EXHIBIT (99)(i)9

                                STATE OF NEW YORK
                            PUBLIC SERVICE COMMISSION

                       At a session of the Public Service
                         Commission held in the City of
                           Albany on October 24, 2001


COMMISSIONERS PRESENT:

Maureen O. Helmer, Chairman
Thomas J. Dunleavy
James D. Bennett
Leonard A. Weiss
Neal N. Galvin


CASE 00-E-1273 -  Proceeding on Motion of the Commission as to the Rates,
                  Charges, Rules, and Regulations of Central Hudson Gas &
                  Electric Corporation for Electric Service.

CASE 00-G-l274 -  Proceeding on Motion of the Commission as to the Rates,
                  Charges, Rules, and Regulations of Central Hudson Gas &
                  Electric Corporation for Gas Service.


                            ORDER ESTABLISHING RATES

                     (Issued and Effective October 25, 2001)


BY THE COMMISSION:

              The following order generally adopts terms set forth in Joint
Proposal submitted by Central Hudson Gas & Electric Corporation (Central Hudson,
the company); staff of the Department of Public Service (Staff); the Consumer
Protection Board (CPB) ; Multiple Intervenors (MI); and Strategic Power
Management, Inc., an energy services company (ESCO). We thereby establish a rate
and regulatory plan intended to take effect as of July 1, 2001 and to continue
for at least three years from that date.

              Today's order determines the rates Central Hudson will charge for

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delivery of electricity and gas to customers that purchase those commodities
from Central Hudson, and to customers that purchase the commodities elsewhere
and rely on Central Hudson for delivery only. (The commodity portion of the bill
is determined by energy prices in markets outside our regulatory jurisdiction.)
The order will freeze electric and gas delivery rates for three years, after
initially reducing electric delivery rates by 1.2% overall.

              In addition to rate levels, a major issue in this case has been
the disposition of a "benefit fund" that will have accumulated as a result of
Central Hudson's operations pursuant to the Rate and Restructuring Plan
instituted in February 1998.(1) The fund includes, most significantly, the
proceeds from the company's sale of its Danskammer and Roseton generating plants
and its interest in the Nine Mile Point No. 2 (NMP2) generating plant. For
purposes of the joint proposal, the parties have estimated the benefit fund as
$164 million. Under a proposal pending in another proceeding,(2) the fund might
be augmented by additional amounts related to the NMP2 sale.

              Under today's order, $42.5 million of the benefit fund will be
used to offset rate base and thereby achieve the three-year rate freeze noted
above. Another $45 million will be used as refunds to customers over the three
years of the rate plan. As the $45 million is a net-of-tax amount, the refunds
actually received by customers will total about $72 million. The remainder will
be applied toward other customer benefits which may include additional refunds,
reliability improvements, bill mitigation in the event of commodity price
volatility, and economic development programs. To the extent that portions of
the fund are held in reserve rather than used immediately, they will accrue
interest on the customers' behalf.

              We also are adopting more stringent service quality criteria, and
expanded programs to help residential customers that have difficulty paying

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(1)  Case 96-E-0909, CENTRAL HUDSON GAS & ELECTRIC CORP. - ELECTRIC RATES AND
     RESTRUCTURING, Opinion No. 98-14 (issued June 30, 1998).


(2)  Case 01-E-0011, NIAGARA MOHAWK POWER CORP. ET AL., PETITION UNDER PUBLIC
     SERVICE LAW ss.70.

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their utility bills. And, to enhance customers' ability to obtain energy
supplies from providers competing with Central Hudson, we are prescribing
backout credits which will determine what portion of the Central Hudson bill a
customer may avoid by shopping elsewhere for the electric or gas commodity. We
also will require that Central Hudson reimburse ESCOs for ancillary service
charges imposed on them by the Independent System Operator, a cost element whose
volatility has deterred market entry by ESCOs.

                        BACKGROUND AND PROCEDURAL HISTORY

              Central Hudson serves about 260,000 customers in eight mid-Hudson
counties. In the February 1998 Rate and Restructuring Plan, we set rates
intended to continue through June 2001 and directed the company to divest its
electric generating plants, unbundle its rates, and institute full retail
access. The current proceedings were instituted to consider new tariffs for
unbundled delivery service only, proposed in August 2000 and amended in October
2000 after sale of the Roseton and Danskammer plants. The company designed the
proposed tariffs to increase its annual electric and gas delivery revenues by
about $14.1 million (8.8%) and $3.6 million (4.7%) respectively for the year
ending June 30, 2002.

              After full evidentiary hearings and numerous public statement
hearings, a recommended decision (RD) issued April 24, 2001 called for electric
and gas revenue decreases of $1.7 million and $2.1 million respectively. The RD
provisionally addressed the disposition of the benefit fund, but it recommended
further negotiations on that issue and others. Settlement discussions had been
conducted intermittently throughout the proceedings, on notice to potentially
interested parties (in compliance with 16 NYCRR 3.9). After two rounds of briefs
on or opposing exceptions to the RD, negotiations resumed, and culminated in the
joint proposal under review here. To allow for negotiations and Commission
review of any resulting proposal, the company has waived the expiration of the
statutory suspension period through October 31, 2001.

              The joint proposal was filed August 21, 2001 and was followed by
two rounds of written statements in support or in opposition. Supporting
statements and replies have been filed by Central Hudson, Staff, CPB, and MI.
Statements opposing at least some elements of the joint proposal have been

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filed by the Office of the Attorney General (OAG); Small Customer Marketer
Coalition (SCMC), representing certain ESCOs; and John J. Mavretich, PRO SE.

                 TERMS SUBMITTED PURSUANT TO THE JOINT PROPOSAL

              Should we adopt the terms proposed by the parties, significant
results would include the following:(3)

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(3)  For a complete statement of the joint proposal's terms, one must rely on
     the text of the proposal itself (Attachment B of this order).

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REVENUE REQUIREMENT

              Delivery rates would be frozen for three years through June
              2004,(4) at levels designed to produce (over the three years) a $2
              million decrease in annual electric delivery revenues and no
              change in gas delivery revenues. Within certain limits, the
              company could use deferral accounting as a means of extending the
              freeze beyond three years.

              The implicit return on common equity would be 10.3%, assuming that
              the 47% equity ratio declines to a target of 45% by the third
              year. To the extent that the equity return for the electric or gas
              department exceeded 11.3%, the excess would be shared 50:50
              between shareholders and customers. Excesses over 14% would be
              allocated entirely to customers. The rate plan would be subject to
              reopening if either department's equity return fell below 8.5%.

              The benefit fund would be applied for the following purposes (in
              amounts that remain to be quantified through further negotiations,
              if not specified here):

              a.     $45 million (about $74 million, stated on a net-of-tax
                     basis), for three annual refunds of about $24 million each
                     year, to customers on a per-kWh basis;

              b.     $42.5 million as a permanent offset to electric rate base;

              c.     $13 million over three years for distribution system
                     reinforcement and increased tree trimming;

              d.     $10 million for site remediation at a former gas
                     manufacturing site in Newburgh;

              e.     recovery of stranded costs caused by competitive electric
                     rate restructuring, if consistent with Commission policy to
                     be established in other proceedings;

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       (4)    Under orders in these proceedings extending the suspension period
(issued June 25, August 29, and September 28, 2001), rates are to be set as if
the new revenue allowance had taken effect July 1, 2001.

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              f.     economic development initiatives (other than the present
                     Revitalization Rate Program), to be formulated through
                     collaboration among the parties starting November 1, 2001;
                     and

              g.     other items to be proposed through collaboration starting
                     in mid-January 2002, which might include additional
                     refunds, delivery rate mitigation after the three-year plan
                     expires, and commodity price spike mitigation.


COST ALLOCATION AND RATE DESIGN

              In lieu of the present fuel adjustment clause, a purchased power
              recovery (PPR) charge would recover energy and capacity costs that
              Central Hudson incurs to serve its remaining electric sales ("full
              service") customers. The PPR charge would be calculated separately
              for each class, rather than on a uniform per-kWh basis as the
              company had advocated.(5) A variable cost recovery (VCR) charge
              for all customers would reflect the costs and benefits associated
              with Central Hudson's remaining generating plants and independent
              power producer contracts.

              Central Hudson will have access to relatively low-cost power
              supplied by Dynegy, from the Roseton and Danskammer plants
              (under a Transition Power Agreement or TPA); and by
              Constellation, from NMP2 (under a Purchase Power Agreement or
              PPA), if NMP2 is transferred as proposed in Case 0l-E-0lll, SUPRA.
              Under the terms submitted in the joint proposal, TPA/PPA power
              would be allocated to both full service and delivery customers,
              based on each class's kWh as a percentage of total system kWh
              sales, and among customers within classes based on each customer's
              usage characteristics.

              Class electric rate decreases would range from 0.5 to 1.25 times
              the overall electric revenue decrease, as needed to reduce
              variances between class and system rates of return. For
              residential electric service,

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       (5)    In addition to the PPR, a variable cost recovery (VCR) charge
would recover non-avoidable variable energy costs, including purchases from
qualifying facilities and fuel for the company's remaining generators.

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              a.     the $7.15 monthly customer charge would increase to $12.00
                     in three steps between now and June 2004 (moving it closer
                     toward the estimated marginal per-customer cost that the
                     charge is intended to recover), with offsetting decreases
                     in other residential charges;

              b.     the space heating discount would be eliminated; and

              c.     time of use metering would continue to be offered.

              Restoration of disconnected residential electric or gas service,
              now billed at $10 for restoration during workdays and $25 after
              hours, would increase to $20 workdays and $40 after hours or, if a
              work crew is needed, $100 workdays and $140 after hours.

CUSTOMER SERVICE

              Bills could be paid by credit card.

              The service quality incentive formulas would continue to provide
              potential penalties only, without affirmative rewards for good
              service. The maximum annual disallowance would be 25 basis points
              (bp) of common equity return for customer service, 25 bp for
              electric reliability, 6 bp for gas reliability, and 3 bp for
              non-emergency gas leak repair.

              The low-income customer program would limit the monthly gas and
              electric minimum charge to $5.00 for eligible customers, and
              require that participating customers pay at least $5.00 per month
              toward arrears if a local community action agency certifies their
              ability to pay.

