<PAGE>   1
                                                                    EXHIBIT 99.3

                                STATE OF NEW YORK
                            PUBLIC SERVICE COMMISSION

                                OPINION NO. 97-20

CASE 96-E-0900 -  In the Matter of Orange and Rockland Utilities, Inc.'s Plans
                  for Electric Rate/Restructuring Pursuant to Opinion No. 96-12.

                 OPINION AND ORDER ADOPTING TERMS OF SETTLEMENT

Issued and Effective:  December 31, 1997

APPEARANCES

INTRODUCTION                                                  1

PROCEDURAL HISTORY                                            2

SETTLEMENT                                                    5

PUBLIC INPUT                                                  6
<PAGE>   2
STANDARD TO TEST A PROPOSED SETTLEMENT                        7

PRINCIPAL ISSUES                                              8

  Corporate Structure                                         8

  Discussion                                                 11

  Strandable Costs and the CTC                               12

  Discussion                                                 15

OTHER ISSUES                                                 16

  Transition Rate Design                                     16

  Discussion                                                 17

  Return on Equity and Revenue Sharing                       18

  Discussion                                                 19

  Systems Benefit Charge                                     19

  Discussion                                                 20

  Revenue Allocation                                         21

  Discussion                                                 21

  Retail Wheeling to Residential Customers                   22

  Discussion                                                 23

  Price Cap Plus Regulation                                  23

  Sources of Funds for Rate Decrease                         24

  Deferrals                                                  25

  Consumer Outreach and Education                            25

MISCELLANEOUS                                                26

FINDINGS UNDER THE STATE ENVIRONMENTAL

 QUALITY REVIEW ACT                                          28

DISCUSSION AND RECOMMENDATION                                30

ORDER                                                        31

APPENDIX

FOR DEPARTMENT OF PUBLIC SERVICE STAFF:

         Robert Garlin & Saul Rigberg, Staff Counsel, Three Empire State Plaza,
         Albany, New York 12223.

FOR ORANGE & ROCKLAND UTILITIES, INC.:

         G. D. Caliendo, Senior Vice-President and General Counsel (by John L.
         Carley, Senior Attorney).

         Nixon, Hargrave, Devans & Doyle (by Andrew Gansberg, Esq.), One Key
         Corp Plaza, Albany, New York 12207.
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FOR NEW YORK STATE ELECTRIC & GAS CORPORATION:

         Huber, Lawrence & Abell (by William D. Booth, Attorney), 605 Third
         Avenue, New York, New York 10158.

FOR CONSOLIDATED EDISON COMPANY OF NEW YORK, INC.:

         James F. Gallagher, Attorney, 4 Irving Place, Room 1815-5, New York,
         New York 10003.

FOR INDUSTRIAL ENERGY USERS ASSOCIATION:

         Birbrower, Montalbano, Condon & Frank, P.C. (by Thomas A. Condon,
         Attorney), 67 North Main Street, New City, New York 10956.

FOR NEW YORK STATE POWER AUTHORITY:

         Eric J. Schmaler, Attorney, 1633 Broadway, New York, New York 10019.

FOR NEW YORK STATE DEPARTMENT OF ECONOMIC DEVELOPMENT:

         Gloria Kavanah, Assistant Counsel, One Commerce Plaza, Albany, New York
         12245.

FOR NEW YORK STATE CONSUMER PROTECTION BOARD:

         Timothy S. Carey, Executive Director, Ann Kutter, Deputy Director (by
         James F. Warden, Jr., Intervenor Attorney), 5 Empire State Plaza,
         Albany, New York 12210.

FOR PUBLIC INTEREST INTERVENORS:

         Melanie Pien, Counsel, Mollie Lampi, Attorney-at-Law, 122 Swan Street,
         Albany, New York 12210.

FOR PUBLIC UTILITY LAW PROJECT OF NEW YORK, INC.:

         Ben Wiles, Esq., 90 State Street, Albany, New York 12207.

FOR INDEPENDENT POWER PRODUCERS OF NEW YORK, INC., AND ENRON CAPITAL & TRADE
 RESOURCES:

         Read & Laniado (by Craig M. Indyke, Esq., Sam Laniado, Esq.), 25 Eagle
         Street, Albany, New York 12207.

FOR WHEELED ELECTRIC POWER COMPANY:

         Joel Blau, Esq., 32 Windsor Court, Delmar, New York 12054.

FOR NEW ENERGY VENTURES, INC., AND ENTEK POWER SERVICES, INC:

         Cohen, Dax & Koenig, P.C. (by Jeffrey C. Cohen and Richard B. Miller),
         90 State Street, Albany, New York 12207.

FOR THE DEPARTMENT OF LAW:

         Dennis Vacco, Attorney General (by Richard W. Golden, Assistant
         Attorney General), 120 Broadway, New York, New York 10271.

FOR THE RETAIL COUNCIL OF NEW YORK:
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         Cohen, Dax and Koenig, P.C. (by Paul C. Rapp), 90 State Street, Albany,
         New York 12207.

FOR THE NATIONAL ASSOCIATION OF ENERGY COMPANIES AND JOINT
SUPPORTERS:

         Ruben S. Brown, M.A.L.D., 201 West 70th, Suite 41E, New York, New York
         10023.

                                STATE OF NEW YORK
                            PUBLIC SERVICE COMMISSION

COMMISSIONERS:

  John F. O'Mara, Chairman
  Maureen O. Helmer
  Thomas J. Dunleavy

CASE 96-E-0900 -In the Matter of Orange and Rockland Utilities,
                Inc.'s Plans for Electric Rate/Restructuring
                Pursuant to Opinion No. 96-12.

                                OPINION NO. 97-20

                 OPINION AND ORDER ADOPTING TERMS OF SETTLEMENT

                    (Issued and Effective December 31, 1997)

BY THE COMMISSION:

                                  INTRODUCTION

          On November 26, 1997, we issued an abbreviated order adopting the
terms of a revised Settlement Agreement (Settlement) filed November 6, 1997, by
nine parties to this proceeding. We found that the Settlement, which addresses
the electric rates/corporate restructuring of Orange and Rockland Utilities,
Inc. (O&R or the company) offers a sound regulatory framework and will produce
significant customer benefits. In addition to accomplishing the divestiture of
generation, the Settlement will produce an average electricity price of 6 kWh
for large industrial customers, with rates for all other customers reduced in
the first rate year 1.09% and another 1% effective one year later. These
reductions are in addition to average rate reductions of 4% over the past two
years. Further, the latter group of customers may receive additional rate
reductions in the event O&R realizes a significant gain when it divests its
electric generating facilities. In our November 6 order we committed to issue a
more comprehensive opinion and order describing the bases for our decision and
containing the final Environmental Assessment Form (EAF). This document
satisfies our commitment and its issuance begins the period for filing petitions
for rehearing or court review.

                               PROCEDURAL HISTORY

          This proceeding's complete procedural history is presented in Judge
Boschwitz' recommended decision issued July 2, 1997. In brief, in response to
our expectations set forth in Cases 94-E-0952 et al., the terms of a proposed
electric rate/restructuring plan (Plan) were filed by O&R, Staff, and several
other sponsors on March 25, 1997. Thereafter, following educational forums,
public statement hearings, and evidentiary hearings (on May 19, 20, and 22,
1997), and the 
<PAGE>   5

submission of pre- and post-hearing briefs, and replies, Judge Boschwitz
recommended that the Plan be returned to the parties for modification.

          In his recommended decision, Judge Boschwitz commented favorably on
the fact that, among other things, the Plan would:

          (1)       Reduce the average "opportunity" price for 26 large
                    industrial customers from 6.82/kWh to 6.0/kWh;

          (2)       Reduce rates for all other customers by 1.09% in the first
                    year and by 2.1% cumulatively for the following three years;

          (3)       Establish Standards of Competitive Conduct and Guidelines to
                    preclude inter-corporate abuses; and

          (4)       Institute full retail access by May 1999;

          However, he found that a number of provisions were unfavorable to
ratepayers and potential competitors of O&R, and he concluded that the
unfavorable aspects of the Plan outweighed the favorable ones. Among the aspects
of the Plan the Judge questioned are the following:

          (1)       O&R was not required to divest its unregulated operations;

          (2)       The revenue sharing trigger was increased from 10.9% to
                    11.5%, despite the favorable offsetting operation of the
                    competitive transition charge (CTC);

          (3)       The operation of the CTC tended to be anti-competitive and,
                    moreover, lacked sufficient incentive to promote a greater
                    emphasis on strandable cost mitigation; and

          (4)       The CTC provided for the recovery of non-variable O&M
                    expenses, which should have been recovered in sales.

          Judge Boschwitz concluded in summary that,

         the proponents' assertion that the . . . [Plan] complies with the
         dictates of the Commission, as set forth in Opinion No. 96-12, falls
         far short of the mark. In that Opinion, the Commission articulated
         unequivocally its expectation that the electric utility industry would
         produce more innovative rate designs, improve productivity, increase
         revenues and mitigate stranded costs, thereby resulting in lower
         electric rates and increased economic development and growth. After
         reciting these objectives, the Commission stated '[T]he utility filings
         we are directing are expected to reflect these trends.' But the [Plan]
         aside from meeting the mandate of unbundled rates, does not reflect an
         innovative rate design, nor is it likely to achieve more than token
         mitigation of stranded costs, to the extent they exist, since this
         result appears to be largely dependent on O&R earning a return on its
         common equity in excess of 11.5%."

He thus recommended that the parties modify the Plan.
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          Exceptions to the recommended decision were filed on July 24, 1997, by
Staff, O&R, DED, IEUA, Independent Power Producers of New York, Inc. and ENRON
Capital and Trade Resources, jointly (IPPNY/ENRON), 15 groups denominated as
Public Interest Intervenors (PII), the Consumer Protection Board (CPB), the New
York Power Authority (NYPA), Wheeled Electric Power Company (WEPCO), Public
Utility Law Project of New York, Inc. (PULP), the Retail Council of New York
(Retail Council), and New York State Electric & Gas Corporation (NYSEG). Replies
to exceptions were filed on August 18, 1997 by Staff, O&R, IPPNY/ENRON, PII,
CPB, WEPCO, and PULP.

          At our session of September 10, 1997, we reviewed the record, the
recommended decision and the exceptions thereto. We concluded that O&R's
generation assets should be auctioned as soon as possible, that incentives
should be developed to encourage that outcome, that the allocation of risks
between ratepayers and shareholders was skewed in favor of shareholders during
the term of the Plan, and that the term of the CTC should be shortened from four
years. Accordingly, we returned the Plan to the parties for restructuring and
modification. They, in turn, responded by filing a revised Settlement on
November 6, 1997.

          Comments supporting the Settlement were filed on November 14, 1997 by
O&R, Staff, DED and IPPNY/ENRON. Comments in opposition were filed by CPB, DOL,
PULP, and Retail Council. At our session on November 25, 1997, we approved the
Settlement. However, based on comments received at a public statement hearing
held in New City on November 19, 1997, (see below), we offered O&R the
opportunity to elect an alternative resolution to one aspect of the Settlement.

          After describing the salient aspects of the Settlement, we shall
address the issues as developed by Judge Boschwitz with emphasis on the
Settlement and the comments thereon.

                                   SETTLEMENT

          The Settlement spans four years starting on the effective date of the
proposed rates. It provides large industrial customers the opportunity to
realize an average electric price of 6/kWh. The rates for all other customers
will be reduced in the first year by 1.09% and by another 1.0% one year later.
In the event O&R realizes a gain on the projected divestiture of its generation
assets, the customers' share of the gain will accrue first to the latter group
of "all other customers," up to the equivalent of a 5.0% rate reduction.

          The Settlement provides that within one month after its approval, O&R
will file proposed unbundled electric rates. On May 1, 1998, the opportunity to
choose alternative electric energy suppliers will be offered to all customers
and full retail access to a competitive energy and capacity market will become
available on May 1, 1999. The Settlement further provides that "[u]ntil the
wholesale energy market becomes effective and/or full retail access is
implemented, energy costs will continue to be charged through the existing FAC
and the fixed cost of O&R's generation and purchased power will continue to be
recovered through the base rates approved as part of the [Settlement]. When
wholesale competition is implemented, the FAC will reflect energy purchases at
market price made by the regulated delivery function on behalf of its
customers."

          It is intended that O&R continue as the provider of last resort;
however, the parties have agreed to study whether transferral of this obligation
to the market is in the public interest and will present their recommendations
to us by May 1, 1999. With respect to metering, O&R will submit a proposal to us
by March 1, 1999 providing for competitive metering services. Competitors will
also be permitted to provide billing services.

