13,654          13,654         13,653         13,532
   Return on Average Common Equity                          7.09%           11.33%           9.35%          9.01%         11.16%
-------------------------------------------------------------------------------------------------------------------------------
CAPITALIZATION DATA (000's):
   Common Stock Equity                               $   376,319      $   387,850      $  379,776     $  379,403     $  376,044
   Non-Redeemable Preferred and Preference Stock          43,223           43,241          43,253         43,268         43,287
   Redeemable Preferred Stock                                  0                0           1,390          2,774          4,158
   Long-Term Debt (includes current portion)             356,676          359,825         359,928        379,014        381,248
-------------------------------------------------------------------------------------------------------------------------------
     Total Capitalization                            $   776,218      $   790,916      $  784,347     $  804,459     $  804,737
-------------------------------------------------------------------------------------------------------------------------------
CAPITALIZATION RATIOS:
   Common Stock Equity                                     48.48%           49.04%          48.42%         47.16%         46.73%
   Non-Redeemable Preferred and Preference Stock            5.57%            5.47%           5.51%          5.38%          5.38%
   Redeemable Preferred Stock                               0.00%            0.00%           0.18%          0.35%          0.52%
   Long-Term Debt (includes current portion)               45.95%           45.49%          45.89%         47.11%         47.37%
-------------------------------------------------------------------------------------------------------------------------------
SELECTED FINANCIAL DATA  (000's):
   Operating Revenues                                $   648,774      $   654,889      $  602,310     $  638,404     $  645,640
   Operating Expenses                                $   571,777      $   572,245      $  526,741     $  562,810     $  563,066
   Operating Income                                  $    76,997      $    82,644      $   75,569     $   75,594     $   82,574
   Net Income                                        $    29,506      $    46,303      $   38,573     $   37,217     $   44,815
   Earnings Applicable to Common Stock               $    26,706      $    43,279      $   35,438     $   33,966     $   41,451
   Net Utility Plant                                 $   936,213      $   899,643      $  873,668     $  856,289     $  831,980
   Total Assets                                      $ 1,288,009      $ 1,266,132      $1,251,541     $1,230,726     $1,225,627
   Long-Term Debt Including
     Redeemable Preferred Stock                      $   356,676      $   359,825      $  361,318     $  381,788     $  385,406
   Ratio of Long-Term Debt to Net Plant                     38.1%            40.0%           41.2%          44.3%          46.0%
   Ratio of Accumulated Depreciation to
     Utility Plant in Service                               35.1%            33.8%           33.3%          33.1%          31.7%
-------------------------------------------------------------------------------------------------------------------------------
</TABLE>

<TABLE>
<CAPTION>
CREDIT RATINGS                      Duff & Phelps      Moody's          Standard &
                                    Credit Rating     Investors           Poor's
                                       Company         Service             Corp.
----------------------------------------------------------------------------------
<S>                                 <C>               <C>               <C>
Commercial paper                    D-1 -              P-2               A-2
Pollution control bonds               A -               A3               A -
Unsecured debt                        A -               A3               A -
Preferred debt                       BBB+             baa1              BBB+
----------------------------------------------------------------------------------
</TABLE>


32