COMPETITIVE INITIATIVES

              To encourage retail access, Central Hudson would:

              a.     offer a single-bill format;

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              b.     bill customers for Independent System Operator (ISO)
                     ancillary services, and reimburse ESCOs for ancillary
                     charges that the ESCO pays the ISO;

              c.     develop metrics to be used in an ESCO/marketer satisfaction
                     incentive mechanism, including potentially an award of 10
                     bp on common equity, and designate an ESCO/marketer
                     ombudsman; and


              d.     improve the company's outreach program to enhance public
                     understanding of competitive options, with a potential
                     award of up to 10 bp of common equity return for a
                     successful program.

              Pending the outcome of the generic rate unbundling proceeding,(6)
              electric backout credits would be set at $.0005 (0.5 mills) per
              kWh (S.C. 13), $.002/kWh (S.C. 3), $.003/kWh (S.C. 2 demand), or
              $.004/kWh (S.C. 1, S.C. 2 non-demand, and S.C. 6) . The gas
              backout credit would be $.l5/mcf.

                                UNRESOLVED ISSUES

              The following matters require discussion here because the joint
proposal does not expressly address them or because the parties disagree.

METERING PROGRAMS

              As noted above, the joint proposal calls for collaborative efforts
to consider disposition of benefit fund amounts not immediately addressed in
today's order. According to the joint proposal, potential future uses of the
fund could include competition-related initiatives that we might designate.

              As one such initiative which we are prepared to designate now, the
company and parties should explore the development of advanced pricing and
metering offerings for a broader range of its customers, including approaches

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       (6)    Case 00-M-0504, COMPETITIVE ENERGY MARKETS AND RETAIL COMPETITIVE
OPPORTUNITIES, Order Directing Expedited Consideration of Rate Unbundling
(issued March 29, 2001).

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that would better enable customers to respond optimally to improved price
signals. Properly implemented, this initiative could result in multiple
benefits, including lower customer bills; reduced wholesale market prices due to
improved demand responsiveness; and reduced costs, to the utility and other
load-serving entities, of recording and transmitting customer usage and billing
data. In particular, the company and parties should consider:

              the potential benefits resulting from enhanced pricing offerings
              for a broad range of customers beyond those now eligible for the
              company's existing real-time pricing tariffs;

              appropriate methods for providing customers access to the
              education and control technologies that may be necessary to adjust
              their usage in response to actual market prices; and

              appropriate sources of funding for enhanced metering and meter
              reading technologies, ideally through competitive means, to
              effectively record and transmit usage and billing data among
              customers, the utility, and competitive load-serving entities.

CREDIT CARDS

              The joint proposal includes an uncontested provision that the
company would be allowed to collect bill payments by credit card. In adopting
this element of the proposal, we note that it leaves unresolved several matters
of implementation. First, we seek assurances that Central Hudson will not use
the availability of the credit card option as leverage to extract payments from
financially troubled customers for whom the payment and interest charges are not
truly affordable. Second, future determinations of the company's revenue
requirement will require recognition of cost offsets, such as reductions in
working capital and uncollectibles, resulting from credit card usage subsequent
to the three-year rate plan. Third, the joint proposal is silent regarding a
significant disagreement that arose during the litigation of this issue: whether
costs associated with the credit card option should be allocated to all
customers, or to some classes exclusively, or only as a service fee to those
customers who actually make a credit card payment. To address these concerns,
Central Hudson should provide our staff the details of any proposed

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credit card payment program before implementing it.

SERVICE QUALITY AND MARKETER SATISFACTION INCENTIVES

              Regarding the proposed service quality program and the program to
gauge marketer satisfaction, we assume the parties recognize that we need to
review the progress and results of the company's efforts periodically.
Therefore, in adopting the proposed terms, we do so with the understanding that
compliance with today's order will require an annual report concerning these
programs. The company should consult with the Director of our Office of Consumer
Education and Advocacy as to specific details of this requirement.

REFUNDS VS. RATE BASE REDUCTIONS

              OAG advocates that we reject the joint proposal's terms insofar as
they would limit the rate base reduction to $42.5 million. OAG says we should
enlarge this amount by reallocating, into additional rate base offsets, the $45
million that would be used for direct customer refunds under the joint proposal.
OAG notes that a rate base offset is permanent, while a refund is transitory.
Therefore, OAG argues, rate base offsets would be preferable, because they would
not culminate in a bill increase upon exhaustion of the benefit fund and because
their permanence assures customers a larger dollar benefit over time than any
finite amount of refunds. OAG adds that any benefit fund balance not
specifically allocated to other purposes should be applied toward immediate rate
base reductions, instead of being held in reserve pending collaborative
discussions as contemplated in the joint proposal.

              OAG misstates the comparison between rate base reductions and
refunds, and (as MI observes) misreads the RD's comments about the relative
advantages of rate base offsets and refunds. The RD regarded refunds as
preferable from the customer's standpoint, in view of tax considerations which
nearly double the effective short-term benefit to customers from refunds as
compared with rate base offsets.(7) And the customer benefit from a refund may

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       (7)    MI's analysis, uncontradicted on the record, estimates that each
dollar allocated to refunds engenders approximately a $0.40 tax savings. This
benefit is unavailable in connection with amounts allocated to rate base
reduction.

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be just as permanent as the benefit of a rate base offset, because any refund is
a potential earnings source for the customer. For these reasons, an immediate
refund may well provide a customer greater long-term economic benefits than a
rate base offset of the same dollar amount, even if (as OAG emphasizes) the rate
base offset may provide a larger long-term reduction in the customer's utility
bill. Finally, as Staff observes, the possible consequences of the massive rate
base reduction implicit in OAG's position have not been examined on the record
or addressed by the parties.(8)

              The proposed allocation from the benefit fund provides a rate base
reduction designed to stabilize rates at a slightly reduced level, provides a
similar amount in refunds, and creates the possibility of additional allocations
in the future to bill mitigation and additional refunds. Notwithstanding OAG's

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       (8)    Staff, the company, and MI object to OAG's arguments, regarding
this and other issues, on the ground that OAG raised them initially in the
second round of statements instead of the first. OAG responds that its statement
legitimately addressed the initial round of other parties' statements; the
objections to OAG's statement constitute unauthorized surreplies; and OAG's
statement cannot have come as a surprise to other parties, as it reflected
positions advocated by OAG throughout the proceeding. The parties objecting are
correct that OAG's submittal was inconsistent with the procedural schedule,
which specified that the initial round would be the occasion for both supporting
and opposing statements. Cases 00-E-l273 and 00-G-1274, Procedural Ruling
(issued August 22, 2001) . In any event, we find OAG's points unpersuasive for
reasons discussed in the accompanying text.

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comments, we find that the proposal strikes an entirely reasonable balance among
those objectives. Moreover, OAG has not shown that additional rate base
reductions are preferable to using the benefit fund for competitive initiatives,
bill mitigation, or other possible purposes besides refunds. The joint proposal
aptly calls for further collaboration to explore such options in the future, in
light of evolving circumstances which may not be clearly foreseeable now.
Meanwhile, any portion of the benefit fund not used immediately will accrue
interest at a rate equal to the company's pre-tax rate of return, thus providing
customers the same benefit as if the amount thus reserved were a rate base
offset.

BACKOUT CREDITS

              Pending the redetermination of unbundled rates in the unbundling
proceeding,(9) the joint proposal calls for backout credits of $.004 (four
mills) per kWh for S.C. 1 residential and S.C. 2 general non-demand customers.
SCMC advocates, instead, a credit of $.007/kWh for these classes. SCMC says the
larger credit is necessary because Central Hudson, with almost no retail access
penetration several years after the initial order directing its restructuring,
is in a position analogous to that of other utilities years ago when we adopted
more robust stimuli to "jump-start" competition simultaneously with
restructuring. SCMC argues that, in allowing other utilities to offer
non-volumetric, lump-sum incentive payments to retail access customers or ESCOs,
our primary objective has been to stimulate competition rather than calibrate
rates to reflect avoided costs. SCMC adds that Central Hudson has an equitable
obligation to promote competition more vigorously, because the company has
benefited from generation divestiture whose purpose was to create competition.

              However, we agree with Staff that the $.004/kWh provision in the
joint proposal is a reasonable measure at this time, given that it will be
adjusted if necessary on the basis of the record in the unbundling proceeding.
Staff notes that $.004/kWh is the same temporary proxy that we also have adopted
for other companies. Conversely (as Central Hudson observes), there is no
evidence in this case either to rebut a $.004/kWh approximation of avoided costs
or to support a $.007/kWh credit as SCMC advocates. In these circumstances,
SCMC's asserted dichotomy between encouraging competition

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       (9)    Case 00-M-0504, SUPRA.

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and gauging costs is overstated; at this moment, our most effective means of
promoting competition is to establish cost-based rates on the basis of a full
record in the unbundling proceeding.

              OAG objects in principle to any backout credits as proposed, on
the ground that such credits would subsidize retail access customers at other
customers' expense. We agree with Staff that OAG's argument errs in two
respects. First, to the extent that the benefit fund can be used to promote
competitive initiatives through measures such as backout rates, it serves the
interests of customers in general and therefore cannot properly be deemed an
unfair burden on full-service customers. Second, unless we adopt backout rates
here (at least as an interim proxy for Central Hudson's avoided costs while
awaiting more accurate cost determinations in the unbundling proceeding), it is
retail access customers that will be burdened with a subsidy, insofar as they
must continue to pay delivery rates that include costs related to the merchant
function. Thus, rather than create subsidies as OAG alleges, the backout credit
will offset them.

PPR VOLATILITY

              OAG says the proposed purchased power recovery (PPR) mechanism
should be modified so that the risk of commodity price volatility would rest
"primarily with the company" rather than with low-usage customers. OAG argues
that Central Hudson, as compared with its customers, can better avoid the
consequences of supply shortages during a transition to competition.