          A Low-Income Customer Assistance Program costing about $400,000 will
be conducted for a four-year period for approximately 400 customers in the City
of Port Jervis. The 
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Program will address energy efficiency, payment patterns, and/or arrears
forgiveness. Energy efficiency measures, including refrigerator replacement,
will be the first priority of this program.

          Finally, the Settlement provides for recovery by O&R of prudent and
verifiable costs, subject to certain restrictions, totalling $7.5 million for
retraining, outplacement, severance, early retirement, and employee retention
programs for employees, other than officers, affected by the divestiture
proposal.

          Other significant contested aspects of the Settlement are addressed
below.

                                  PUBLIC INPUT

          Public input on the Plan was provided through informal comments at six
educational forums held prior to public statement hearings, at those hearings,
and through letters, telephone calls to the Commission's opinion lines, and
comments on the Commission's home page on the World Wide Web.

          The following views were prevalent: emission profiles of the power
producers should be made public; the sources of the power should be identified
in order for consumers to make informed choices; rate reductions for
residential, small commercial businesses, and industry should be equitable;
restructuring should focus on bills that customers receive instead of their
rates; some regulatory oversight of marketers should remain; and the proposed
low-income program addresses insufficiently the needs of low-income citizens.

          In response to anticipated interest in the Settlement filed November
6, 1997, a further public statement hearing was conducted, as noted, in New City
on November 19, 1997, at which about 100 persons were in attendance. The
speakers contended that O&R should not retain a share of a potential tax refund,
that the rate allocation plan remained unfair, that divestiture should not be
required, but that if it were, O&R should not be precluded from participating in
any auction of its generating assets. We address those points relating to this
proceeding in detail below.

                     STANDARD TO TEST A PROPOSED SETTLEMENT

          The recommended decision addressed arguments that the absence of a
full litigation record precluded evaluation of the Plan. Judge Boschwitz
concluded that while the absence of a full litigation record complicated that
evaluation, the nature of the issues here and the fact that many issues were
resolved by the parties permitted an evaluation on the merits.

          NYSEG excepts, arguing that the wrong test was used to evaluate the
reasonableness of the Plan, because O&R did not file a rate/restructuring
proposal voluntarily, and did so only to comply with the requirements of Opinion
No. 96-12. Thus, NYSEG contends that the Plan should have been evaluated in the
context of that opinion and should take into account other rate/restructuring
proposals, including NYSEG's.

          Our Settlement Guidelines establish the following standards, which we
have followed herein, for assessing a proposed settlement in light of our
obligation to set just and reasonable rates and a utility's burden, under the
Public Service Law, of showing the reasonableness of a rate change it is
proposing:

          a.        A desirable settlement should strive for a balance among (1)
                    protection of the ratepayers, (2) fairness to investors, and
                    (3) the long term viability of the utility; should be
                    consistent with sound environmental, social, and economic
                    policies of the Agency and the State; and should produce
                    results that were within the range of reasonable results
                    that
<PAGE>   8

                    would likely have arisen from a Commission decision in a
                    litigated proceeding.

          b.        In judging a settlement, the Commission shall give weight to
                    the fact that a settlement reflects agreement by normally
                    adversarial parties.

Those guidelines will serve as the basis of our decision and, accordingly,
NYSEG's exception is denied.

                                PRINCIPAL ISSUES

Corporate Structure

          The corporate structure contemplated in the Plan would have resulted
in three or more structurally separate units, i.e., a generating company
(GENCO), a regulated transmission and distribution (T&D) company, and one or
more energy service companies (ESCOs). O&R's interest in its generating
facilities, exclusive of its hydro and gas turbine facilities, would be
transferred to a separate affiliate (the GENCO), if it was willing to pay full
market price.

          The T&D company would provide basic energy services, although other
companies, including O&R's ESCO(s), could provide metering and billing services
to T&D customers. The GENCO would be precluded, except in special circumstances,
from entering into bilateral contracts with the T&D company. Finally, O&R's
ESCO(s) would be authorized to operate in the T&D's franchise territory and to
trade on O&R's name and reputation, without payment of a royalty, as long as
there was adherence to specified standards of conduct.

          The recommended decision criticized the corporate structure, but did
not recommend divestiture of O&R's generation assets because the company cannot
exercise horizontal market power and because, as O&R argued, the corporate
structure was integral to the Plan. In addition, the recommended decision did
not advocate divestiture of O&R's ESCO, nor would the recommended decision have
limited the ESCO's operation, as WEPCO proposed, until competitor ESCOs had
gained a significant foothold in O&R's service territory. However, in view of
these facts, and the fact that O&R's ESCO intended to trade on the company's
name and reputation, the recommended decision proposed the imposition of a
royalty of at least $2 million annually, which would continue until at least 20%
of the customers in O&R's service territory were served by competitor ESCOs.

          Staff, O&R, and WEPCO excepted. WEPCO acknowledged that a royalty
would compensate ratepayers for the proposed corporate structure, but argued
that it would be insufficient to assure the development of robust competition.
Moreover, WEPCO maintained that a royalty would be inadequate to offset "the
unique advantage that the affiliated ESCO would enjoy in the local market." At a
minimum, WEPCO contended, in addition to a royalty, the ESCO(s) should be
precluded from using the company's name in marketing endeavors, and also should
be precluded from marketing in O&R's service territory until at least 20% of the
company's customers were served by competitor ESCOs.

          Staff replied that consideration of a royalty should be deferred until
the company applied for authorization to restructure itself. Similarly, O&R
would defer consideration of a royalty until after the ESCO(s) actually traded
on O&R's name and began transacting business.

          As noted, at our September 10, 1997, session we did not endorse the
corporate structure advocated in the Plan. Consequently, in lieu of structural
separation, O&R has acceded in the Settlement to commencement immediately of
full divestiture by auction of all of its electric generating assets, including
its hydro-electric facilities and gas turbines. The company 
<PAGE>   9
agreed to submit its divestiture plan to Staff and the other parties in this
proceeding for comment within three months of our approval of the Settlement.
The divestiture proposal was to, and did, identify how the generating assets
will be packaged for sale; what restrictions, if any, will be placed on the
capacity that any one bidder may purchase; the procedures to be followed in the
sale of the generating assets, including minimum bids; and key dates and
milestones to achieve the scheduled divestiture.

          If a winning bidder is selected prior to May 1, 1999, any gain shall
be allocated between shareholders and customers on a 25%/75% basis, and any loss
on a 5%/95% basis. If a winning bidder is selected thereafter, gains and losses
shall be allocated between shareholders and customers on a 20%/80% basis. The
gain, if any, allocable to shareholders will be capped at $20 million. Further,
neither the company nor any of its affiliates are to participate in the auction.
Finally, the company will not be allowed to own generation in its service
territory or adjoining ones for ten years.

          CPB endorses the proposed corporate structure, but objects to the
incentive scheme associated with the divestiture of generation assets,
contending that it favors the company at ratepayers' expense. In addition, in an
effort to achieve symmetry, CPB proposes that potential ratepayer losses
associated with divestiture be capped at $10 million.

          With regard to the T&D company and the ESCO(s), the terms and
conditions of their operation are not changed from the Plan. However, the
Settlement provides that to the extent a royalty may be warranted, it is
subsumed in the rate levels provided for.

          At the public statement hearing held November 19, 1997, there were
objections to a provision of the Settlement that would preclude O&R from bidding
in the auction. The speakers focused primarily on the impact divestiture would
have on O&R's employees, though concern was also expressed about the impact
divestiture would have on the tax base of municipalities in which generation
facilities are located.

Discussion

          In Opinion No. 97-16 we stated that "[D]ivestiture of generation is
essential in the movement to competition, in order to avoid undue concentration
of market power and the use of monopoly power on the distribution side.
Divestiture of assets through an auction has the potential to result in a
dynamic and aggressive generation market, and also has the advantage of
establishing a clear market value for generating assets."

          As we indicated in Opinion No. 96-12, divestiture of generation and
energy services is a clear way to allay concerns about vertical market power and
avoid anti-competitive behavior (such as cross-subsidies among affiliates in
both competitive and monopoly environments, and favored treatment of
affiliates). Also, divestiture may foster creation of a larger number of
competing generating companies and ESCOs, which can result in a dynamic and
aggressive market. Thus, O&R's agreement to divestiture in the Settlement
furthers our policies.

          The proposed mechanism for sharing gains and losses is intended to
provide an incentive for O&R to divest its generating assets prior to the time
full retail access is available in its service territory. That policy goal
warrants a slightly disproportionate allocation of incentives between ratepayers
and shareholders, since it encourages O&R to divest its generation assets prior
to May 1, 1999, and thereby helps avoid the institution of the CTC. As for
capping ratepayer losses, these are considered unlikely, and it is undesirable
to potentially upset the Settlement by modifying this feature.

          With regard to the provision prohibiting O&R's participation in the
auction, we stated in our November 26, 1997 order that since O&R does not
possess horizontal market power, and the public interest may be enhanced by
giving O&R an option 
<PAGE>   10
to bid in the auction of its generating assets, O&R could elect to do so,
subject to conditions. By letter dated December 10, 1997, O&R advised that it
would not participate in the auction.

          Regarding a royalty, we are satisfied that the concessions made by O&R
in the Settlement adequately compensate ratepayers for the fact that no explicit
provision has been made for a royalty, but are subsumed in the rate and
restructuring proposal, and contrary to Judge Boschwitz' recommendation, no
additional, explicit royalty will be required. However, we agree with Judge
Boschwitz that, with the safeguards provided by the Settlement, it is
unnecessary to limit the operation of O&R's ESCO(s) until competitor ESCOs have
secured a significant market share. By not fettering O&R with specific market
share thresholds, there is a greater likelihood that competitor ESCOs will not
delay their entry and will offer increased advantages to consumers in order to
secure a foothold in the company's service territory. Were O&R to be restrained
in the initial stages of competitive electric markets, we fear that some of the
advantages associated with deregulation would not be realized.

Strandable Costs and the CTC

          The Plan provided O&R, during the transition period, an opportunity to
recover its above-market generation costs through a wires charge (the CTC), to
be effective May 1, 1999 and to operate for four years. Also, O&R was to be
afforded an opportunity to recover its strandable assets including (1) assets
established in accordance with prior Commission orders, policies or practices
(regulatory assets), (2) net NUG purchased power costs (which are minimal and
will be reconciled and passed through annually until they expire in 2008), (3)
other depreciable assets related to metering and billing, and (4) above-market
generation costs.

          The above-market generation costs, which comprised the vast majority
of the projected strandable assets, were defined as the difference between the
embedded fixed costs of generation, and the revenues net of fuel and variable
O&M expenses, derived from the operation of O&R's fossil fuel (Bowline and
Lovett) plants. Any difference, within a band of + 10% around O&R's generation
costs (which costs are to be determined in the forthcoming unbundling
proceeding, based on a 1996 cost of service study), was to be reflected in the
CTC and was to be borne, or avoided, solely by ratepayers. Any additional
difference was to be shared by O&R and all of its customers on a 10%/90% basis,
with the customer share being incorporated into the CTC.

          These above-market costs, which are now recovered in base rates, were
to be recovered beginning with the onset of full retail access and included
"fixed" production costs plus allocable administrative and general costs.
Increases in these costs over 1996 actual levels would not be recovered via the
CTC, nor would increased costs associated with capital additions or changes in
the cost of capital applicable to production costs.

          Upon expiration of the CTC, the fossil fuel-fired generation assets
were to be subject to a one-time valuation pursuant to a procedure to be
established by Staff and O&R, or, if they were unable to agree on a procedure,
by us. Net gains, or losses, resulting from the valuation of these assets would
be shared by shareholders and ratepayers on a 20%/80% basis.

          The recommended decision agreed conceptually with O&R's recovery of
its strandable costs at the expiration of the four-year transition period. In
addition, the recommended decision agreed that the final determination of the
amount of such strandable costs should occur near the end of the transition
period, as prescribed by the Plan. Those recommendations presumed that O&R over
time would be able to sell increasing amounts of energy from both its Lovett and
Bowline plants and, therefore, would likely have "positive" strandable costs.

          On the other hand, the recommended decision was highly 
<PAGE>   11
critical of the CTC, which was found to be (1) anti-competitive, because it
provided for the recovery of non-variable going forward costs during the
transition, and (2) adverse to ratepayers, since its operation would tend to
deprive them of the benefits of competition by offsetting, in part, the rate
reductions promised by the Plan. Nevertheless, because relevant accounting
standards require firms in competitive environments to "write down"
non-productive assets, the recommended decision made provision for accrual of
the CTC on O&R's books, with deferral of its recovery until the end of the
transition period, to permit O&R to set off any accruals against a possible gain
on the disposition of generation assets.