              OAG's criticism of the PPR is inappropriate in several respects.
First, the joint proposal already incorporates the results of efforts by Central
Hudson to mitigate volatility, by providing customers an allocation of TPA
power. Second, OAG presents no specific mechanism for carrying out its proposed
risk reallocation. Third, the joint proposal already addresses OAG's concern by
calling for further exploration of how the benefit fund might be used to
mitigate price volatility.

RETURN ON EQUITY AND NMP2 ISSUES

              Mr. Mavretich contends that there is only a superficial
resemblance between the joint proposal's 10.3% implicit return on equity and the
10.28%


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return allowance recommended in the RD, because the joint proposal's 100 basis
point deadband would allow Central Hudson to retain any earnings up to 11.3%.
Mr. Mavretich, opposed by Central Hudson and Staff, argues that the deadband
should be eliminated so that 50:50 sharing between shareholders and customers
would be applicable to any excess over 10.3%.

              This criticism of the joint proposal is a NON SEQUITUR. The
proposal's various provisions are designed to create a reasonable opportunity
for the company to earn a return of 10.3%, corresponding to the cost of equity
as indicated by the record on which the RD relied and which Mr. Mavretich seems
to invoke now. Absent any showing that adoption of the proposed terms would
produce a return greater than 10.3%, we are adopting them so as to establish
rates that reflect the cost of equity. The joint proposal's earnings sharing
provisions are not an indication that the earned return is EXPECTED to exceed
10.3%, as Mr. Mavretich suggests, but only a mechanism to reasonably balance
investor and shareholder if it does.

              As a more general matter, Mr. Mavretich supports this and his
other criticisms of the joint proposal (noted below) by arguing that we should
take into consideration Central Hudson's continuing failure to answer
interrogatories regarding the long-term costs of its alleged managerial errors
in connection with the NMP2 generating unit. The company responds by asserting a
record of managerial success. While we would not condone the company's disregard
of a discovery ruling if the issue were directly presented, here the issue is
moot in two respects. First, Central Hudson is not pursuing any challenge to the
Judge's discovery rulings, or to the RD's finding that the lack of interrogatory
responses should be construed against the company pursuant to 16 NYCRR 5.10(1)
when estimating NMP2's costs. Second, the company has abandoned its request for
an allocation from the benefit fund as a reward for exemplary performance. It
was that request which, in Mr. Mavretich's view, established the relevance of
the history surrounding NMP2 for purposes of these proceedings. Thus, the NMP2
discovery issue does not affect our assessment of the balancing of interests in
the joint proposal.(10)

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       (10)   We need not decide here whether, as Staff suggests, Mr.
Mavretich's arguments about Central Hudson's NMP2 participation "are best
addressed in Case 0l-E-00ll" (the proceeding to consider ownership transfer of
NMP2).

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STOCK SYMBOL

              Central Hudson received $2.5 million from the sale of its stock
trading symbol, after its shares ceased to be publicly traded because it became
a subsidiary wholly owned by a new parent company. Staff's litigating position,
accepted in the RD, was that the sale proceeds should be viewed as an offset to
corporate reorganization costs and that $1.0 million of the proceeds therefore
should be used to reduce rate base. Under the joint proposal, we are asked to
reject that approach and disregard the sale proceeds for ratemaking purposes.
Mr. Mavretich opposes this resolution of the issue. Staff and the company
correctly respond that Mr. Mavretich has not accurately characterized the asset
in question. Contrary to his assertions, the sale of the stock symbol did not
occur pursuant to provisions resembling those that governed the auction of the
company's generating plants. Nor is it true that the stock symbol was a rate
base item like other assets "supported through customers['] rates," as Mr.
Mavretich says; and, even if it were, we have broad discretion over the
ratemaking treatment of sale proceeds regardless of whether the asset has been
held in rate base. In this instance, there is nothing unreasonable about the
proposed allocation of the proceeds to shareholders.

RELIABILITY IMPROVEMENT PROGRAM

              Mr. Mavretich notes that the RD, in approving an infrastructure
program similar in some respects to the Reliability Improvement Program
described in the joint proposal, called for a progress report after the initial
expenditures. He criticizes the lack of a comparable reporting requirement in
the joint proposal. Central Hudson responds that the program's efficacy would be
reflected in the proposed incentive provisions related to system reliability,
while Staff points out that the joint proposal expressly provides for an annual
plan subject to Staff review. Thus, Mr. Mavretich's concern about the company's
accountability is unfounded."(11)

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       (11)   OAG raises concerns similar to Mr. Mavretich's, regarding both the
Reliability Improvement Program and the Newburgh gas manufacturing site
remediation project. In both instances, however, we expect that the company's
activities will be subject to ongoing Commission review.

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                                   DISCUSSION

              Subject to our determinations described above, we find that the
joint proposal's sponsors have satisfied their burden of showing that adoption
of the proposed terms would satisfy the Public Service Law's requirement of safe
and adequate service at just and reasonable rates. They also have shown that
implementation of their proposals would achieve a fair balance of interests
among the parties and customers, and would produce constructive results that may
not have been achievable except through a negotiated agreement.

              In particular, the rates we are establishing reasonably reflect
Central Hudson's cost of service and protect the company's financial integrity,
thus striking a fair balance between customer and investor interests; and the
proposed terms ensure rate stability for at least three years beyond the end of
the current rate plan. The economic benefits the company will have secured, in
negotiating the prices it will pay for electric output from its former
generating plants, will be allocated among customer classes in a fair and
competitively neutral fashion. To encourage progress toward retail competition
among energy suppliers in Central Hudson's service territory, the proposed terms
specify reasonable backout credits, incentives and other mechanisms to promote
cooperation between Central Hudson and ESCOs, and enhanced efforts to inform
customers about their supply options.

              The disposition of the benefit fund serves a diverse array of
customer interests, including rate stabilization and an equitable distribution
of refunds among customer classes; bill mitigation; measures to attract and
retain jobs; environmental remediation; backout credits and other competitive
initiatives; and infrastructure reinforcement to improve service reliability.
Reliability, as well as safety and service quality, also will be enhanced as a
result of new performance measures and incentive mechanisms. Low-income
customers in particular will benefit from new programs addressing their needs.

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              Finally, adoption of the proposed terms will accomplish these
goals within the context of a rate allowance consistent with an extensive record
in the litigated phase, concerning the company's revenue requirement and cost of
capital. Moreover, the proposals reflect the parties' best efforts to find a
reasonable resolution of issues that the RD identified as potentially productive
areas for further negotiation, particularly the uses of the benefit fund and the
design of cost recovery mechanisms and backout credits.

                                   CONCLUSION

              For the reasons stated, we find that our adoption of the joint
proposal's provisions subject to the discussion above will serve the public
interest and satisfy our statutory obligation to ensure safe and adequate
service at just and reasonable rates pursuant to Public Service Law ss.66. We
therefore will direct the company to file tariff revisions consistent with this
finding. To comply with the orders issued in these proceedings June 25, August
29, and September 28, 2001, the filing should be designed to implement the
tariff revisions as if they had taken effect July 1, 2001, notwithstanding the
November 1, 2001 effective date specified in Order Clause 3 (below).

THE COMMISSION ORDERS:

              1.     Subject to the foregoing discussion and the determinations
and understandings set forth therein, the terms of the Joint Proposal filed in
these proceedings August 21, 2001 are adopted in their entirety and are
incorporated as part of this order.

              2.     Central Hudson Gas & Electric Corporation (the company)
shall submit a written statement of unconditional acceptance of this order,
within five days following the order's issuance date, signed and acknowledged by
a duly authorized officer of the company. If an acceptance statement is not so
filed, the adoption of the joint proposal's terms may be revoked. The acceptance
statement should be filed with the Secretary of the Commission and served on the
parties to these proceedings.

              3.     The company is directed to cancel, no later than October
31, 2001, the tariff amendments and supplements listed in Attachment A of this

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order. The company is directed to file on not less than one day's notice, to
take effect no later than November 1, 2001 on a temporary basis, such further
tariff changes as are necessary to effectuate the provisions adopted in this
order. The company shall serve copies of its filing upon all parties to these
proceedings. Any comments on the compliance filings must be received at the
Commission's offices within ten days of service of the company's proposed
amendments. The amendments specified in the compliance filing shall not become
effective on a permanent basis until approved by the Commission and will be
subject to refund if any showing is made that the revisions are not in
compliance with this order. The requirement of ss.66(12)(b) of the Public
Service Law that newspaper publication be completed prior to the effective date
of the proposed amendments is waived, provided that the company shall file with
the Commission, not later than six weeks following the amendments' effective
date, proof that a notice to the public of the changes proposed by the
amendments and their effective date has been published once a week for four
successive weeks in newspapers having general circulation in the areas affected
by the amendments.

                                       18
<PAGE>


              4. These proceedings are continued.

                                                         By the Commission,



                 (SIGNED)                                JANET HAND DEIXLER
                                                           Secretary

                                       19
<PAGE>


                                  ATTACHMENT B







CASE            00-E-1273 - Proceeding on Motion of the Commission as to the
                            Rates, Charges, Rules, and Regulations of Central
                            Hudson Gas & Electric Corporation for Electric
                            Service.


CASE            00-G-1274 - Proceeding on Motion of the Commission as to the
                            Rates, Charges, Rules, and Regulations of Central
                            Hudson Gas & Electric Corporation for Gas Service.



                               JOINT PROPOSAL AND
                    JOINT PROPOSAL'S ATTACHMENTS A THROUGH I

<PAGE>



STATE OF NEW YORK PUBLIC SERVICE COMMISSION
 - - - - - - - - - - - - - - - - - - - - - - - - - - x

Proceeding on Motion of the Commission                           Case 00-E-l273
as to rates, charges, rules and regulations of Central Hudson
Gas & Electric Corporation for electric service;

                  and

Proceeding on Motion of the Commission                           Case 00-G-1274
as to rates, charges, rules and regulations of Central Hudson
Gas & Electric Corporation for gas service
 - - - - - - - - - - - - - - - - - - - - - - - - - - x


                                 JOINT PROPOSAL

I.     INTRODUCTION

       This is a Joint Proposal, dated as of August 15, 2001, for the resolution
of the above-captioned cases by and among the following parties and participants
("Signatories"): Central Hudson Gas & Electric Corporation ("Central Hudson" or
the "Company"); the Consumer Protection Board; Multiple Intervenors; the Staff
of the Department of Public Service ("Staff") and Strategic Power Management,
Inc.