          Staff, O&R, and CPB excepted. CPB advocated an immediate appraisal of
O&R's strandable costs, which it believes is in the range of $260-$384 million,
and an immediate write-off of $124 million of such costs, thereby achieving a 5%
rate reduction.

          O&R and Staff contended that the CTC is a reasonable and measured
approach to assure substantial recovery of costs that were not avoidable during
the transition to competition and could not be recouped in the marketplace. O&R
also argued that a period of cost recovery was necessary to permit O&R's
generation plants to become more competitive.

          At our September 10, 1997 session, we concluded that the term of the
CTC should be shortened and its sharing mechanism should be made more equitable.
As revised, in the November 6 Settlement, the CTC will again become operative
May 1, 1999, but only in the event O&R is unable, prior thereto, to auction its
generating assets, or if O&R is delayed in transferring title. However, there is
no provision for a null band, and 25% of fixed production labor expenses and
property taxes would be at risk in the competitive market. If title does not
transfer by May 1, 2000, 35% of those costs would be exposed to the market for
recovery. If title does not pass by October 31, 2000, the CTC would expire, and
O&R would be required to obtain our approval to continue a version of it until
the generating assets were transferred.

          CPB concedes that the Settlement substantially minimizes the impact of
the CTC. However, CPB argues that a CTC should be implemented only if there is a
6% overall rate reduction. Otherwise, asserts CPB, there should be no provision
for the recovery of stranded costs.

Discussion

          In Opinion No. 96-12 we stated that we were prepared to permit
recovery of strandable costs but expected a balancing of ratepayer and
shareholder interests. We also indicated that, in addition to achieving rate
reductions, a key goal was the development of a robust competitive market. And
divestiture was strongly encouraged. The Settlement accomplishes these
objectives and the company's commitment to divest its generation assets will
mitigate stranded costs, if any. The company's commitment to divestiture is
supported by the relatively limited term of the CTC, the elimination of the null
band, and the provision for certain "going forward" costs to be at risk in the
event the CTC becomes operative. This aspect of the Settlement is reasonable and
will serve to encourage early divestiture.

          Additionally, we anticipate the CTC as revised will generate less
revenue than under the Plan, even if the CTC operates for the maximum 18-month
period. This outcome is likely to result in a savings to ratepayers,
particularly if, as we expect, they are able to purchase energy more cheaply
than otherwise, and represents the equivalent of a rate reduction, which could
easily approximate or exceed that which CPB seeks. Accordingly, we are satisfied
that the CTC mechanism and the overall rate reduction are reasonable and in the
public interest.

                                  OTHER ISSUES
<PAGE>   12
Transition Rate Design

          The Settlement, like the Plan, contemplates minimal rate design
changes pending the resolution of the unbundling phase of this proceeding.
Specifically, O&R will phase out its mandatory time-of-use (TOU) residential
rates for existing customers and will no longer add mandatory TOU residential
customers. However, O&R will continue the TOU rate for those customers who elect
to be served under it voluntarily. Also, O&R will eliminate the mandatory nature
of its peak activated rate (PAR) for SC-9 and large industrial customers,
prospectively offering the PAR on an optional basis.

          The recommended decision supported a transition rate design proposed
by IPPNY/ENRON that would approximately halve the unit cost of electricity for
residential customers, while concurrently increasing the customer charge. The
recommended decision would base the new rate design on 12 months of consumption
thereby increasing bills, by comparison to prior periods, in off-peak months and
decreasing bills, on average, in the on-peak months.

          This transition rate design was endorsed because the Judge thought it
would promote consumption and reduce strandable costs, and because it would
generate additional annual revenues, some of which could be returned to
ratepayers.

          O&R, Staff, CPB, and PII excepted to the recommended rate design
change. Staff and O&R objected because they feared there would be customer
confusion and other adverse reactions. While Staff acknowledged the correctness
of the economic theory underlying the recommended rate design, it questioned
whether significant additional revenues would be generated. Staff concluded that
while the proposed rate design may be meritorious, its timing was inappropriate.

          O&R suggested we should defer the rate design issue to the unbundling
phase of the proceeding. Together with CPB, it viewed the administrative burden
of implementing the rate design as substantial. However, like Staff, O&R
acknowledged the merit of the rate design stating "in theory, for certain
customers, the transitional rate design should lead to higher sales levels which
should have a positive effect on stranded cost and may well increase customer
benefits under the sharing mechanism."

          In addition to its concerns about the administrative feasibility of
the recommended rate design, CPB stated that for minimum use and near minimum
use customers, it would violate the Commission's expressed desire to reduce
rates for all customers. But CPB conceded that "to the extent such promotional
rates are desired by consumers, the market will probably provide them in short
order."

          PII argued on exceptions that the recommended transitional rate design
sacrificed the environment for the economy and that its adoption was contrary to
Public Service Law 5(2), which, it stated, compelled the preservation of
environmental values and the conservation of natural resources.

Discussion

          We are satisfied that pending the outcome of the unbundling phase,
dramatic rate design changes of the type proposed by IPPNY/ENRON are
unwarranted. After we have had an opportunity to examine O&R's current cost of
service study, and analyze the potential cost and environmental impacts of such
a shift, we will be better able to determine whether such rate design changes
should be instituted by O&R in advance of the onset of full retail access and
unbundling, or whether it is better left to the market to implement comparable
rate designs once full retail access is implemented.

Return on Equity and Revenue Sharing

          The Plan is predicated on a 10.4% equity return, but increases the
revenue sharing trigger from 10.9% to 11.5%.

          The recommended decision found that (1) O&R's cost of 
<PAGE>   13
equity had not changed since the last rate decision for the company, and (2)
that O&R largely would be made whole whether or not it suffered a revenue
shortfall due to reduced sales, because the CTC would operate to offset the
shortfall. Also, the recommended decision concluded that the T&D company would
face less risk than utilities operating in a competitive environment. Thus,
Judge Boschwitz recommended the 10.9% revenue sharing trigger be maintained.

          O&R, Staff, and CPB excepted. O&R argued that it would be at risk for
inflationary increases in wages, property taxes and other expenses over the four
year term of the Plan. O&R also suggested that T&D companies its size would face
a greater level of risk in a deregulated environment. Staff contended that the
recommended decision underestimated the risks of T&D operations because the
company agreed "to lock in 1996 costs for such items as property taxes, labor,
cost of money, capital additions and operating expenses."

          CPB maintained that the cost of equity had declined to 10.2% and that
a revenue decrease of $4.14 million was warranted to reflect the difference
between that return and the reported earned return on equity of 11.35% for the
12 months ended June 30, 1997.

          At our session of September 10, we expressed reservations about the
level of the revenue sharing trigger, but indicated it might be acceptable if
other aspects of the Plan were modified.

          The Settlement sets the sharing trigger at 11.4%, 0.1% below the
Plan's threshold. O&R states that in view of the increased risks it has assumed,
no reduction is warranted; however, it goes on to explain that it agreed to this
modest reduction in "the interest of achieving consensus." CPB comments that
this modest reduction is inadequate. It continues to press for a 10.2% equity
return sharing trigger, arguing that beyond the justification previously offered
for its proposed adjustment, bond yields have declined about 55 basis points
since late summer and that equity costs, to the extent they tend to track bond
yields, are lower too.

Discussion

          Overall, the Settlement is significantly improved when compared to the
Plan and is likely to produce greater ratepayer benefits. In these
circumstances, we conclude that the revised sharing trigger need not be amended
further.

Systems Benefit Charge

          The recommended decision suggested the System Benefits Charge (SBC)
revenues should amount to $3.0 million annually, rather than the $4.2 million
allowed by the Commission in O&R's last electric rate case (Case 95-E-0491), or
the $4.5 million advocated by PII. However, the recommended decision stated that
O&R should be required to demonstrate that certain demand side management (DSM)
programs being eliminated were not cost effective.

          CPB, PII, and O&R excepted. CPB contended that the funding level
should approximate 1995 actual expenditures of $7.5 million and O&R should
absorb any cost increases. According to CPB, the rate case allowance of $4.2
million should not be considered a base, because it was the result of a
settlement and because the emphasis in the prior rate case was on lowering rates
instead of fostering competition.

          PII argued that a further reduction in the SBC fund would result
eventually in rate increases by reducing "the variety, flexibility, quality and
quantity of SBC funded programs thus reducing consumers' choices to lower their
bills . . . ." Moreover, argued PII, the rate effect of a reduction in the
annual SBC allowance, from $4.2 million to $3.0 million, was insignificant
compared to the long-term benefits of a vigorous SBC program.
<PAGE>   14
Discussion

          In Opinion No. 96-12, we expressed our interest that an SBC be
inaugurated during the transition to retail competition and that the level of
SBC funding equal approximately the level of current utility expenditures. We
subsequently established a general funding guideline of one mill per kWh in
other utility-specific proceedings.

          The recommended decision, based on O&R's brief, erroneously quantified
the Plan's SBC allowance at $3.0 million. The correct level is $3.3 million,
which equates to about one mill per kWh. As O&R has demonstrated to our
satisfaction that $1.0 million in DSM programs can properly be eliminated
because these programs are not cost effective, and as the SBC allowance in the
Settlement appears to be consistent with Opinion No. 96-12 and our current
guidelines, the exceptions are denied. 

Revenue Allocation

          The recommended decision endorsed in concept a revenue allocation
which favored certain large users. However, the recommended decision expressed
concern that the revenue allocation was founded solely on a comparison of O&R's
rates with national averages, and did not also compare the proposed rates to
O&R's cost of service. Accordingly, the Judge recommended that O&R be required
to file earlier than planned, and in advance of this decision, a new embedded
cost of service study.

          O&R and CPB excepted. The company argued that it was unfair to other
signatories for us to defer acting upon the Plan until we had examined the new
cost of service study. The company noted that previous cost of service studies
demonstrated that the customers receiving disproportionate rate decreases in
recent years consistently have subsidized residential customers. Finally, O&R
argued "[I]t makes sense to provide such benefits to those customers to whom the
economic attractiveness of continuing operations in O&R's service territory will
most likely be subject to continuing challenge." CPB, on the other hand,
advocated an across-the-board revenue decrease, which it continues to foster, in
concert with its 6% rate reduction.

Discussion

          Based on O&R's most recent cost of service study, the projected rate
of return for large users, even after considering the decrease, suggests that
the Settlement's allocation of the revenue decrease is reasonable with reference
to cost of service, especially considering our traditional + 15% tolerance
range. Moreover, the fact that industrial class rates are not competitive with
national averages further supports the Settlement's allocation. Were we to
endorse an across-the-board revenue decrease, it would generate a rate reduction
of only about 3% for all customers. In view of the fact that O&R's rates for
residential service have been reduced, on average, about 4% in the last several
years, we conclude that public policy is better served by the revised revenue
allocation, which is intended to stimulate economic growth in O&R's service
territory. It is important to note that the disparity in the respective rate
reductions may become minimal if O&R realizes appreciable gains in the
contemplated auction of its generation assets.

Retail Wheeling to Residential Customers

          The recommended decision disagreed with PULP's argument that we lack
statutory authority to mandate retail wheeling of electricity to residential
customers. The recommended decision concluded that the Legislature has favored
the expansion of retail wheeling and that legislative intent was controlling in
this matter. Furthermore, the recommended decision concluded PULP should have
established that legislative policy disfavored such expansion and that it had
failed to do so.

          PULP denied that it bore the burden of proof and contended the burden
was on the proponents of the Plan to 
<PAGE>   15
establish the statutory authority for retail wheeling. PULP also denied that
legislative intent is controlling, asserting a determination of legislative
intent is necessary only if it is established that the relevant statute is
ambiguous. PULP went on to assert this is not the case here. PULP also contended
there would have to be a demonstration that the legislature favored the
introduction of retail wheeling by "administrative fiat" alone. Finally, PULP
argued that while retail wheeling is authorized by statute for the natural gas
industry, this fact does not lead inevitably to the conclusion that the statute
intended that retail wheeling be authorized for the electric industry. And, PULP
maintained that many statutory differences (not enumerated) exist between the
two industries.

Discussion

          PULP's argument is a generic one raised in this and other electric
rate/restructuring proceedings, and our resolution of it in the Consolidated
Edison proceeding is adopted here and requires no further elaboration.

Price Cap Plus Regulation

          The recommended decision rejected PII's proposal to institute "price
cap plus regulation" (a methodology intended to force consideration of
alternatives to plant growth) of the T&D company. The recommended decision noted
that PII had not established affirmatively that price cap plus regulation was
necessary, because PII had not investigated O&R's transmission and distribution
systems to determine whether there was sub-optimal use of those systems. The
subject proposal was also found to be flawed technically. The recommended
decision also rejected PII's alternate to price cap plus regulation, i.e., "the
Distribution Utility Concept", which promotes the deferral of new distribution
system costs.