       This Joint Proposal is the product of negotiations among parties to the
proceeding on due notice in accord with the Commission's Settlement Guidelines
and of compromises among the Signatories. It has been made on the basis of the
Conditions of the Joint Proposal described below and is intended to resolve all
issues in these proceedings.

<PAGE>


       In general, both electric and gas rates are frozen at specified delivery
rate revenue levels until June 30, 2004 and specifically identified amounts of
delivery rate revenues are deferred from July 1, 2001 through June 30, 2002
("Rate Year One" or "RY1") to July 1, 2003 through June 30, 2004 ("Rate Year
Three" or "RY3").(1) Additional provisions address enhancements of competition
in gas and electric services and establish uses and procedures for reviewing
additional uses of the "Benefit Fund."(2)

II.    JOINT PROPOSAL

       A.     Electric Rate Freeze: Electric delivery rates will be designed to
              recover $153 million in delivery revenues annually and will be
              frozen through June 30, 2004.

       B.     Gas Rate Freeze: Gas delivery rates will be designed to recover
              $36.6 million in delivery revenues annually and will be frozen
              through June 30, 2004.

       C.     Term of Electric and Gas Delivery Rate Freezes: The electric and
              gas delivery rate freezes are effective through June 30, 2004 and
              are further subject to the understandings that:

              1.     Nothing in this Joint Proposal or the Commission's adoption
                     of it is intended to prevent Central Hudson from filing
                     with the Commission requests for changes in rates to be
                     effective (after any applicable suspension) as of July 1,
                     2004;

              2.     Rate mechanisms for the pass-through of the purchase price
                     of electricity or gas are an integral part of this Joint
                     Proposal. Nothing in the rate freeze provisions of this
                     Joint Proposal is intended to preclude those mechanisms
                     from passing through the purchase prices of electricity
                     or gas.


----------
(1)    The twelve month period ending June 30, 2003 is "Rate Year Two" or "RY2."

(2)    The Benefit Fund results from Central Hudson's prior rate proceeding,
       Case 96-E-0909. See, Opinion No. 98-14, issued June 30, 1998 and Order
       Adopting Terms of Settlement Subject to Modifications and Conditions,
       issued February 19, 1998.

                                       2
<PAGE>


              3.     Central Hudson is authorized to reopen this Joint Proposal
                     if its achieved regulatory return on actual common equity
                     in either its electric or gas department (or both) falls
                     below 8.5%.

       D.     Treatment of Litigated Issues:

              1.     The Signatories have agreed to levels of delivery rate
                     revenues, which agreements are for settlement purposes
                     only, and not necessarily on the disposition of any
                     particular issue raised during the litigation, other than
                     as described in this Joint Proposal.

              2.     The terms and provisions of this Joint Proposal apply
                     solely to, and are binding only in the context of, the
                     purposes and results of the mutual agreements reflected in
                     the Signatories' settlement. None of the terms and
                     provisions of this Joint Proposal and none of the positions
                     taken herein by any party may be cited or relied upon by
                     any other party in any fashion as precedent in any
                     proceeding before the Commission, or before any other
                     regulatory agency or any court of law for any purpose
                     except in furtherance of the purposes and results of the
                     Signatories' settlement.

       E.     Income Statements

              1.     The Income Statements for Electric (Attachment A) and Gas
                     (Attachment B) services that have been attached to this
                     Joint Proposal are intended to show that the Joint Proposal
                     is reasonable and do not necessarily represent the views of
                     any Signatory.

              2.     The Income Statements attached hereto have incorporated the
                     following items:

                                       3
<PAGE>


                     a.     Return on Common Equity: An assumed return on common
                            equity of 10.3% has been agreed to as a fall out
                            from the agreed-to revenue requirements shown in the
                            Income Statements.

                     b.     Equity Ratio: 47% first year, 46% second year and
                            45% third year.

                     c.     Cost of Long-Term Debt and Redemption Premiums: As
                            shown in Attachment C, updated costs and amounts of
                            long term debt issuances, including the costs of
                            redemption, and the costs of preferred stock
                            redemption premiums and unamortized expenses, have
                            been employed in determining the revenue
                            requirements shown in the attached Income
                            Statements. Central Hudson is authorized to recover
                            the debt redemption premiums and unamortized debt
                            expense over the remaining life of the redeemed debt
                            and to recover the preferred stock redemption
                            premiums and unamortized expenses ratably over the
                            period ending 2028.

                     d.     Rate base details have been reflected on Attachment
                            H.

                     e.     Electric Loss Factor: The electric loss factor will
                            be 1.0437.

                                       4
<PAGE>


                     f.     Lost & Unaccounted For Gas: The factor for lost and
                            unaccounted for gas will be 1.025.

       F.     Agreed-to Dispositions of Specific Items and Other Conditions

              1.     Required Deferrals and Restorations of Electric Delivery
                     Revenues: As shown on the attached Electric Income
                     Statement, electric delivery revenues of $3.1 million in
                     RY1 will be deferred for restoration in RY3 without regard
                     for the amount of electric delivery revenues actually
                     received in any of the RYs. The deferrals and restorations
                     of revenues will be recognized for purposes of determining
                     regulatory earnings and regulatory return on common equity
                     (i.e., revenues in RY1 will be reduced by the deferred
                     amount and RY3 revenues will be increased by the restored
                     amount).

              2.     Required Utilization of Benefit Fund:

                     a.     An amount of $42.5 Million will be removed from the
                            Benefit Fund and will be included as a credit to
                            electric rate base for the three Rate Years.

                     b.     The credit will be applied to electric plant
                            transmission and distribution book depreciation
                            reserves in proportion to the relative book cost of
                            plant in service at August 31, 2001 for such plant
                            categories, subject to the provisions of item l3.b
                            of this Part II. F. of this Joint Proposal.

                     c.     The $42.5 Million amount will be maintained as a
                            rate base credit after the end of RY3, subject to
                            other potential treatment by order of the


                                       5
<PAGE>

                            Commission in a subsequent Central Hudson electric
                            rate case.

                     d.     This $42.5 Million rate base credit amount will be
                            recognized in calculation of the achieved regulatory
                            rate of return on common equity for the electric
                            department.

              3.     Required Deferrals and Restorations of Gas Delivery
                     Revenues: Gas delivery revenues of $0.9 million will be
                     deferred in RY1 for restoration in RY3 without regard for
                     the amount of gas delivery revenues actually received in
                     any of the three RYs. The deferral and restoration of
                     revenues will be recognized for purposes of determining
                     regulatory earnings and regulatory rate of return on common
                     equity (i.e., revenues in RY1 will be reduced by the
                     deferred amount and RY3 revenues will be increased by the
                     restored amount).

              4.     Earnings Sharing:

                     a.     There is a regulatory rate of return on common
                            equity deadband by department between 8.5% and
                            11.3%.

                     b.     In the event that Central Hudson achieves a
                            regulatory rate of return on common equity above
                            11.3% in either the electric or gas department, the
                            earnings above 11.3% and up to 14.00% in such
                            department(s) will be shared 50/50 between the
                            Company and ratepayers. The ratepayer's portion of
                            such earnings in the electric department will be
                            added to the Benefit Fund and in the gas department,
                            deferred subject to further order of the Commission.

                     c.     In the event that Central Hudson achieves a
                            regulatory rate of return on common equity above
                            14.00% in either the electric or gas department, the


                                       6
<PAGE>


                            earnings above 14.00% in the electric department
                            will be added to the Benefit Fund and in the gas
                            department, deferred subject to further order of the
                            Commission. The 14.00% value is subject to
                            adjustment pursuant to Parts IX. F. and H.

              5.     Measurement of Achieved Regulatory Rate of Return on Common
                     Equity for Earnings Sharing Purposes:

                     a.     Separate determinations of the achieved regulatory
                            rate of return on common equity for gas and electric
                            operations will be made annually, on a rate year
                            basis.

                     b.     The achieved regulatory return on common equity will
                            be measured by department on the basis of Central
                            Hudson's actual capitalization for the period being
                            measured; provided, however, that if the actual
                            equity ratio in a given RY exceeds the applicable
                            rate year target equity ratio (RY1: 47%; RY2: 46%;
                            and RY3: 45%), then the target ratio for that RY
                            will be used.

                     c.     The financial consequences of the Part VII Service
                            Quality Mechanisms, the Part V.A.2. Gas
                            Interruptible Sharing incentive and the Parts IX. F.
                            and H. incentives will be excluded in determinations
                            of regulatory rate of return on common equity.

                     d.     Within 90 days following the end of RY1, RY2 and
                            RY3, Central Hudson

                                       7
<PAGE>


                            shall provide Staff with a computation of achieved
                            regulatory rate of return on common equity by
                            department for the preceding RY period.

              6.     Reopener: Central Hudson is authorized to file for
                     increased rates for either the gas or electric department
                     anytime that the respective regulatory rate of return on
                     common equity for a trailing 12-month period, measured in
                     the fashion used for the annual RY determination, falls
                     below 8.5%.

              7.     Deferrals:

                     a.     The Company is authorized to defer the following
                            kinds of items for recovery in the next electric or
                            gas, as appropriate, base rate change or other
                            Commission-ordered disposition:

                            (1)    The Company is authorized to continue its use
                                   of deferral accounting with respect to the
                                   following expenses and costs and all other
                                   expenses and costs for which Commission
                                   authorization for deferral accounting is
                                   currently effective whether by reason of
                                   Commission order or policy of general
                                   applicability or by reason of a Commission
                                   determination with specific reference to the
                                   Company:

                                   (a)    Pension Expense under Statement of
                                          Financial Accounting Standards No. 87;

                                   (b)    Post Employment Benefits Other than
                                          Pensions under Statement of Financial
                                          Accounting Standards No.106;

                                       8
<PAGE>


                                   (c)    Interest Costs on Variable Rate Debt;

                                   (d)    Incremental costs of litigation
                                          regarding claims of exposure to
                                          asbestos at Company facilities;

                                   (e)    Research and Development costs under
                                          the Commission's Technical Release No.
                                          17.