          PII excepted, arguing that it need not have provided "a complete
technical proposal on 'price cap plus' . . . ." Rather, PII asserted it was
sufficient that it offered an alternative form of T&D regulation which better
avoided adverse environmental impacts. PII claimed the lack of technical detail
was an insufficient basis for rejection of the proposal.

          PII's primary Price Cap Plus regulation proposal does not balance
relevant economic issues, and it will not be endorsed in view of its negative
impact on sales growth. As for the Distribution Utility Concept, we find it is
unnecessary in view of the safeguards in place to preclude O&R from expanding
rate base at the expense of environmentally benign alternatives.

          Specifically, the Settlement requires O&R, for each major T&D upgrade
(projects of $2 million or more), to first evaluate alternatives such as DSM,
fuel cells, photovoltaic systems, etc. In addition, O&R has agreed to monitor
the circuit peaks for any affected substation and the load on transmission and
distribution facilities, and to minimize cost and environmental impacts for
non-major transmission and distribution projects.

Sources of Funds for Rate Decrease

          The recommended decision questioned the level of the overall revenue
decrease and whether adequate allowance had been made for improved productivity
and increased sales. The recommended decision noted that of the approximately
$37 million revenue decrease, only about $5.0 million related to these factors.
The remainder of the decrease was to be financed largely by the expiration of
surcharges, one time refunds, and reductions in DSM and R&D expenditures. The
recommended decision suggested that, based on projections of sales growth and
productivity, as much as an additional $15 million could be available for
ratepayers.

          Staff contended that the recommended decision erred by relying on
gross revenues rather than net margin. Staff asserted 
<PAGE>   16
also that the recommended decision failed to account for the fact that the first
two years of the Plan overlapped a prior rate settlement, wherein productivity
and sales growth were accounted for. Finally, Staff criticized the recommended
decision for ignoring growth in O&R's expenses.

          A table attached to Staff's Brief on Exceptions supports Staff's
position, and, accordingly, we do not agree with the Judge's suggestion that
additional sums are available to reduce rates further. In view of this fact, the
fact that O&R does not possess horizontal market power now, and because our
oversight of the auction will ensure that no party will exercise market power in
O&R's service territory, we conclude that the Settlement results in just and
reasonable rates. 

Deferrals

          CPB expressed concern about a number of deferrals or otherwise
"open-ended adders" provided for in the Settlement such as deferral of $2.85
million of coal costs, potential shortfalls from time-of-use rates, deferral of
$7.5 million of employee-related costs, and the deferral of storm damage costs.
CPB requested that to the extent O&R is permitted to recover some or all of the
deferred costs, this should occur only if rate increases do not result.

          The CPB's concern about a rate spike is reasonable. However, the
Settlement contains no language that would limit our authority to review the
deferral petitions and authorize deferral accounting for only reasonable
amounts. While the Settlement would permit the company to offset regulatory
assets against regulatory liabilities, including gains on the sale of
generation, it is likely that the customers' share of gains from the sale of
generation will more than offset any deferred debits.

Consumer Outreach and Education

          A new provision has been added to the Settlement which provides
additional funding for an informational campaign designed to aid residential and
commercial customers in making informed energy choices. Also, information will
be disseminated by O&R concerning environmental programs and impacts related to
electric deregulation.

          Specifically, the company has agreed to commit "up to the equivalent
of $1 million of the present value of fourth year SBC funds for the purpose of
educating residential and commercial customers about electric competition."
Staff is to circulate to all active parties, by December 31, 1997, a proposal
for implementing the educational program which is to begin in early 1998.

          PULP opposes the creation of this fund, arguing that the amount at
issue should instead be refunded to ratepayers. Moreover, argues PULP, as O&R
acknowledges that it spends substantial amounts for consumer education, no
additional expenditures are warranted. Finally, PULP contends that the benefits
of competition will accrue largely to O&R's shareholders, and thus, they should
shoulder the burden of any additional educational costs.

          PULP's contention about the beneficiaries of competition is pure
surmise and discounts unreasonably the benefits ratepayers are expected to
receive. Insofar as a well-orchestrated outreach and education program eases
ratepayers' confusion and educates them about their options, we believe that
this program is in the ratepayers' interest.

                                  MISCELLANEOUS

          1. NYSEG maintains that the recommended decision should have provided
guidance to the parties concerning the generation backout credit and endorsed
the use of full market price of electric power supply without subsidization. The
Settlement provides for the embedded cost of O&R's generation to be charged at
tariff rates until the implementation of full retail access. No further action
is required.
<PAGE>   17

          2. IEUA argues for a capacity pilot program. Given the swift pace of
retail access for both capacity and energy, its exception is denied.

          3. DED and Staff oppose the recommendation that the term of flexible
rate contracts be truncated to minimize the possibility of anti-competitive
outcomes. In Opinion No. 96-12, we set forth the relevant parameters for such
contracts. Accordingly, their exceptions are granted.

          4. PULP, while satisfied with the recommendation that rates and
contracts of ESCOs be filed, excepts to the recommended decision's failure to
recommend that these be reviewed by us. A related matter is PULP's objection to
the recommended decision's reliance on Opinion No. 97-5 regarding the
applicability of HEFPA to ESCOs. These issues have been pursued by PULP in its
petition for reconsideration of Opinion No. 97-5 and elsewhere, and are resolved
in Opinion No. 97-17.

          5. WEPCO and IPPNY/ENRON object to the recommendation that ESCOs be
required to provide, on their bills and in marketing materials, information
which reveals the fuel mix and emissions characteristics of their energy supply.
This matter was resolved in the Settlement, which calls for the development of a
system for providing such information to customers.

          6. WEPCO takes issue with the recommended decision's endorsement of
the gas transfer pricing provision of the Settlement. As the cost to deliver gas
is covered by the proposed gas transportation rate, this exception is denied.

          7. NYPA contests the recommendation that its business customers be
required to absorb O&R's stranded costs, proportionate to the fixed generation
costs they currently incur, because additional cost burdens might motivate them
to relocate. As O&R's system was developed to serve all of its customers, if
NYPA acquires customers from O&R, they will be required to absorb a portion of
O&R's resulting strandable costs.

          8. NYPA raises an issue, not addressed by the parties or the
recommended decision, concerning the potential for the T&D company to offer
discounted services on a preferential basis, in flexible rate contracts, to
O&R's GENCO customers. This issue was not raised timely in any event and is not
considered further as O&R will not maintain a generation business.

          9. PII excepts to the recommended decision's rejection of its proposal
that ESCOs maintain an emissions portfolio standard. This exception is dismissed
for the reasons offered by Judge Boschwitz in the recommended decision.

          10. Staff chastises the Judge for engaging in micro-management by
endorsing a $200,000 adjustment proposed by CPB relating to workers'
compensation costs. We agree with Staff that adjustments of this type are
subsumed in the overall revenue requirement. Moreover, at our session of
December 17, we rejected a CPB petition regarding the accounting for such costs.

          11. WEPCO and IPPNY/ENRON object to a recommendation that ESCOs file
energy rates and customer charges with us and that, we, in turn, make such
information available on a web site in a standardized format. This issue is
being addressed in the farms and food processor pilot.

                            FINDINGS UNDER THE STATE
                        ENVIRONMENTAL QUALITY REVIEW ACT

          In conformance with the State Environmental Quality Review Act
(SEQRA), on May 3, 1996, in Case 94-E-0952, we issued a Final Generic
Environmental Impact Statement (FGEIS) which evaluated the action adopted in the
generic proceeding regarding competitive opportunities for electric service.
Recognizing that individual utility restructuring proposals might bring to light
new concerns, we also required each utility to file an environmental assessment
of its restructuring plans. O&R filed an EAF concerning the March 25 Settlement
on April 4, 1997.

          Subsequent to filing of the EAF, PII filed a petition asking that a
Supplemental Environmental Impact Statement be
<PAGE>   18
filed. In its arguments supporting the petition, PII raised several substantive
issues for SEQRA consideration. In a June 19, 1997 ruling, Chief Administrative
Law Judge Lynch narrowed the issues needing further consideration in the
environmental assessment and invited additional party comments on O&R's EAF.

          The information provided by O&R in its EAF, the parties' comments and
responses, and other information were evaluated in order to determine whether
the potential impacts resulting from adoption of the November 6 Settlement's
terms would be within the bounds and thresholds of the FGEIS adopted in 1996.
Arguably, all of the potential environmental impacts of the Settlement need not
be considered, given that some result from Type II exempt rate actions.
Nonetheless, the analysis examined all areas in which impacts would reasonably
be expected.

          No impacts were found to be associated with price cap regulation or
the Settlement's treatment of the CTC. Minor localized community economic
impacts may occur (e.g., due to reduced tax receipts), but these would be
balanced by positive effects in other localities.

          Of greater concern is the possible increase in air pollution that
could accompany increased demand for electric energy. It is likely that
increases in energy demand will result from the Settlement's decrease in (1)
rates (0.42% average annual increase in demand over the 1997-2012 period), and
(2) DSM expenditures (0.08% increase in demand). Each of these incremental
growth rates is an upper bound. For example, it is not clear that all of the
rate reductions from the Settlement should be attributed to restructuring, and
the lower DSM expenditures do not consider ESCO DSM spending. We believe that
actual growth rates will be substantially less than the corresponding rates in
the FGEIS (1% annual incremental growth from the "high sales" scenario, and
0.29% from the "no incremental utility DSM" scenario).

          Because of the inherent uncertainty in forecasting future impacts, as
a matter of discretion, monitoring of O&R's restructuring and environmental
impacts is being implemented, and an SBC is being established. While limiting
the rate decreases in the Settlement could mitigate environmental impacts, it
would not be rational to do so in light of the economic benefits of the rate
reductions to consumers and businesses. Rather, the mitigation methods we are
adopting are sufficient.

          Based on these analyses, the potential environmental impacts of the
Settlement are found to be within the range of thresholds and conditions set
forth in the FGEIS. Therefore, no further SEQRA action is necessary.

                          DISCUSSION AND RECOMMENDATION

          Our assessment of this Settlement reflects not only the diverse nature
of those parties who endorse it, but also the views of other parties whose
comments have been less favorable. The salient features upon which we focus are
the rate plan, the impact on competition, and the amelioration of environmental
concerns.

          The rate plan is intended to promote jobs and economic development by
reducing rates for large industrial customers to a level approaching the
national average. At the same time rates for other customers will also be
reduced. Furthermore, the residential and small commercial reductions will be
more appreciable in the event O&R realizes a significant gain when it divests
its electric generating facilities. As we noted, had we apportioned the revenue
reduction equally among all classes, customers other than large industrial
customers would have realized a minimal gain, while the laudatory goal of
promoting job growth and economic development would have been abandoned.

          With regard to those parties who have advocated a greater revenue
reduction, we believe that by shortening the time frame for recovery by O&R of
its going forward costs and by 
<PAGE>   19
reducing the costs that O&R will be permitted to recover via the CTC, we have
accomplished essentially the same outcome.

          As for the competitive aspects of the Settlement, these are
particularly favorable as O&R's customers will be able to avail themselves of
full retail access sooner than the customers of any other New York utility and
because O&R has now agreed to divest by auction all of its generating assets.
This should contribute to the development of a robust, competitive electric
generation market. The company's unbundling plan, as well as the auction plan,
will be subject to our approval, and we will ensure that market power concerns
are mitigated. These elements of the Settlement, together with the development
of a competitive electric market will, therefore, produce just and reasonable
rates that we expect will be lower than they would be otherwise. As to concerns
about potential anti-competitive conduct, we are satisfied that the Standards of
Competitive Conduct (Appendix H of the Settlement) and the controls on Affiliate
Relations (Appendix I of the Settlement) will preclude such conduct,
particularly given that we are authorized to "impose on the Delivery company
remedial action for violation of standards of competitive conduct." Moreover,
the Settlement acknowledges our authority to modify the standards.

          Finally, we are satisfied the funding of an SBC and the additional
environmental protections agreed to by O&R adequately protect our environment.

          For the reasons stated, O&R and the supporting parties have
demonstrated that the proposed rate reductions are reasonable and that the
Settlement satisfies the objectives of Opinion No. 96-12 and our Settlement
Guidelines. We therefore adopt the terms of the Settlement and reaffirm our
Order of November 26, 1997 and our view that the development of a competitive
market will produce further consumer benefits.

The Commission orders:

          1. The Order Adopting Terms of Settlement (issued November 26, 1997)
is adopted in its entirety and is incorporated as part of this opinion and
order.