                            (2)    Changes in accounting standards, subject to
                                   the understanding that this specific
                                   authority to defer is subject to such orders
                                   as the Commission may issue that provide for
                                   generic treatment of accounting practices;

                            (3)    Changes in federal or state regulations;

                            (4)    Force Majeure; and

                            (5)    Others addressed herein.

                     b.     All previously authorized uses of deferral
                            accounting continue and shall not terminate because
                            of the end of the term of this Joint Proposal.

                     c.     Central Hudson retains the right to petition the
                            Commission for authorization to defer extraordinary
                            expenditures not otherwise addressed by this Joint
                            Proposal.

                                        9
<PAGE>


                     d.     Additional Deferral Provisions Related to Changes in
                            Federal, State or Other Tax Laws:

                            (1)    The Signatories agree that the attached
                                   Income Statements do not reflect
                                   implementation of the tax law changes
                                   resulting from the 2000 Legislative Session.
                                   Accordingly, tax differences between the
                                   prior State Tax Laws and the 2000 Legislative
                                   enactments will be deferred, in accordance
                                   with the Commission's Order of June 28, 2001
                                   in Case 00-M-l556 for disposition as
                                   determined subsequently by the Commission.
                                   The deferral of state income taxes on
                                   earnings shall be permitted up to the sharing
                                   trigger level of 11.3%. The calculation of
                                   regulatory earnings and achieved rate of
                                   return on common equity for purposes of Parts
                                   II.F.4 and 5 shall recognize the calculation
                                   of state income tax on earnings.

                            (2)    In addition, the company is authorized to
                                   defer increases or decreases in costs related
                                   to changes in federal, state and local tax
                                   law or regulations for the period through RY
                                   3.

              8.     Net deferred debit and credit balances for the electric
                     department items shown on Attachment D-2 have been
                     reflected in the determination of the Benefit Fund.
                     Deferred debit and credit offsets for the gas department,
                     using actual deferred balances at June 30, 2001 for the
                     deferred items listed on Attachment E, will be subject to

                                       10
<PAGE>


                     balance sheet offset accounting to the extent necessary to
                     achieve a net of tax offset of zero.

              9.     Central Hudson is authorized to record electric or gas
                     revenue amounts post-June 30, 2004 subject to the
                     following:

                     a.     The annual amount recorded by department may not
                            exceed the lesser of the revenue requirement
                            deficiency for RY3 shown on Attachment A or B, as
                            appropriate, or the amount of revenues needed by
                            department to provide a regulatory rate of return on
                            common equity of 10.5% for the 12-month "RY" periods
                            subsequent to June 30, 2004.

                     b.     Estimated amounts of revenue will be recorded on a
                            monthly basis and adjusted to the final amount
                            within the above constraints in the last month of
                            the appropriate "RY" period.

                     c.     The amount of revenues that are recorded may be
                            based on the measurement of earnings for periods of
                            time that are less than a twelve month RY period.
                            Earnings for partial periods will be calculated by
                            determining the level of earnings for the twelve
                            month period ending on the date new rates are
                            established and comparing it to the level of
                            earnings required to provide a 10.5% equity return.
                            If a deficiency in earnings results, the amount of
                            revenues recorded for the partial period will be
                            determined by the ratio of sales for the partial
                            period to the sales for the twelve month period
                            ending as of the date new

                                       11
<PAGE>


                            rates are established.

                     d.     Central Hudson will submit reports showing any
                            revenues recorded under this provision, and the
                            measurement of earnings used in the calculation of
                            the revenues recorded, for each annual period beyond
                            June 30, 2004 or period of time ending on the date
                            new rates take effect. These reports will be
                            submitted no later than 90 days from the end each
                            annual period or the date when new rates take
                            effect.

                     e.     Central Hudson may charge the electric department
                            amounts accrued hereunder each month against the
                            Benefit Fund, subject to a subsequent final Order by
                            the Commission directing otherwise, in which event
                            Central Hudson shall be deemed to have fully
                            reserved its rights and nothing in this Joint
                            Proposal or Central Hudson's participation in it
                            shall be deemed to prejudice Central Hudson's
                            position.

                     f.     Central Hudson may record a regulatory asset for the
                            gas department amounts accrued hereunder each month.

                     g.     This authority continues until the earlier of June
                            30, 2006 or, with respect to electric department
                            revenue deferrals, the effective date of new base
                            electric rates as a result of a general electric
                            rate filing by Central Hudson and, with respect to
                            gas department revenue deferrals, the effective date
                            of new base gas rates as a

                                       12
<PAGE>


                            result of a general gas rate filing by Central
                            Hudson.

              10.    Common Cost Allocation Factor: 85% electric, 15% gas.

              11.    Payment By Credit Card: The Company is authorized, but not
                     required, to accept payments for service by credit card
                     from residential and small commercial customers.

              12.    The Company's accounting for the sale of its stock symbol
                     is affirmed.

              13.    Depreciation:

                     a.     The Company's electric, gas and common depreciation
                            studies and methods as presented in its initial
                            filing are accepted, except for depreciation of Gas
                            Distribution Mains, which will be based on an
                            Average Service Life of 85 years and a net salvage
                            factor of negative 60% (actual negative net salvage
                            in excess of negative 60% will be charged to
                            maintenance expense).

                     b.     A method will be developed for reducing, in the next
                            rate case after the end of the term hereof, the
                            electric book depreciation reserve so that it
                            exceeds the theoretical depreciation reserve by no
                            more than 10 percent. Any Benefit Fund amounts
                            transferred to the book depreciation reserve will be
                            excluded from the measurement of the book to
                            theoretical reserve ratio.

              14.    The amounts shown on Attachment A, B and H will be used as
                     the rate allowances for purposes of revenue matching
                     accounting or other deferral purposes as appropriate.

                                       13
<PAGE>


III.   ELECTRIC ISSUES

       A.     The Company will implement a Reliability Improvement Program,
              subject to the following conditions:

              1.     The Program will be funded up to a total of $20 Million
                     (pre-tax) over the period ending June 30, 2004.

              2.     Funding will be from the Benefit Fund.

              3.     Capital amounts funded will be removed from rate base and
                     treated as Contributions in Aid of Construction, and as a
                     result will carry a book balance of zero.

              4.     Expense amounts related to the capital projects are
                     included in the $20 Million allowance and will also be
                     funded from the Benefit Fund.

              5.     Outside contractors and labor will be used for the Program,
                     and none of the Benefit Fund-will be allocated to Company
                     labor expense.

              6.     Plans:

                     a.     An Annual Plan will be developed and reviewed with
                            Staff before the start of RY2 for the remaining two
                            years of the program.

                     b.     Central Hudson will review RY1 projects with Staff
                            on an expedited basis following approval of this
                            Joint Proposal.

                                       14
<PAGE>


       B.     The outcomes of generic Commission proceedings such as the
              Unbundling, Competitive Markets or Stand-by Rates Proceedings, and
              any others during the term of this Joint Proposal that may affect
              implementation of electric competition will be reflected
              prospectively, subject to the understanding that any stranded or
              similar costs resulting from any such proceedings, as determined
              by the Commission, may be recovered out of the Benefit Fund to the
              extent not inconsistent with any applicable Commission Order or,
              if recovery out of the Benefit Fund is inconsistent with the
              applicable Commission Order, Central Hudson shall be deemed to
              have fully reserved its rights and nothing in this Joint Proposal
              or Central Hudson's participation in it shall be deemed to
              prejudice Central Hudson's position. Nothing in this Joint
              Proposal shall be interpreted to preclude Central Hudson from
              participating in any Commission proceeding in any manner it may
              deem advisable.

IV.    ELECTRIC RATE DESIGN

       A.     Unbundling: The revenue allocation, as shown in Attachment F will
              be utilized to design rates, as amplified below.

       B.     Purchased Power Recovery ("PPR"):

              1.     Mechanism will vary by class;

              2.     Recover all commodity related costs using market prices;

                                       15
<PAGE>


              3.     Use bimonthly averaging for bimonthly billed customers;

              4.     Include uncollectibles & working capital costs; and

              5.     Be determined and reconciled monthly.

       C.     Variable Cost Recovery ("VCR"): This mechanism will be reconciled
              monthly and will recover the costs of ancillary services and the
              variable costs and benefits of the Company's remaining generating
              facilities.

       D.     Central Hudson has entered into a Transition Power Agreement
              ("TPA") with Dynegy that provides for the purchase and sale of
              specified amounts of power to Central Hudson. The TPA was approved
              by the Commission in an Order issued December 20, 2000 in Case
              96-E-0909. In addition, Central Hudson has entered into a Purchase
              Power Agreement ("PPA") with Constellation that provides for the
              purchase and sale of specified portions of the output of Nine Mile
              Point 2 ("NMP2"). The PPA has been filed with the Commission in
              Case 01-E-0111 and that Case is currently pending before the
              Commission. The prices in the TPA and PPA will not necessarily
              equal the market prices and the differences are referred to herein
              as "TPA and PPA Benefits." The TPA and PPA Benefits will be
              apportioned to full service and delivery customers as follows:

                                       16
<PAGE>


              1.     TPA and PPA Benefits will be apportioned among service
                     classes on the basis of each class's sales (kWh) as a
                     portion of the total system sales (kWh) in a given month;

              2.     Within a given class, TPA and PPA Benefits will be
                     apportioned among customers on the basis of relative usage
                     in a month as a portion of the total class usage;

              3.     Central Hudson shall have no obligation, other than as
                     specifically provided for herein, to track the amount of
                     any TPA and PPA Benefits by individual customer. In Service
                     Classifications 3 and 13, the TPA and PPA Benefits will be
                     subject to the constraints that:

                            (1)    The total TPA and PPA Benefits credited to a
                                   customer will not exceed the total Central
                                   Hudson delivery charges for that customer in
                                   a billing period; and

                            (2)    Any TPA and PPA Benefits not received by a
                                   customer due to operation of the above
                                   constraint will be reallocated to that
                                   customer in the subsequent billing period. In
                                   any such reallocation, the constraint that
                                   the total TPA and PPA Benefits not exceed the
                                   total Central Hudson delivery charges in the
                                   billing period will continue to be applicable
                                   and may entail reallocation to subsequent
                                   billing periods.