          2. Orange and Rockland Utilities, Inc. (O&R) shall file its specific
plans for the holding company structure as soon as practicable. At least 20 days
before any intermediate holding companies acquire stock of the utility, O&R
shall file with the Commission a detailed description of any such intermediate
holding companies, including copies of filings with the Securities and Exchange
Commission relevant to such transactions. Such transactions regarding any
intermediate holding companies shall be deemed approved, unless within 45 days
the Commission notifies O&R that the provisions are inconsistent with the
November 6 Settlement or the November 26 order in this proceeding.

          3. O&R is authorized to use Account 186, Miscellaneous Deferred Debits
and Account 253, Other Deferred Credits, as appropriate, to record the principal
amount and any authorized carrying charge for the items included in the Electric
Rate and Restructuring Plan for which deferred accounting has been approved. The
amounts deferred for each of these items and their income tax effects shall be
recorded in separate subaccounts so as to remain readily identifiable. O&R shall
maintain proper and easily accessible documentation for each entry. The
disposition or amortization for each item shall be carried out according to the
terms of the Rate Settlement or as otherwise authorized by the Commission.
Within 30 days of this order, the company will submit to the Director of
Accounting and Finance, for his approval, the proposed journal entities to
accomplish the accounting provisions of this order.

          4. O&R is authorized to defer the costs it incurred to terminate its
contract with the Pittston Coal Sales Corporation to the extent that such
termination resulted in cost savings. Staff will report to the Commission its
determination of the 
<PAGE>   20
related cost savings and a recommendation regarding the appropriate amount that
would be recoverable in rates.

          5.  This proceeding is continued.
                              By the Commission,

              (SIGNED)        JOHN C. CRARY

                                Secretary

                             617.20                            APPENDIX

               State Environmental Quality Review

ENVIRONMENTAL ASSESSMENT FORM

                               PROJECT INFORMATION

1.        APPLICANT/SPONSOR: Orange and Rockland Utilities, Inc.

2.        PROJECT NAME: Elect.Rate/Restructuring - Case 96-E-0900

3.        PROJECT LOCATION: Orange and Rockland Utilities Service Territory
          Municipality NA County NA

4.        PRECISE LOCATION: (Street address and road intersections, prominent
          landmarks, etc., or provide map) NA

5.        PROPOSED ACTION IS:

          New Expansion Modification/alteration

6.        DESCRIBE PROJECT BRIEFLY: Cases 94-E-0952 & 96-E-0900 - In the matter
          of competitive opportunities regarding electric service, filed in Case
          93-M-0229; Plans for electric rate/restructuring pursuant to Opinion
          No. 96-12; and the formation of a holding company pursuant to PSL, 70,
          108 and 110, and certain related transactions -- Environmental
          Assessment Form.

7.        AMOUNT OF LAND AFFECTED: NA
          Initially________acres     Ultimately_________acres

8.        WILL PROPOSED ACTION COMPLY WITH EXISTING ZONING OR OTHER EXISTING
          LAND USE RESTRICTIONS?    NA

          Yes     No     If No, describe briefly

9.        WHAT IS PRESENT LAND USE IN VICINITY OF PROJECT?

          NA

          Residential Industrial Commercial Agricultural Park/Forest/Open space
          Other

          Describe:

10.       DOES ACTION INVOLVE A PERMIT APPROVAL, OR FUNDING, NOW OR ULTIMATELY
          FROM ANY OTHER GOVERNMENTAL AGENCY (FEDERAL, STATE OR LOCAL)?

          Yes   No   

          If yes, list agency(s) name and permit/approvals: NYS Public Service
          Commission

11.       DOES ANY ASPECT OF THE ACTION HAVE A CURRENTLY VALID PERMIT OR
          APPROVAL?

          Yes     No     

          If yes, list agency(s) name and permit/approval Stationary sources
          owned and operated by Orange and Rockland

          Utilities have valid, approved certificates to operate.

12.       AS A RESULT OF PROPOSED ACTION WILL EXISTING PERMIT/APPROVAL REQUIRE
          MODIFICATION? 

          NA

          Yes   No   

          I CERTIFY THAT THE INFORMATION PROVIDED ABOVE IS TRUE TO THE BEST OF
          MY KNOWLEDGE

Agency: NYS Department of Public Service Date: November 25, 1997

Signature:

                                    APPENDIX

                        PART II-ENVIRONMENTAL ASSESSMENT

A. DOES ACTION EXCEED ANY TYPE 1 THRESHOLD IN 6 NYCRR, PART 617.4? 

If yes, coordinate the review process and use the FULL EAF. Yes No

B. WILL ACTION RECEIVE COORDINATED REVIEW AS PROVIDED FOR UNLISTED ACTIONS IN 6
NYCRR, PART 617.6? If No, a negative declaration may be superseded by another
involved agency. NA Yes  No

C. COULD ACTION RESULT IN ANY ADVERSE EFFECTS ASSOCIATED WITH THE FOLLOWING:
(Answers may be handwritten, if legible.)

          C1. Existing air quality, surface or groundwater quality or quantity,
noise levels, existing traffic patterns, solid waste production or disposal,
potential for erosion, drainage or flooding problems? Explain briefly:

          Expected impacts are within the range of thresholds and conditions set
forth in the FGEIS.

          C2. Aesthetic, agricultural, archaeological, historic, or other
natural or cultural resources; or community or neighborhood character? Explain
briefly:

          Expected impacts are within the range of thresholds and conditions set
forth in the FGEIS.
<PAGE>   21

          C3.       Vegetation or fauna, fish, shellfish or wildlife species,
                    significant habitats, or threatened or endangered species?
                    Explain briefly:

                    Expected impacts are within the range of thresholds and
                    conditions set forth in the FGEIS.

          C4.       A community's existing plans or goals as officially adopted,
                    or a change in use or intensity of use of land or other
                    natural resources? Explain briefly:

                    Expected impacts are within the range of thresholds and
                    conditions set forth in the FGEIS.

          C5.       Growth, subsequent development, or related activities likely
                    to be induced by the proposed action? Explain briefly:

                    Expected impacts are within the range of thresholds and
                    conditions set forth in the FGEIS.

          C6.       Long term, short term, cumulative, or other effects not
                    identified in C1-C5? Explain briefly: 

                    Expected impacts are within the range of thresholds and
                    conditions set forth in the FGEIS.

          C7.       Other impacts (including changes in use of either quantity
                    or type of energy)? Explain briefly: 

                    Expected impacts are within the range of thresholds and
                    conditions set forth in the FGEIS.

D.        WILL THE PROJECT HAVE AN IMPACT ON THE ENVIRONMENTAL CHARACTERISTICS
          THAT CAUSED THE ESTABLISHMENT OF A CRITICAL ENVIRONMENTAL AREA (CEA)?

          Yes      No  If Yes, explain briefly:

E.        IS THERE, OR IS THERE LIKELY TO BE, CONTROVERSY RELATED TO POTENTIAL
          ADVERSE ENVIRONMENTAL IMPACTS?

          Yes      No  If Yes, explain briefly:

Part III - DETERMINATION OF SIGNIFICANCE (To be completed by Agency) See the
attached Environmental Assessment Form Narrative.

Staff recommends that the Final Generic Environmental Impact Statement (FGEIS)
issued on May 3, 1996 (Case 94-E-0952), with respect to the proposed action of
adopting a policy supporting increased competition in electric markets be
extended in applicability, without modification or supplementation, to the
approval of Consolidated Edison Company of New York, Inc.s (The Company)
Agreement and Settlement on the grounds that the significance of the proposals
anticipated environmental impacts will not exceed the threshold values examined
in the FGEIS. Consequently, no further State Environmental Quality Review Act
(SEQRA) action is necessary in approving the Proposal.

Staff further recommends that a monitoring program be instituted to provide a
record of changes resulting from the restructuring plans implementation to
enable confirmation and/or exposition of unexpected outcomes and their
significance, and to assure that specific mitigation measures are implemented as
needed.

      NYS Department of Public Service          
      Date November 25, 1997
      Name of Lead Agency                              
       John H. Smolinsky                        
      Chief, Environmental Compliance and Operations

     Print or Type Name of Responsible Officer in Lead Agency                   
          Title of Responsible Officer

     Signature of Responsible Officer in Lead Agency      
         Signature of Preparer (If different from responsible officer)

                                    APPENDIX

             ENVIRONMENTAL ASSESSMENT FORM NARRATIVE

      I.  BACKGROUND

          On May 3, 1996, the Commission issued a Final Generic Environmental
Impact Statement (FGEIS) in the competitive Opportunities proceeding which
addressed the environmental impacts of a policy supporting increased competition
in electric markets. Alternative approaches to achieving electric competition,
including a no-action alternative, were studied.

          In Opinion No. 96-12 issued May 20, 1996, the Commission set forth its
findings with respect to the FGEIS (p.76-81). The Commission determined that the
likely environmental effects of a shift to a more competitive market for
electricity are not fully predictable but that:

         In general, the proposed action will have environmental impacts that
         are modest or not distinguishable from those of alternative actions,
         including the no-action alternative... Apart from the areas of
         substantial concern noted below, the FGEIS did not identify reasonably
         likely significant adverse impacts.
<PAGE>   22

         With respect to air quality impacts related to oxides of nitrogen and
         sulfur, it appears likely that the retail or wholesale electric market
         structures would have greater impacts than the no action alternative.
         It appears likely that, in the absence of mitigation measures, research
         and development in environmental and renewables areas would lose
         funding if competitive restructuring moves forward. In addition, there
         would likely be a decrease in the amount of cost-effective energy
         efficiency during any transition to wholesale or retail competition...

         In order to address the adverse environmental effects identified above
         on air quality, energy efficiency, and research and development,
         several mitigation measures will be employed as necessary. First, a
         system benefits charge will be used as appropriate to fund DSM and
         research and a development in environmental and renewable resource
         areas during the transition to competition. Second, the competitive
         restructuring will be monitored closely to ensure that specific
         mitigation measures are implemented if needed. Finally, the Commission
         will support and assist efforts by New York State and federal agencies
         to ensure that adverse environmental impacts to the state's air quality
         from upwind sources of air contamination do not occur as a result of
         the movement toward competition.

         Notwithstanding the mitigation measures identified, the proposed action
         to restructure the electric industry may result in an unavoidable
         adverse environmental impact on air quality related to oxides of
         nitrogen and sulfur, loss of some DSM activity, loss of some research
         and development funding in the environmental and renewables areas, and
         displacement of workers and local economic loss where plants are
         closed. Nevertheless, weighing and balancing these likely environmental
         effects of the shift to competition in the electric industry in New
         York with social, economic, and other essential considerations, leads
         to the conclusion that implementing the proposed action toward greater
         competition is desirable.

          The Commission also recognized that individual utility proposals might
bring to light new concerns. In Opinion No. 96-12, and as further clarified in
Opinion No. 96-17, it required each utility to file with its restructuring plans
an Environmental Assessment Form and a recommendation on further environmental
review. The information to be provided was expected to assist the Commission in
determining the need for additional mitigation measures with respect to company
restructuring.

          On April 4, 1997, Orange and Rockland submitted its Environmental
Assessment Form (EAF) and SEQRA recommendation in connection with the Agreement
and Settlement dated March 25, 1997 in Case 96-E-0229.

          Staff reviewed the company's EAF and prepared a staff EAF based on the
March 25, 1997 proposed settlement. The Commission considered and rejected the
March 25 settlement at its session of September 10, 1997. The company, staff and
interested parties subsequently negotiated a revised settlement (November 6,
1997) intended to address deficiencies in the March 25 settlement. The following
document is a revised staff EAF intended to address the November 6 settlement
agreement.

SEQR and Commission Approval of the Orange and Rockland
Restructuring Plan - Options Before the Commission
<PAGE>   23

          The FGEIS issued by the Commission in conformance with
SEQRA in Case 94-E-0952 et. al. addressed the following proposed
action:

         "adoption of a policy supporting increased competition in electric
         markets, including a preferred method to achieve electric competition;
         and regulatory and ratemaking practices that will assist in the
         transition to a more competitive and efficient electric industry, while
         maintaining safety, environmental, affordability, and service quality
         goals."

          Commission approval of Orange and Rockland's proposed restructuring
plan constitutes a "subsequent proposed action". SEQRA requirements with respect
to this "subsequent proposed action' allow the Commission to pursue one of the
four following options:

         1.       No further State Environmental Quality Review (SEQR)
                  compliance is required if a subsequent proposed action will be
                  carried out in conformance with the conditions and thresholds
                  established for such actions in the generic Environmental
                  Impact Statement (EIS) or its findings statement;

         2.       An amended findings statement must be prepared if the
                  subsequent proposed action was adequately addressed in the
                  generic EIS but was not addressed or was not adequately
                  addressed in the findings statement for the generic EIS;

         3.       A negative declaration must be prepared if a subsequent
                  proposed action was not addressed or was not adequately
                  addressed in the generic EIS and the subsequent action will
                  not result in any significant environmental impacts; and

         4.       A supplement to the final generic EIS must be prepared if the
                  subsequent proposed action was not addressed or was not
                  adequately addressed in the generic EIS and the subsequent
                  action may have one or more significant adverse environmental
                  impacts.