                                       17
<PAGE>


       E.     Billing Format: Separate line items will be provided for the
              following items:

              1.     PPR;

              2.     PPR under/over recovery;

              3.     VCR;

              4.     TPA/PPA Benefits; and

              5.     System Benefit Charge ("SBC").

       F.     Cost of Service Study & Revenue Allocation

              1.     The rate changes will be allocated as follows:

                     a.     Service classifications which have a rate of return
                            below the lower tolerance level of 85% of the system
                            average would receive a minimum decrease of 0.5
                            times the average overall decrease.

                     b.     Service classifications which have a rate of return
                            exceeding the upper tolerance of 115% of the system
                            average would receive a maximum decrease of 1.25
                            times the average overall decrease.

                     c.     Application of these maximum and minimum decreases
                            results in revenues different from the rate decrease
                            revenue. This difference is allocated to the
                            unconstrained decreases for S.C. 1, S.C. 2, S.C. 5
                            and S.C. 13 -Transmission.

              2.     Peaker & Hydro Costs: The investment in combustion turbine
                     production plant is classified as demand-related. The
                     investment in hydroelectric production plant is classified
                     as energy-related.

              3.     The marginal customer cost for S.C. 1 is $23.67 per month
                     and for S.C. 2 is $32.79 per month.

              4.     Rate design for S.C. 13 will include flat energy charges, a
                     single basic monthly demand charge and a $500/month
                     customer charge.

                                       18
<PAGE>


       G.     Customer Charges

              1.     S.C.l residential customer charges will increase from the
                     current $7.15 to $9.75 for RY1 and RY2 and to $11.50 after
                     RY2 until June 29, 2004. On June 30, 2004 the customer
                     charge will be increased to $12.00.

              2.     S.C.2 small commercial (non-demand) customer charge will
                     increase from the current $6.25 to $12 for RY1 to $13 for
                     RY2 and to $14 for RY3.

              3.     The above changes will be made on a revenue neutral basis
                     within the affected customer classes.

              4.     The remaining monthly customer charges are as follows: S.C.
                     2 Secondary Demand: $20.00; S.C. 2 Primary Demand: $80.00;
                     S.C. 3: $250 and S.C. 6: $12.00.

              5.     All customer charges agreed to herein are without prejudice
                     to the filing by the Company of superseding rate change
                     filings, effective after June 30, 2004.

       H.     Time of Use ("TOU") & Space Heating Rates

              1.     Continue offering S.C. 6 residential TOU.

              2.     Elimination of S.C. 12 commercial TOU.

              3.     Elimination of S.C. 2 heating discount.

                                       19
<PAGE>


       I.     Charges for restoration of service to the same customer at the
              same meter location within twelve months of discontinuation of
              service will be as shown below.

              During Normal Work Hours:

              Without Line or Gas Crew             $ 20.00

              With Line or Gas Crew                $100.00

              Outside Normal Work Hours:

              Without Line or Gas Crew             $ 40.00

              With Line or Gas Crew                $140.00

       J.     Treatment of Central Hudson's NMP2 Costs:

              1.     The existing ratemaking for Central Hudson's NMP2 costs,
                     approved by the Commission effective February 1, 2001
                     includes two components: a Competitive Transition Charge
                     ("CTC") (reflecting property taxes and certain O&M costs),
                     and variable cost recovery through the existing ESC.

              2.     Upon the effectiveness of the rates produced by this Joint
                     Proposal, Central Hudson's NMP2 costs will be recovered
                     through three components: a CTC, the PPR and the VCR.

                     a.     Until such time as the Commission approves the
                            pending PSL ss.70 asset transfer and the closing for
                            Central Hudson's NMP2 interests takes place:

                            (1)    the CTC will recover NMP2 property tax and
                                   fixed O&M elements (hydro and GT costs will
                                   be recovered through base rates);

                                       20
<PAGE>


                            (2)    The PPR will recover the market price of
                                   Central Hudson's share of the power produced
                                   at NMP2; and

                            (3)    The VCR will recover transmission costs, ISO
                                   charges, and recover/pass back the difference
                                   between the market price and the variable
                                   production costs of Central Hudson's share of
                                   NMP2 output.

                     b.     After the Commission approves the pending PSL ss.70
                            asset transfer and the closing for Central Hudson's
                            NMP2 interests takes place:

                            (1)    The CTC will cease.

                            (2)    The PPR will reflect the Market Price of
                                   Central Hudson's share of the power produced
                                   at NMP2 under the NMP2 PPA.

                            (3)    The VCR will recover transmission costs and
                                   ISO charges.

                            (4)    The TPA/PPA Benefits will recover/pass back
                                   the difference between the market price and
                                   the costs of the PPA for Central Hudson's
                                   share of NMP2 output.

V.     GAS RATE ISSUES

       A.     Revenue Sharing

              1.     The imputation for interruptible and electric generation
                     sales is set at $1,900,000.

                                       21
<PAGE>


              2.     Accounting:

                     a.     Each August, the Company will reconcile the annual
                            IT profit received in the prior RY. Profit realized
                            by the Company pursuant to this mechanism will be
                            excluded from any determination of achieved
                            regulatory rate of return on common equity.

                            (1)    If the Company's IT profits exceed the annual
                                   imputation of $1,900,000, the sharing
                                   mechanism will be as follows:

                                   (a)    From $1,900,000 up to $2,299,999:
                                          Profit will be shared in an 85%
                                          customer/15% shareholder ratio;

                                   (b)    Profit above $2,300,000 will be shared
                                          in an 80% customer/20% shareholder
                                          ratio.

                            (2)    If the Company's IT profits are less than the
                                   annual imputation of $1,900,000, the sharing
                                   mechanism will be as follows:

                                   (a)    From $0 up to $1,499,999 in IT
                                          revenue, the short-fall below
                                          $1,900,000 will be borne by the
                                          Company;

                                   (b)    From $1,500,000 up to $1,899,999 the
                                          short-fall below $1,900,000 will be
                                          shared in an 15% shareholder/85%
                                          customer ratio.

                     b.     In addition, the Company shall be permitted to
                            attempt to minimize


                                       22
<PAGE>


                            potential monthly short-falls or over collections
                            through the Gas Supply Charge ("GSC"):

                            (1)    Each month the Company will compare the
                                   profit received from customers taking service
                                   under Service Class NOS. 8, 9 and 14 ("IT
                                   Profit": to $158,333 (1/12 of the annual
                                   imputation of $1,900,000), and

                            (2)    If the IT Profit differs significantly from
                                   the monthly imputation, the Company may
                                   refund or surcharge, as appropriate, through
                                   the GSC in a subsequent month.

       B.     Agreed-to Dispositions of Specific Gas Items:

              1.     Gas Manufacturing Site Remediation

                     a.     Write off Newburgh site costs from Benefit Fund.

                     b.     Case 95-M-0874 requirements remain in force for
                            Newburgh site.

              2.     The prudence of the Company's gas purchasing policies and
                     load management practices prior to the date of this Joint
                     proposal have been reviewed and have not been challenged in
                     these proceedings.

                                       23
<PAGE>


VI.    GAS RATE DESIGN

       A.     Unbundling and GSC

              1.     The GSC mechanism will recover all commodity related and
                     upstream pipeline demand costs.

              2.     The GSC will be determined monthly and reconciled annually.

              3.     The GSC will include uncollectibles, working capital and
                     carrying costs on cash working capital requirements and
                     materials and supplies.

       B.     S.C. 9 Customers Eligible for S.C. 11: The Company's current rate
              design methodology, which uses the load factors of existing
              customers to establish the price caps, will remain in effect.

       C.     Minimum Charge and Tail Blocks: The minimum charges in firm
              Service Classification Nos. 1,2,6,12 and 13 are increased to
              $7.20. To offset the increase in the minimum charge, the second
              block of S.C.1 and 12 has been reduced and the third block of S.C.
              2, 6 and 13 has been reduced. No rate changes are made to current
              tail block prices.

                                       24
<PAGE>


VII.   SERVICE QUALITY MECHANISMS

       A.     Customer Service Quality Program:

              1.     Twenty-five basis point total potential penalty on combined
                     Company basis, per calendar year commencing January 1,
                     2002.

                     a.     Of the twenty-five basis point total, twelve and
                            one-half basis points are for the PSC Complaint Rate
                            (12.5 basis points) and

                     b.     twelve and one-half basis points (12.5 basis points)
                            are for the Customer Satisfaction Index ("CSI").

              2.     PSC Complaint Rate:

                     a.     Targets and penalties for the PSC Complaint Rate
                            (chargeable complaints per 100,000 customers, based
                            on a 12-month rolling average at the end of each
                            performance period) follow:

                                       25
<PAGE>

                            Penalty                                     To a PSC
                            Basis         From a PSC Complaint         Complaint
                            Points              Rate of                 Rate of
                            ----------------------------------------------------
                            None                   0                     <6.0
                            2.5    (is greater than or equal to)  6.0    <6.5
                            5.0    (is greater than or equal to)  6.5    <7.0
                            7.5    (is greater than or equal to)  7.0    <7.5
                            10.0   (is greater than or equal to)  7.5    <8.0
                            12.5   (is greater than or equal to)  8.0

                     b.     The PSC Complaint Rates set forth above are
                            predicated upon existing PSC practices and
                            procedures for chargeable complaints per 100,000
                            customers. In the event of a change to those
                            practices and procedures, the Signatories will
                            discuss in good faith whether alteration of the
                            above target and penalty levels are appropriate to
                            maintain the incentive to the Company at levels
                            comparable to those above. Any disputes will be
                            referred to the Commission.

              3.     CSI:

                     a.     The CSI will be based on the calculations performed
                            by Central Hudson consistent with the procedures
                            adopted as a result of Case 96-E-0909.

                     b.     Targets and penalties for the CSI follow:

                                       26
<PAGE>


                            Basis
                            Point
                            Penalty           CHGE CSI From                To
                            -------------------------------------------------
                            None      (is greater than or equal to)  83    NA
                            3.125     (is greater than or equal to)  82   <83
                            6.25      (is greater than or equal to)  8l   <82
                            9.375     (is greater than or equal to)  80   <81
                            12.5                Below  80

              4.     For purposes of this Joint Proposal, the performance
                     periods are the calendar years ending December 31, 2002 and
                     2003 and the six months ending June 30, 2004 (for which the
                     basis point penalties will be penalties will be halved).

              5.     The "Appointments Kept" incentive remains at $20 per missed
                     appointment.

       B.     Electric Reliability

              1.     Twenty-five (25) basis point total potential penalty on
                     electric operations, per calendar year commencing January
                     1, 2002.

                     a.     Of the twenty-five basis point total, twelve and
                            one-half basis points (12.5 basis points) are for
                            SAIFI and

                     b.     twelve and one-half basis points (12.5 basis points)
                            are for CAIDI.

              2.     SAIFI indices and penalties, as shown below:

                            >1.10     6.25 basis point penalty
                            >1.20     12.5 basis point penalty

              3.     CAIDI indices and penalties, as shown below:

                            >2.10     6.25 basis point penalty
                            >2.20     12.5 basis point penalty

                                       27
<PAGE>


              4.     The SAIFI and CAIDI indices are based on electric service
                     interruptions that are not related to major storms.

                     a.     The initial SAIFI index levels will be reduced by 2%
                            from 2002 to 2003 and by 4% from 2003 to 2004.

                     b.     The Company may petition for appropriate adjustment
                            to the final CAIDI and SAIFI indices for each
                            performance period to recognize the effects, if any,
                            of Outage Management System ("OMS") implementation
                            or interventions by the ISO or similar authority
                            causing service interruptions.

              5.     For purposes of this Joint Proposal, the performance
                     periods are the calendar years ending December 31, 2002 and
                     2003 and the six months ending June 30, 2004 (for which the
                     basis point penalties will be halved).

              6.     Penalties will be calculated with respect to electric
                     operations.

       C.     Gas Reliability

              1.     Number of One-Call Ticket Mis-marks per Thousand One Call
                     Tickets.

                                       28
<PAGE>


                     Basis Point        From                       To
                     Penalty      Mis-marks/1000 of         Mis-marks/1000 of
                     --------------------------------------------------------
                     Zero           0                             1.25
                     2              1.26                          1.45
                     3              1.46                          1.65
                     6              1.66 or higher

              2.     Penalties will be calculated with respect to gas
                     operations. Mis-marks will be determined based on Central
                     Hudson's current procedures, including recognition of the
                     Tolerance Zone as defined in 16 NYCRR Part 753-1.2(t).

              3.     The measurement periods will be the calendar years ending
                     December 31, 2002 and 2003 and the six months ending June
                     30, 2004. The basis point penalty applicable to the six
                     month period ending June 30, 2004 will be one-half of that
                     set forth in the above table.

       D.     Gas Leak Management:

              1.     Applicable to Type 3 leaks only;

              2.     Penalty-only plan over the three year term. No penalty for
                     Type 3 leak inventory levels at or below 362 at December
                     31, 2002, 337 at December 31, 2003 or 325 at June 30, 2004
                     or in any calendar year in which 140 or more Type 3 leak
                     repairs are completed. In addition, no

                                       29
<PAGE>


                     penalty will be applicable to the six months ending June
                     30, 2004 if 70 or more Type 3 leak repairs are completed in
                     that time period.

              3.     A penalty of 3 basis points is applicable to gas operations
                     in any calendar year in which 140 Type 3 leak repairs are
                     not completed and the specified Type 3 inventory level is
                     not achieved (362 at Y.E. 2002 or 337 at Y.E. 2003). A
                     penalty of 1.5 basis points is applicable to gas operations
                     in the six months ending June 30, 2004 if 70 Type 3 leak
                     repairs are not completed and the specified Type 3
                     inventory level (325) is not achieved.

              4.     If, in any year during the term of this Joint Proposal the
                     target level for Type 3 leak inventory is not met, but a
                     penalty is not due because 140 Type 3 leak repairs were
                     completed, the leak inventory target level for the
                     subsequent year shall be 25 less than the actual ending
                     inventory level for that prior period.

       E.     Central Hudson will, by March 31, 2003 and 2004 and by September
              30, 2004, file a report or reports on its performance under each
              of the above incentive programs during the prior performance
              period, with the format and contents to be developed in
              collaboration, commencing on or about November 1, 2001, between
              the Company and Staff.

       F.     The Service Quality Incentive Plan of Case 96-E-0909 is extended

                                       30
<PAGE>


              from July 1, 2001 to and including December 31, 2001.

VIII.  LOW INCOME PROGRAM

       A.     The Company will implement a Low Income Program consistent with
              Attachment G.

       B.     The costs of the program, funded out of the revenue requirements,
              will be limited to the expense allowances shown on Attachments A
              and B. In the event that the costs of the program differ from
              those levels, the difference will be deferred and, after review,

              1.     Any electric shortfall will be added to the Benefit Fund
                     and any gas shortfall will be returned to customers through
                     the GSC and;

              2.     Any electric excess will be recovered from the Benefit Fund
                     and any gas EXCESS will be recovered through the GSC.

       C.     Commencing on or about November 1, 2001, the Company and Staff
              shall collaborate in the development of any program reporting
              requirements, with the Commission resolving any disputes over
              those requirements.

IX.      COMPETITIVE ISSUES

       A.     Consolidated Bills will be made available per the May 18, 2001


                                       31
<PAGE>


              Billing Proceeding Order.

       B.     Single Bill: Central Hudson will pursue offering a Single Bill
              using the Rate Ready format. In order to utilize this option, each
              ESCO OR marketer must provide Central Hudson monthly with the
              Central Hudson customer account number and a billing rate per kWh
              or CCF for each customer in sufficient time in advance (minimum
              period to BE established) of the billing dates set forth on
              Central Hudson's web site. Central Hudson will comply with the
              criteria established in the Billing Proceeding Order and ED1
              Proceeding related to single bills.

       C.     Ancillary Services: The Company will bill all delivery customers
              for ancillary services commencing three months after Commission
              approval of this Joint Proposal. This non-by-passable charge will
              be collected from customers through the Variable Cost Recovery
              factor. Central Hudson will reimburse ESCOs for ancillary service
              charges incurred to serve Central Hudson load.

              1.     Each ESCO serving load in Central Hudson's retail access
                     program must provide the Company with a copy of its NYISO
                     bill which identifies the ancillary services for the ESCO's
                     Central Hudson load served (PTID) within a day of billing
                     by the NYISO. The invoice provided by the ESCO must detail
                     the load (kWh), rate for each service and total amount
                     requested for reimbursement.

                                       32
<PAGE>


              2.     Bills and credits issued by the NYISO to the ESCO for prior
                     periods must also be provided to Central Hudson in the
                     month received by the ESCO. Central Hudson will be
                     authorized to collect all such amounts through its VCR.
                     Reimbursement to ESCOs by Central Hudson for ancillary
                     service charges will be made prior to the date ESCOs are
                     required to pay the NYISO for such charges.

              3.     The Company reserves the right to file a petition with the
                     Commission to modify this process, including potentially
                     terminating billing or reimbursing ESCOs for NYISO
                     ancillary services.

       D.     Electric Back Out Credits: Credit levels would be set at 0.5 mills
              per kWh for S.C. 13 customers; 2.0 mills per kWh for S.C. 3
              customers; 3.0 mills per kWh for S.C. 2 demand customers; and 4
              mills per kWh for S.C. 2 non-demand, S.C. 6 and S.C. 1 customers
              pending the outcome of the Unbundling Proceeding and are subject
              to being superseded by the Unbundling Proceeding as provided for
              in Part III.B. hereof. Prior to that time, the cost of the credits
              will be recovered from the Benefit Fund, subject to a penetration
              limit of 20% of electric customers. If it appears likely that the
              20% penetration level will be exceeded, the penetration level and
              recovery mechanism will be reviewed.

       E.     Gas Merchant Back Out Credit: The gas merchant function back-out
              credit will be set at $.15 per mCf pending the outcome of the
              Unbundling Proceeding, and is subject to being superceded by the
              Unbundling Proceeding as provided for in Part III.B hereof. Prior
              to that

                                       33
<PAGE>


              time, the cost of the credit will be recovered through the GSC,
              subject to a penetration limit of 20% of gas customers. If it
              appears likely that the 20% penetration level will be exceeded,
              the penetration level and recovery mechanism will be reviewed.

       F.     ESCO & Marketer Satisfaction Mechanism

              1.     ESCO/Marketer Satisfaction Survey: After consultation
                     between Staff and the Company, a survey will be developed
                     as a baseline for an incentive mechanism.

              2.     The survey metrics would include the performance of the
                     Company in satisfying the terms of the UBP and other
                     operational arrangements (e.g., GTOP) between it and ESCOs
                     (electric) and marketers (gas) . The survey should include
                     relevant questions for both ESCOs and gas marketers.

              3.     The survey would be implemented on an annual basis by an
                     objective third party selected after consultation
                     commencing on or about November 1, 2001 between Staff and
                     the Company.

              4.     Prior to implementation of the survey, Staff and the
                     Company will agree to a threshold number of participating
                     marketers as a basis for implementation of an incentive
                     mechanism. If the threshold number of marketers
                     participate, an incentive allowing the Company to receive
                     up to 10 basis points of earnings in excess of 11.3% on a
                     combined

                                       34
<PAGE>


                     Company basis will be implemented after the baseline
                     results are available. In this event, the overall earnings
                     cap will also be increased by ten basis points.

              5.     Once the results of the satisfaction survey are available,
                     the company will have 60 days to report to Staff and
                     interested parties on how it plans to address marketer
                     concerns, if any, that were expressed in the survey.

       G.     The Company will consult with Staff concerning the suitability of
              potential aggregation initiatives within the Central Hudson
              service territory, subject to the funding provisions of Part X.G.

       H.     Electric and Gas Outreach and Education Mechanisms

              1.     Improvements in outreach and education (O&E), to increase
                     customer awareness and understanding of energy competition,
                     will be measured by using Central Hudson's existing
                     residential survey.