          The following environmental assessment will assist in choosing the
appropriate option. The assessment is based on Orange and Rockland's EAF, party
comments submitted in response to Judge Lynchs June 19, 1997 ruling, and on
additional analysis by Department Staff. The Assessment consists of:

         -        Section II - summarizes pertinent aspects of Orange and
                  Rockland and its service territory and describes the proposed
                  settlement agreement.

         -        Section III - summarizes the Environmental Assessment Form
                  submitted by the Company.

         -        Section IV - summarizes party comments on the Company's EAF.

         -        Section V - Staff's analysis of the environmental impacts of
                  the proposed settlement.

         -        Section VI - recommend mitigation and monitoring plan.

         -        Section VII - Staff's overall conclusions and recommendations.
<PAGE>   24

         II.  Orange and Rockland's Settlement Agreement on
              Restructuring

          As of July 1997, the company served 197,977 customers. Its annual
sales, were about 4605 GWH.

          Unique among New York utilities, about 40% of the company's generation
comes from purchased power. The company itself owns two fossil fired baseload
plants (Lovett and Bowline), combustion turbines and a number of small
hydroelectric plants. The company indicates that there are two load pockets in
its territory. An eastern load pocket serving 128,000 customers and a west load
pocket serving 53,000 customers.

          Under the proposed four year settlement agreement on restructuring
large industrial customers will have the opportunity to realize an average
electric price of six cents per kWh. The rates of all other customers will be
reduced in the first year by 1.09% and by another 1.0% effective one year later.
Also, additional reductions, up to a maximum of 5%, will be available to
customers who do not qualify for the large industrial rates if sufficient net
gains are realized from the sale of generating plants. The cumulative customer
rate reductions over the four-year period are equal to approximately $32.4
million.

          Once retail access begins, O&R will be allowed a reasonable
opportunity to recover its investment in stranded generation assets. For each of
the four rate years that the settlement is in effect, earnings on regulated
electric operations in excess of 11.4% in New York will be shared with 75% of
the benefits going to ratepayers and 25% to shareholders.

          A flexible rate tariff will be designed and filed with the Commission.
It will provide for the possibility of rate discounts for commercial and
industrial customers who are currently taking service and who are at serious
risk of relocating or closing their facilities. Full retail access to a
competitive energy and capacity market will be available on May 1, 1999, for all
customers.

          The company will auction off all of its generating assets and
restructure itself as a Registered Holding Company with structurally separate
subsidiaries which may include unregulated subsidiaries as well as a regulated
T&D company. Upon commencement of retail access, the T&D company will provide
basic energy services, including energy, capacity, ancillary services, metering
and billing within the service territory. The T&D company will be the Provider
of Last Resort for all customers choosing to continue to purchase energy
services from it, for those customers who do not choose an energy provider, and
for those customers who purchase from other providers, but who later return as
customers purchasing power from the T&D company. The parties agree to study
transferring this obligation to the competitive market.

          The settlement includes provisions for a competitive transition charge
(CTC) mechanism which would allow the company to recover a portion of its going
forward costs through rates during the period, if any, between the onset of
retail access (scheduled for May 1, 1999) and the divestiture of the company's
generating facilities. The percentage of costs recovered is reduced if the
company does not transfer title of its plants by May 1, 2000. The CTC is
scheduled to end no later than October 31, 2000.

          The settlement includes provisions for sharing the benefits or losses
of the sale of generating plants. If the company selects winning bidders prior
to May 1, 1999, any gains shall be allocated between shareholders and ratepayers
on a 25/75 percent basis and any losses on a 5/95 percent basis. If bidders are
selected after that date, gains or losses will be shared on a 20/80 percent
basis.

          The Performance Standards, which were agreed to in the company's
recent case, will be continued.

          A Low Income Customer Assistance Program will be 
<PAGE>   25
conducted for a two-year period for the residents of the City of Port Jervis.
The company will support the development of a pilot program that would aggregate
low income customers as a single purchasing group.

          The company will continue to develop and implement programs and
materials that will aid its customers in understanding the changes in the
electric industry that are coming and the nature of the services that customers
can expect to receive from O&R in the future. The settlement includes provisions
for an environmental disclosure program which will provide information on the
source of power offered under retail access. Public interest programs will be
continued through a competitively neutral Systems Benefit Charge funded at
approximately $3.2 million (about 1.0 mills/kWh), annually.

    III.  Orange and Rockland Utilities, Inc. Environmental
          Assessment Form
          On April 4, 1997, Orange and Rockland submitted a Short

Environmental Assessment Form (EAF) covering the four year restructuring
settlement it had entered into on March 25, 1997. As a result of this very brief
analysis (discussed below), the company concludes that the settlement agreement
will have "environmental impacts that are modest or not distinguishable from
those of alternative action."

          With regard to changes in generation, the company asserts that it has
no plans to retire its Lovett or Bowline plants or to construct new generating
plants during the period of the settlement. The company does not predict whether
or not other parties will choose to build plants to "meet load growth or replace
existing generation" (i.e., compete with O&R) but notes that any new plants will
be required to undergo thorough environmental review. The company anticipates
that under competition, plant dispatch will be handled by an Independent System
Operator (ISO) and that "actual generation dispatch conducted in a competitive
market is difficult to predict." Similarly, the company states that it cannot
predict whether out-of-state imports of power to O&R's service territory will
increase or decrease.

          The company states that under the agreement it will continue to
support research and development and will spend money on Demand Side Management.
The company notes that a systems benefit charge will also provide some funds for
energy efficiency and public policy related programs. In the long run, it
anticipates that competitive providers of cost effective energy efficiency
services will enter the market place.

          Given the uncertainties about future loads (net of DSM), new plant
construction and out-of-state purchases, the company anticipates no significant
predictable impacts on air quality, water resources or land use. The company
notes that any plants, new or existing, would have to comply with applicable
environmental regulations and that any new steam electric power plants over 80
mw or transmission lines built in New York State would be subject to State
Siting Board or Public Service Commission review and impacts would be thoroughly
examined.

          The company anticipates that the employment and tax revenues from its
existing plants will continue--although possibly at somewhat reduced (but
predictable) levels. On the other hand, the company asserts that lower electric
rates resulting from competition will enhance economic development and job
growth in its service territory.

     IV.  COMMENTS ON THE ORANGE AND ROCKLAND EAF

          On May 13, 1997, the Public Interest Intervenors (PII) moved for the
Department of Public Service staff to prepare supplemental environmental impact
statements (SEISs) in several restructuring cases including case 96-E-0900 - the
Orange and Rockland case.

          At the time the petition was filed several of the 
<PAGE>   26
utilities, including Orange and Rockland, had submitted Environmental Assessment
Forms for their proposed restructuring plans. In its petition PII identified a
number of claimed deficiencies in the EAF's. Some were generic in nature and, in
our understanding, were intended to apply to all utilities; some were specific
to particular utilities. The following are the issues raised by PII which
pertain, generically or specifically, to O&R.

             The systems benefits charge [SBC] proposed in the settlement
             agreement is below the thresholds and conditions established in the
             FGEIS and warrants additional environmental scrutiny.

             PII notes that the FGEIS considered using a systems benefit charge
             (which would pay for certain energy efficiency, low income and R&D
             activities not likely to be undertaken by a deregulated utility) as
             means of mitigating some environmental impacts. It asserts that the
             Commission made a decision in Opinion 96- 12 that the SBC should be
             funded at approximately the current levels of activity and that a
             SEIS is required to assess the environmental impacts of the funding
             level proposed in the settlement.

             The air quality impacts of the reduced commitment to energy
             efficiency should be examined.

              While the system benefit charge is intended to provide for energy
             efficiency services (beyond those arising from market forces) it is
             anticipated that utilities will continue to offer some DSM
             services. PII asserts that O&R's proposed DSM budget will be lower
             than in previous years as a result of the restructuring plan and
             that will have negative environmental impacts.

             Environmental Impacts associated with the elimination of the
             existing revenue per customer mechanism and the institution of a
             price cap form of regulation for the T&D company must be evaluated,

              PII notes that although the proposed agreement provides for
             transition to deregulation of generation, T&D services would remain
             under a traditional price cap form of regulation with a freeze in
             rates for the period of the agreement. PII argues that price cap
             regulation contains inherent incentives for a utility to increase
             sales and inflate rate base and that the Commission is therefore
             required to order an SEIS on the subject of price cap regulation.

             Failure to expose the utilitys fossil generating units to full
             market risk requires environmental review.

             The proposed March 25 settlement included a provision for a
             Competitive Transition Charge (CTC) which would allow the company
             to recover the "going forward" costs of its steam electric plants.
             This charge, which would be 
<PAGE>   27

          recovered through energy, capacity or customer charges, would cover
          generating facility costs, such as labor, routine maintenance, and
          property taxes, which are not variable in the short term but which
          could be avoided in the long term by shutting the plant down. PII
          argues that by providing a mechanism for the recovery of these costs,
          the agreement would subsidize the operation of the company's plants,
          give the company an unfair price advantage when bidding energy sales
          to an ISO and result in those plants operating more than is
          economically efficient. Environmental impacts would ensue if the
          Orange and Rockland plants were run in lieu of other plants which are
          both more economically efficient and more environmentally benign.

          The environmental impact of new construction needed to eliminate load
          pockets/market power must be addressed, including the consideration of
          alternatives.

          PII notes that load pockets have been identified in several utilities
          service territory and that construction of new transmission facilities
          may be required to mitigate these load pockets. These facilities will
          have environmental impacts which should be evaluated in a SEIS.

          Chief Administrative Law Judge Lynch considered the PII petition and
reply comments by staff and several other parties and recommended that "the
final EAFs prepared for Commission use in the Con Edison and O&R cases consider
the potential environmental effects of T&D price cap regulation for Con Edison
and the recovery of non-variable generation costs in T&D rates for Con Edison
and O&R" but that "in all other respects, there is no reason to commence
preparation of SEISs." Nonetheless staff's analysis in Section V will address
the issues raised by PII which are relevant to O&R.

      V.  Staff Analysis

          The FGEIS covered the significant generic issues connected with
restructuring at considerable length. The following analysis will not
recapitulate the material in the FGEIS. Nor will the analysis repeat the
material adequately covered in the company's EAF and summarized in section III
of this memorandum. Instead this analysis will deal with issues identified by
staff or by the PII comments on the Orange and Rockland EAF where it is
reasonable to anticipate that unique features of the company's service territory
or restructuring plan might result in environmental impacts not considered in
the FGEIS or in excess of thresholds identified in the FGEIS.

     A.  Effects of Restructuring on Overall Level of
         Electric Sales in Orange and Rockland's

          Service Territory

          A key determinant of the incremental environmental impacts of
restructuring the electric industry in New York is the effect of restructuring
on the overall level of electric sales. This section of the EAF will address the
question of whether any likely effect of the Orange and Rockland restructuring
plan would cause sales growth in excess of the levels contemplated in the Final
Generic Environmental Impact Statement (FGEIS).
<PAGE>   28
          There appear to be three realistic ways in which restructuring could
have significant impacts on electric sales.

          1.  Price Elasticity Effects

              If electric prices drop - as a result of
utility rate reductions incorporated in restructuring agreements and/or as a
result of competition among the utility and alternative suppliers - customers
may make the economic decision to consume more electricity. This is a price
elasticity effect. The FGEIS analysis included the preparation of a statewide
"high sales" scenario based on estimated sales increases that could result from
decreases in electric prices given the best information then available to staff
economists. (FGEIS scenario - 1). Scenario 1 assumed that under the high sales
assumptions used in the analysis, the compounding statewide electric sales
growth would be about 2.2% per year.

          This scenario was compared to a FGEIS base case "evolving regulatory
model" scenario. The base case assumed incremental sales growth of 1.2%. Thus
the additional incremental statewide sales growth likely to result from the high
sales scenario compared to the no action base case was estimated as about 1.0% a
year.

          PROMOD simulation of comparative plant dispatching under these
scenarios showed that compared to the evolving regulatory model, the high sales
model would result in a 2.9% increase in SO2 emissions, a 5.5% increase in NOx
and a 12% increase in CO2 by 2012. The Commission determined that, although the
FGEIS showed the possibility of detrimental incremental air quality impacts
"consistent with the social, economic and other considerations, from among the
reasonable alternatives available" the Commission's restructuring policy "avoids
or minimizes adverse environmental impacts to the maximum extent possible."

          Recently Staff of the Office of Regulatory Economics (ORE) of the DPS
estimated a range for expected growth under a competitive environment. The new
estimates use updated data, including information developed during the
settlement negotiations. The ORE's forecast shows that statewide incremental
sales growth under competition could be about 0.4%.

          Orange and Rockland is a relatively small utility and only accounts
for roughly 2.4% of NYPP sales. In analyzing the significance of any potential
incremental sales growth attributable to the Orange and Rockland restructuring
plan it is reasonable to focus on Orange and Rockland's pro rata share of the
sales growth and impacts considered in the FGEIS and ask whether Orange and
Rockland's incremental sales growth due to price elasticity effects resulting
from restructuring would be likely to be significantly greater than the average
Statewide incremental sales growth due to restructuring.

          Staff of the Department's Office of Regulatory Economics projects that
Orange and Rockland Sales would probably grow somewhat faster than the statewide
average over the next few years due to local economic factors regardless of
whether or not the company is restructured. However, there are no particular
features of the proposed restructuring plan or the company's service territory
which suggest that the effects of restructuring would be greater in Orange and
Rockland's case than in the State as a whole. An elasticity analysis using the
rate reductions in the Orange and Rockland settlement (see Attachment, Tables A
and C) shows that the guaranteed rate reductions are likely to produce a 0.25%
incremental annual increase in demand over the same 15 year modeling period used
in the FGEIS. If the sale of generating facilities increases the rate reduction
to 5% for non-large-industrial customers, the increase in 
<PAGE>   29
demand could be as much as 0.42%.

          2. Price Cap Regulation of the T&D Utility

              While the proposed settlement provides for a transition to a more
competitive market for generation, the T&D portion of Orange and Rockland would
remain a regulated utility with rate of return regulation and capped prices. PII
argues that price cap rate of return regulation gives the T&D utility incentives
to promote sales and to build uneconomic rate base. According to PII, these
incentives could result in environmental impacts which should be considered in a
separate SEIS.

          For several years a revenue decoupling mechanism (RDM) was in effect
for O&R which was intended to remove the linkage between increased sales and
increased company profits. However in May of 1996, the Commission approved a
return to price cap regulation for O&R. The continuation of this traditional and
well understood mechanism for the regulated T&D company does not constitute a
change resulting from competition or the transition plan. To the extent that
prices are capped until 2002, the Company may have difficulty recovering T&D
upgrade costs resulting from load growth. Furthermore, the possibility of
prudence review might encourage the company to use targeted DSM as necessary as
possible to avoid T&D upgrades.

          3.  Lower Energy Efficiency Effect

              For a number of years the New York Commission has encouraged
utilities to promote end use energy efficiency (DSM). This encouragement has
included review and approval of utility DSM plans and budgets and various
incentive and cost recovery mechanisms. For all New York utilities, including
Orange and Rockland, the levels of DSM expenditures and energy savings have
declined drastically in recent years. Orange and Rockland's DSM expenditures
peaked at $17 million in 1993 and its incremental annual DSM energy savings
peaked at 41.4 GWH, also in 1993. By 1996, its DSM budget had declined to only
$4.2 million and its DSM incremental energy savings goal had declined to only 11
GWH. However, the company actually achieved only 2.5 GWH of DSM savings in 1996.
Staff estimates the company's incremental energy savings from DSM in 1997 will
be about 1.2 GWH. No specific sum is included in the settlement for the
continuation of utility DSM programs.

          Staff examined the possibility that DSM budget reductions could reduce
the energy conservation measures taken by O&R customers and result in
incremental increases in electric sales beyond the base case.

          In the FGEIS, the base case "evolving regulatory model" scenario and
the high sales scenario (Scenario 1); included annual incremental Orange and
Rockland DSM energy savings of 11 GWH for the years 1997 and beyond. In Scenario
1a in the FGEIS, staff estimated the sales and environmental impacts of halting
all DSM activities. The sales and environmental impacts of the "No incremental
utility DSM" scenario were shown to be much smaller than those of the "high
sales scenario."

          The FGEIS did not consider a scenario that assumed both high sales and
no incremental DSM, so staff evaluated the plausibility of a realistic
combination of low Orange and Rockland DSM and high Orange and Rockland sales
growth could result in sales greater than those postulated in the FGEIS "high
sales scenario".

          Staff has reanalyzed the impact of energy efficiency programs on O&R
sales growth using a value of 1.2 GWH for 1997 and 0 GWH for the years 1998
through 2012 and compared that to the DSM impact analysis underlying the FGEIS
high sales scenario. We calculate that averaged over the FGEIS modeling period
(1997 through 2012), the 
<PAGE>   30
elimination of all energy efficiency sales reduction after 1997 would increase
sales by only 0.08% a year.

          As discussed in Section V.A.1, the price elasticity effects of the
settlement rate reductions would increase sales by an average rate of 0.25% to
0.42% a year over the 15 year period. If the effects of no DSM are added, the
likely sales increases due to the settlement are in the range of 0.33% to 0.50%.
This is well below the 1.0% high sales scenario considered in the FGEIS. In
fact, the settlement provides for substantial funding of energy efficiency
through the SBC and we anticipate that ESCOs will offer energy conservation
services, both of which will tend to reduce sales.

          4. System Benefits Charge

              The settlement provides for an SBC funded at an average level of
$3.2 million a year, of which approximately $2.9 million will be spent on energy
efficiency programs. This is below the company's 1995 DSM expenditure of $6.9
million but quite close to the company's actual 1996 DSM expenditure of $3.1
million. The Commission will determine the appropriate amount of funding for the
SBC in either this proceeding or a separate generic proceeding.

       B.Effect of Restructuring on Retirement or
         Construction of New Generation, Plant Dispatch or
         Fuel Purchase

          Another potential factor that could, in concept, affect New York's
environment is the direct or indirect effect of the Orange and Rockland
restructuring plan on the mix of fuels burned or plants run to meet electric
sales in Orange and Rockland's territory. The following section will analyze
whether there is any reason to believe that the Orange and Rockland plan would
result in impacts that are greater than or different in nature or causation from
those already addressed in the FGEIS.

          1. Retirement of Orange and Rockland Generating
             Facilities

              Retirement of a major Orange and Rockland generating facility
would change the mix of generation resources available in the region and thus
could have a potential environmental impact. In addition, permanent retirement
and decommissioning of a plant could have a variety of local fiscal, economic,
employment and land use impacts. The company asserts in its EAF that it has no
plans to retire any of its existing generating facilities.

          However, under the revised settlement, the company is required to
auction off all of its generating facilities. It is conceivable that a
particularly inefficient plant might receive no bids or an unacceptably low bid.
It is not clear exactly what would happen in that instance. Under the revised
settlement the company is required to file a divestiture plan after Commission
approval of the settlement. This plan will include more detail on the process of
divestiture.

          While unpredictable, it is possible that the divestiture of these
plants could result in one or more of them being retired earlier than they would
have been in the absence of competition. The FGEIS concluded that accelerated
retirement of less efficient plants is an unavoidable potential consequence of a
more competitive electric industry and that this would cause some local adverse
impacts (including increases in unemployment and decreased tax base) which may
be balanced by positive impacts elsewhere.

          2. Construction of New Generating Plants

              In its EAF the company states that it has no plans to construct
new generating facilities. Staff is not 
<PAGE>   31
aware of any reason that the proposed restructuring would result in new plant
construction by O&R or other companies. In any case, under current air quality
regulations (particularly the emissions offset policies for NOx) construction of
new generation facilities tends to improve air quality.

          3. Effect of Competitive Transition Charge
              (CTC) on Plant Dispatch

              The proposed November 6 settlement includes a provision which will
allow the company to partially recover its above market generation costs through
a CTC charge levied on customers participating in retail access. This charge is
limited in both duration and the percentage of expenses the company may recover.

          If the company transfers title of its generating facilities before the
scheduled May 1, 1999 onset of retail access, the CTC provisions will not go
into effect.

          If the company transfers title of its generating facilities between
May 1, 1999 and April 30, 2000, it will be allowed to recover its non-variable
cost of generation in excess of market revenues from the CTC, with the exception
that 25% of fixed labor costs and property taxes cannot be recovered through the
CTC, but must be recovered from the market. Once title is transferred, the CTC
will end.

          If the company transfers title of generating facilities between May 1,
2000 and October 31, 2000, it will be allowed to recover above market costs
through the CTC, with the exception that 35% of fixed labor costs and property
taxes must be recovered through the market.

          In its comments on the March 25 proposed settlement, PII contended
that since potential non-regulated competitors will not receive a similar income
stream, Orange and Rockland could and would offer its generation to the ISO at a
subsidized and uneconomic price. This, PII asserted, could result in Orange and
Rockland operating less efficient and dirtier plants than the ESCO plants which
would have operated in the absence of the CTC.

          However, under the provisions of the proposed settlement, the
company's fixed operating costs would be reconciled to a fixed target through a
CTC mechanism that is indifferent to whether or not any Orange and Rockland
plant operated on a given day. Since collection of these going forward costs is
not dependent on operating a Orange and Rockland plant (i.e., is not marginal
revenue), both Orange and Rockland and any competitors would face the same short
term decision criterion. They would maximize profits (or minimize losses) on
existing facilities by selling on the market whenever the clearing price equals
or exceeds their marginal operating costs -- as they themselves calculate
marginal costs given their best information.

          It is, of course, true in theory that Orange and Rockland, or any
competitor, might be tempted for strategic reasons to sell at a price below true
marginal costs for a period of time in an attempt to secure market share and
dissuade competitors from entering the market. However, the settlement requires
that, on average, Orange and Rockland's bids for its fossil fueled plants will
not fall below its incremental fuel costs and variable O&M.

          In any event, the duration of the CTC is very limited. It may not go
into effect at all, if the company's plants are transferred before May 1, 1999.
Most likely the CTC will be in operation for less than a year, since the company
is allowed to keep a larger percentage of any gains if it divests before May 1,
2000. The maximum duration of the CTC is 18 months - since it is scheduled to
end October 31, 2000 if the company's plants are not sold by that date.

          Given licensing and construction lead times it is 
<PAGE>   32
virtually impossible for a new power plant to be built to compete in the
company's territory before the end of the CTC. Any developer considering
building such a plant would base its decisions on expected income flows in the
years beyond 2000.

          4.  Fuel Burned by Orange and Rockland

              Various Orange and Rockland units have the capacity to burn either
coal, oil or gas within existing air quality limits. Decisions about which fuel
to burn at these facilities will continue to be based on economic considerations
and unrelated to deregulation.

          5. Increased Generation Outside of Orange and
             Rockland Service Territory

              As previously noted, Orange and Rockland currently purchases about
40% of its power. Some of this power comes from out-of-state generators.
Depending on the location, control technology and fuel type of these generators,
their operation may have positive or negative impacts on air quality in New
York.

              Presumably relatively high levels of power purchases from out of
the service territory will continue during the settlement period and perhaps
during the 15 year analysis period. However, Staff cannot predict the exact
level of these purchases over time or the net impact of these purchases on New
York air quality.

              The FGEIS considered four different scenarios (Scenarios 7, 7A, 7B
and 7C) which examined the environmental impacts of alternative patterns of
power sales across state lines. Since O&R only comprises about 2.4% of NYPP
sales, and since there is no reason to believe that the settlement would result
in a disproportionate increase of power imported into O&R's territory, it is
unlikely that the settlement would result in environmental impacts in excess of
those already considered in the FGEIS.

     C.  Effect of Restructuring Plan on Construction of
         New Transmission Facilities

          In its EAF, Orange and Rockland states that no new transmission
facilities are required to implement the March 25 agreement. However, two small
load pockets exist within the franchise in certain combinations of load and
weather.

          Orange and Rockland's eastern load pocket serves 128,000 customers.
When load exceeds 320 MW - which happened for 2100 hours during 1995 - the
company must run Lovett Steam Station. For 70% of the load pocket period during
1995, 100 MW or less of Lovett capacity was required.

          The western load pocket serves 53,000 customers. During thunderstorms,
or when load exceeds 145 MW, the company must operate its Mongaup Hydroelectric
facilities and its Shoemaker Gas Turbine. According to the company this has
happened approximately 600 hours a year on average for the last several years.

          These load pockets do not create reliability problems, but are of
potential concern in a competitive environment because the owner of these
facilities could exercise market power during load pocket conditions. In its
petition PACE recommends that a supplemental environmental impact statement be
prepared to assess the impact of transmission facilities required to alleviate
these load pockets. The company states that it has considered several
alternatives for the mitigation of these load pockets. In addition to
reinforcing the transmission system by installing additional transformers in two
substations at a cost of approximately $24 million the company has considered:

          - entering into capacity and energy contracts; 
<PAGE>   33
          - installing new generating facilities, and 
          - running targeted DSM programs.

          It has concluded that new transmission improvements are less desirable
and are less cost effective than entering into bilateral contracts between
owners of generation and the T&D utility, effective during the duration of a
load pocket incident, which would prevent the exercise of market power. Since
this contractual solution would not involve the construction of new facilities
or change the dispatching of plants from the situation that would obtain in the
absence of restructuring, there would be no incremental environmental impacts.
The proposed settlement requires the company to file a divestiture plan which
addresses market power issues.

     VI.  Mitigation of Impacts -- Monitoring
          It is important to note that the FGEIS explicitly recognized that "the
likely environmental effects of a shift to a more competitive market for
electricity are not fully predictable due to the absence of precedence,
complexity of the New York electric industry, future regulatory activities,
including those of other states and the federal government, and the nature and
degree of market response. The same uncertainty persists with respect to Orange
and Rockland's restructuring plan.

          In Opinion 96-12 (Opinion and Order Regarding Competitive
Opportunities for Electric Service), the Commission made certain "findings"
pursuant to the State Environmental Quality Review Act. The Commission
determined that "...adverse environmental impacts will be avoided or minimized
to the maximum extent practicable by incorporating as conditions to the decision
those mitigative measures that were identified as practicable;... These
mitigation measures are: (1) monitoring environmental impacts; (2) system
benefits charge; and (3) assisting efforts undertaken by other agencies to
address interstate pollution transport."

          Staff analysis of the Orange and Rockland restructuring plan
determined that its implementation would result in environmental effects which
would most likely be less than the impact values assessed in the FGEIS. To
address any uncertainty and to evaluate unknown outcomes, a monitoring program,
as envisioned in the FGEIS should be developed.

          The environmental impacts which could be monitored are described in
Section 6.2.3 of the Final Generic Environmental Impact Statement (FGEIS) issued
May 3, 1996 in Case 94-E-0952 (Competitive Opportunities Regarding Electric
Service). The FGEIS and this EAF discuss a number of environmental activities
and changes that would be important to monitor during the transition to
competition including:

             imported electricity from the midwest,
              SO2 and NOx emissions,

             retirement of Orange and Rockland power
               plants,

              in-state and out-of-state purchased
                generation,

              fuel mixture of generation,
              R&D related environmental impact,
              new electric and gas transmission line

                construction,

             acid precipitation in the Adirondacks and
               Catskills,

              mitigation of load pockets, and
              the operation of the CTC.

          The proposed environmental monitoring plan 
<PAGE>   34
currently being developed by Staff will be organized around the major
environmental impacts considered in the FGEIS and this EAF, including
information necessary for analysis of any restructuring environmental impacts,
confirmation of expected impacts and exposition of unexpected outcomes and their
significance. Staff anticipates Orange and Rockland's cooperation in the
development and implementation of this monitoring plan.

    VII.  Conclusions

          Staff has considered features of Orange and Rockland's territory and
the proposed November 6 settlement agreement and has analyzed the potential
impacts of that agreement on the environment. We have compared these likely
impacts to those addressed in the FGEIS. Our analysis has been broadly framed
and has looked at limiting cases in order to encompass any modifications to that
agreement likely to be adopted by the Commission. In our analysis we have also
considered issues raised by outside parties commenting on the Orange and
Rockland EAF.

          We conclude that the Orange and Rockland restructuring plan would not
result in significant new environmental impacts not considered in the FGEIS, nor
would it result in impacts likely to be greater than those considered in the
FGEIS. Therefore no SEIS is required under the provisions of SEQRA. Staff
recommends that the Commission determine that no further SEQRA compliance is
required with regard to the transitional restructuring plan for this company.

          Although no further SEQRA compliance is required the Commission should
institute mechanism's for monitoring and, if indicated, mitigating some of the
potential impacts of restructuring.

                                             ATTACHMENT
                                             Page 1 of 3

                        IMPACT OF POSSIBLE RATE DECREASES
                                 ON SALES GROWTH

          Several of the potential impacts of deregulation examined in the Final
Generic Environmental Impact Statement (FGEIS) are a result of the increased
sales that are expected to accompany deregulation. Rate reductions, which are a
primary driver of the increased sales, are not considered explicitly in the
FGEIS; rather it was assumed that, beginning in 1997, sales would increase by an
additional 1% per year for 15 years. That is, if statewide growth without
deregulation is 1.2% per year (as was assumed in the FGEIS evolving regulatory
model), growth with deregulation would be 2.2%.

          In each of the restructuring cases, specific rate reductions are now
being considered. Using price elasticity of demand, these proposed rate
reductions now permit the calculation of an estimate of increased sales to be
expected from restructuring.

          The following tables (developed by the Office of Regulatory Economics)
consider both short-run elasticity (the increase in sales which occurs
immediately after the rate reduction) and long-run elasticity (increases which
occur in subsequent years). The first step in the calculation (Table F) is to
determine the weighted average elasticities based on the elasticities for each
sector (industrial, commercial and residential) and the fraction of the
utility's load in each sector (sales weight). Also, the average price reduction
per year is calculated based on the expected rate decrease for each sector and
the sales weight.
<PAGE>   35
          Five price reduction scenarios (A through E) are considered. Scenario
A uses the price reductions from the March 25 Agreement; Scenario C uses maximum
price reductions from the November 6 Settlement Agreement.

          Tables A through E then calculate the year by year increase in sales
due to competition (short-run (SR Sales), long-run (LR Sales) and total), the
cumulative change in sales, and the annual average rate of sales growth (Annual
Rate). Residential Delta (Res. Delta) is the possible residential rate reduction
considered in the table; Percent Total Impact per Year (%TI/Yr) is the average
price reduction per year from Table F; and Lambda is a parameter relating
short-term and long-term elasticity. The end of the five year settlement period
and the end of the 15 year modeling period are highlighted.

                                             ATTACHMENT
                                             Page 2 of 3

                  PRICE ELASTICITY IMPACT

                   ORANGE AND ROCKLAND

Sales ch = (price elasticity * % price ch) + lambda * (sales ch lag 1)

   A.   %Res Delt  %Tl/ Yr   Lambda   SR Elas.   LR Elas
             2.1      1.73     0.73      0.30      1.12

    Year  SR Sales  LR Sales  Total  Cumulative  Annu.Rate
    1998    0.526    0.000    0.526    0.526     0.53
    1999    0.526    0.383    0.909    1.436     0.72
    2000    0.000    0.662    0.662    2.098     0.69
    2001    0.000    0.482    0.482    2.579     0.64
    2002    0.000    0.351    0.351    2.930     0.58
    2003    0.000    0.255    0.255    3.185     0.52
    2004    0.000    0.186    0.186    3.371     0.47
    2005    0.000    0.135    0.135    3.506     0.43
    2006    0.000    0.098    0.098    3.604     0.39
    2007    0.000    0.072    0.072    3.675     0.36
    2008    0.000    0.052    0.052    3.728     0.33
    2009    0.000    0.038    0.038    3.765     0.31
    2010    0.000    0.028    0.028    3.793     0.29
    2011    0.000    0.020    0.020    3.813     0.27
    2012    0.000    0.015    0.015    3.828     0.25

   B.   %Res Delt  %Tl/ Yr   Lambda   SR Elas.   LR Elas
             4.0      2.53     0.73      0.30      1.12

    Year  SR Sales  LR Sales  Total  Cumulative Annu.Rate
    1998    0.770    0.000    0.770    0.770     0.77
    1999    0.770    0.560    1.330    2.100     1.04
    2000    0.000    0.968    0.968    3.069     1.01
    2001    0.000    0.705    0.705    3.773     0.93
    2002    0.000    0.513    0.513    4.286     0.84
    2003    0.000    0.373    0.373    4.659     0.76
    2004    0.000    0.272    0.272    4.931     0.69
    2005    0.000    0.198    0.198    5.128     0.63
    2006    0.000    0.144    0.144    5.272     0.57
    2007    0.000    0.105    0.105    5.377     0.53
    2008    0.000    0.076    0.076    5.453     0.48
    2009    0.000    0.055    0.055    5.509     0.45
    2010    0.000    0.040    0.040    5.549     0.42
    2011    0.000    0.029    0.029    5.578     0.39
    2012    0.000    0.021    0.021    5.600     0.36

   C.  %Res Delt  %Tl/ Yr   Lambda   SR Elas.  LR Elas

<PAGE>   36

            5.0      2.95     0.73      0.30     1.12

    Year  SR Sales  LR Sales  Total  Cumulative Annu.Rate
    1998    0.898    0.000    0.898    0.898     0.90
    1999    0.898    0.653    1.551    2.448     1.22
    2000    0.000    1.129    1.129    3.577     1.18
    2001    0.000    0.821    0.821    4.398     1.08
    2002    0.000    0.598    0.598    4.996     0.98
    2003    0.000    0.435    0.435    5.431     0.89
    2004    0.000    0.317    0.317    5.747     0.80
    2005    0.000    0.230    0.230    5.978     0.73
    2006    0.000    0.168    0.168    6.145     0.66
    2007    0.000    0.122    0.122    6.267     0.61
    2008    0.000    0.089    0.089    6.356     0.56
    2009    0.000    0.065    0.065    6.421     0.52
    2010    0.000    0.047    0.047    6.468     0.48
    2011    0.000    0.034    0.034    6.502     0.45
    2012    0.000    0.025    0.025    6.527     0.42




                                             ATTACHMENT
                                             Page 3 of 3

                     ORANGE & ROCKLAND

Sales ch = (price elasticity * % price ch) + lambda * (sales ch lag 1)

   D.  %Res Delt  %Tl/ Yr   Lambda  SR Elas.   LR Elas
            8.0     4.19     0.73      0.30      1.12

    Year  SR Sales  LR Sales  Total  Cumulative Annu.Rate
    1998    1.277    0.000    1.277    1.277     1.28
    1999    1.277    0.929    2.206    3.483     1.73
    2000    0.000    1.606    1.606    5.089     1.67
    2001    0.000    1.168    1.168    6.257     1.53
    2002    0.000    0.850    0.850    7.107     1.38
    2003    0.000    0.619    0.619    7.726     1.25
    2004    0.000    0.450    0.450    8.177     1.13
    2005    0.000    0.328    0.328    8.504     1.03
    2006    0.000    0.239    0.239    8.743     0.94
    2007    0.000    0.174    0.174    8.916     0.86
    2008    0.000    0.126    0.126    9.043     0.79
    2009    0.000    0.092    0.092    9.135     0.73
    2010    0.000    0.067    0.067    9.201     0.68
    2011    0.000    0.049    0.049    9.250     0.63
    2012    0.000    0.035    0.035    9.286     0.59

   E.  %Res Delt  %Tl/ Yr   Lambda   SR Elas.  LR Elas
           10.0      5.01     0.73      0.30     1.12

    Year  SR Sales  LR Sales  Total  Cumulative Annu.Rate
    1998    1.527    0.000    1.527    1.527     1.53
    1999    1.527    1.112    2.639    4.166     2.06
    2000    0.000    1.920    1.920    6.087     1.99
    2001    0.000    1.398    1.398    7.484     1.82
    2002    0.000    1.017    1.017    8.501     1.65
    2003    0.000    0.740    0.740    9.241     1.48
    2004    0.000    0.539    0.539    9.780     1.34
    2005    0.000    0.392    0.392   10.172     1.22
    2006    0.000    0.285    0.285   10.457     1.11
    2007    0.000    0.208    0.208   10.665     1.02
    2008    0.000    0.151    0.151   10.816     0.94
    2009    0.000    0.110    0.110   10.926     0.87
    2010    0.000    0.080    0.080   11.006     0.81
    2011    0.000    0.058    0.058   11.064     0.75
    2012    0.000    0.042    0.042   11.107     0.70

<PAGE>   37

   F.                     LARGE    SMALL     RES/    WGTED    PRICE
                            IND  IND/COM    OTHER      AVG    PER YR

         Sales Weight      0.14     0.49     0.37
         SR Price          0.43     0.31     0.25     0.30
         LR Price          1.28     1.17     0.99     1.12
         Price Red. A     12.00     2.10     2.10     3.49     1.73
         Price Red. B     12.00     4.00     4.00     5.12     2.53
         Price Red. C     12.00     5.00     5.00     5.98     2.95
         Price Red. D     12.00     8.00     8.00     8.56     4.19
         Price Red. E     12.00    10.00    10.00    10.28     5.01

         Lambda:                                     0.73