              2.     The survey will be enhanced for better measurement of
                     awareness and understanding, according to a list of
                     criteria that will be established after consultation
                     commencing on or about November 1, 2001 between the Company
                     and Staff. A method to evaluate the awareness and
                     understanding of energy competition among small commercial
                     customers will be established.

                                       35
<PAGE>


              3.     An incentive allowing the Company to receive up to 10 basis
                     points of earnings in excess of 11.3% on a combined company
                     basis will be implemented, based on criteria, developed
                     through consultation commencing on or about November 1,
                     2001 between the Company and Staff, for measuring
                     improvements in customer awareness. In this event, the
                     overall earnings cap will be increased by 10 basis points.

       I.     Small Customer Aggregation: The potential funding of aggregation
              initiatives will be considered in the Benefit Fund Review process.

       J.     ESCO/marketer Ombudsman: The company will designate a
              vice-president level ombudsman to address ESCO/marketers'
              unresolved concerns and serve as a liaison with marketers.

X.     BENEFIT FUND

       A.     The total amount of the Benefit Fund is currently estimated at
              $164 million, including an assumed $36.5 million in net gain from
              a sale of NMP2, or $127.5 Million excluding the estimated NMP2
              gain. The components have been shown in Attachment D-l.

       B.     The Signatories have agreed upon the following general approach:
              Allocate a portion of the fund to "Identified Uses" and reserve
              the

                                       36
<PAGE>


              remainder, future NMP2 gain and any unutilized portion of the
              Identified Uses to annual collaborations. The Identified Uses are
              further defined as "Quantified Identified Uses" and
              "Non-Quantified Identified Uses."

       C.     The "Quantified Identified Uses" of the Benefit Fund are (net of
              tax):

              1.     Rate base offset - $42.5 Million;

              2.     Gas site remediation - $10 Million;

              3.     Reliability Improvement Program - $13 Million; and

              4.     Refunds: $l5 Million per RY.

       D.     The Non-Quantified Identified Uses of the Benefit Fund are:

              1.     Other items provided for in this Joint Proposal, including
                     possible additional customer refunds, offset to potential
                     post-June 30, 2004 electric rate increases, back out
                     credits and future stranded or similar costs subject to the
                     provisions of Part III.B hereof; and

              2.     Economic Development - to be developed and dispensed in
                     accordance with below discussion.

       E.     Refunds: The total net of tax amounts for the three RYs of $45
              Million, as shown on Attachment D-l, will be refunded to customers
              through a per kWh credit, commencing in the month following the
              Commission's approval of this Joint Proposal. The credit will be
              developed from the total RY billing units, prorated for the total
              number of months until

                                       37
<PAGE>


              June 30, 2004 following the Commission's approval of this Joint
              Proposal. Central Hudson will track and reconcile the amounts
              credited. In the event that the entire $45 Million is not credited
              prior to June 30, 2004, the un-dispensed credit will be carried
              forward subject to further order of the Commission.

       F.     A carrying charge at an annual rate equal to the pretax-rate of
              return set forth on Attachment C will be applied monthly to the
              net remaining balance in the Benefit Fund.

       G.     Other Potential Uses of Net Benefit Fund

              1.     Potential uses include possible future use for price spike
                     mitigation; for small customer aggregation efforts; and to
                     fund such other competitive-related initiatives as the
                     Commission may approve.

              2.     These uses would be addressed in the Benefit Fund Review
                     discussed below.

              3.     Benefit Fund Review Process: On or about January 15, 2002,
                     and 2003 a collaborative effort will commence on the use of
                     the remaining Benefit Pool amounts not otherwise allocated
                     to specific purposes. The collaborative will be completed
                     and reported to the Commission by April 1, 2002 and 2003.
                     The Commission will expedite its review of the
                     Collaborative Report (and any dissents).

                                       38
<PAGE>


       H.     Economic Development

              1.     An Economic Development Program will be established and
                     funded from the Benefit Pool in accordance with the
                     procedure set forth below. The program's purposes would be
                     to encourage the relocation, growth, expansion, and
                     retention of business customers in the Company's service
                     territory and include consideration of any situations in
                     which reductions in employers' substation costs will lead
                     to employee retention.

              2.     The administration of the program would be facilitated by
                     Staff, through consultation commencing on or about November
                     1, 2001 among the Company, the Empire State Development
                     Authority, local government officials and interested
                     parties. Tariff provisions, guidelines and procedures would
                     be developed as appropriate in that consultation and would
                     be submitted to the Commission for approval.

              3.     Existing electric programs will be terminated with the
                     exception of the Revitalization Rate.

              4.     Revitalization Rate:

                     a.     Current electric customers will receive their
                            existing discounts until the time set for expiration
                            in their existing agreements.

                                       39
<PAGE>


                     b.     For new customers, a rate discount would be offered
                            on the delivery rate for those who meet the existing
                            program's criteria.

                     c.     The discounts would be set at percentage levels
                            comparable to those in the existing program, but
                            applied to the delivery prices.

                     d.     The discounts will be funded from the Benefit Fund.

                     e.     Customers receiving the rate would be contacted in
                            writing 6 months prior to the end of their
                            Revitalization Rate term informing them of the
                            expiration and providing them with a contact at the
                            Company to answer any questions or concerns.

XI.    CONDITIONS OF JOINT PROPOSAL

       A.     This Joint Proposal is intended by the Signatories to be a
              complete resolution of all issues in Cases 00-E-1273 and
              00-G-l274. Each Signatory is obliged to support the Joint Proposal
              before the Commission. The Signatories to the Joint Proposal agree
              that the provisions of the Joint Proposal are, in aggregate, a
              reasonable resolution of each of the proceedings.

                                       40
<PAGE>


       B.     It is understood that each provision hereof is in consideration
              and support of all the other provisions, and each Signatory has
              expressly conditioned its support upon the acceptance of this
              Joint Proposal in its entirety by the Commission. In the event
              that the Commission proposes to alter any provision of the Joint
              Proposal, no Signatory has any further obligation relative to the
              Joint Proposal other than the obligation to discuss in good faith
              with the other Signatories whether any such alteration is
              acceptable to it. In addition, Staff will make its best efforts to
              present to the Commission by September 25, 2001, the Company's
              Petition of May, 2001, as updated, in Case 01-M-0323.

       C.     In the event that the Commission alters any provision of the Joint
              Proposal, each Signatory will be deemed to have fully reserved its
              rights to contest the altered Joint Proposal, and any such
              alteration. In the event that the Commission fails to adopt this
              Joint Proposal according to its terms, then each Signatory shall
              be free to pursue its respective positions in this proceeding,
              without prejudice, upon reasonable notice to the other
              Signatories. This Joint Proposal is an integrated whole, with each
              provision in consideration for, in support of, and dependent on
              the others. Thus, if the Commission does not approve this Joint
              Proposal in its entirety without modification, each of the
              Signatories reserves the right to withdraw its participation and
              support by serving written notice on the Commission and the other
              Signatories and, if necessary, to litigate, without prejudice,


                                       41
<PAGE>


              any or all issues as to which such signatory agreed in this Joint
              Proposal; in such event, any such Signatory shall not be bound by
              the provisions of this Proposal, as executed or as modified.

       D.     In the event of any disagreement over the interpretation of this
              Proposal or the implementation of any of the provisions hereof,
              which cannot be resolved informally among the Signatories, such
              disagreement shall be resolved in the following manner: The
              Signatories shall promptly convene a conference and in good faith
              shall attempt to resolve such disagreement. If any such
              disagreement cannot be resolved by the Signatories, a Signatory
              may petition the Commission for relief on a disputed matter.

       E.     This Joint Proposal represents a negotiated agreement and
              settlement and, except as otherwise expressly stated herein, none
              of the Signatories shall be deemed to have approved, agreed to, or
              consented to any principle, methodology, or interpretation of law
              underlying or supposed to underlie any provision hereof, and this
              Joint Proposal shall not be cited or relied upon with respect to
              any matters other than those specifically addressed herein.

       F.     The Signatories recognize that certain provisions hereof require
              that actions be taken in the future to effectuate fully the
              agreements and compromises set forth in this Joint Proposal.
              Accordingly, each Signatory agrees to cooperate with each other
              Signatory in GOOD faith in taking such actions.

       G.     Survival of Conditions: All reservations of rights of any
              Signatory (including, but not limited to, Parts XI.A. through
              XI.F., inclusive), the continuation of deferral accounting
              authority, the post-June


                                       42
<PAGE>


              30, 2004 revenue deferral provisions, the provision concerning
              development of a method for reducing the book to theoretical
              depreciation reserve, and the Benefit Fund provisions shall
              survive the June 30, 2004 term of this Joint Proposal.

       H.     The Supplemental Environmental Assessment Form attached hereto as
              Appendix I accurately describes the potential environmental
              impacts, if any, that could result from implementation of the
              terms of this Joint Proposal, and the Commissions' determination
              of significance regarding this Joint Proposal should be the
              adoption of a negative declaration.

       I.     All titles, subject headings, section titles and similar items are
              provided for the purpose of reference and convenience only and are
              not intended to affect the meaning, content or interpretation of
              this Joint Proposal.

       J.     The Commission reserves the authority to act on the level of the
              company's base electric and gas rates in the event of unforeseen
              circumstances that, in the Commission's opinion, have such a
              substantial impact on the range of earnings levels or equity costs
              envisioned by this Joint Proposal as to render the company's
              return unreasonable or insufficient for the provision of safe and
              adequate service at just and reasonable rates and in the event
              that the Commission exercises such authority as it possesses in
              that regard, each Signatory reserves its rights and no Signatory
              shall be bound or prejudiced by its entry into, or performance
              under, this Joint Proposal.

       K.     Submission of Settlement: This Joint Proposal is being executed


                                       43
<PAGE>


              in counterpart originals and shall be binding on each Signatory.
              Each person executing this Joint Proposal represents by his or her
              signature that he or she has full authority to bind his or her
              principal. The Signatories hereto agree to submit this Joint
              Proposal to the Commission and individually to support and request
              adoption by the Commission of their mutual settlement as set forth
              herein.

       WHEREFORE, this Joint Proposal has been agreed to by and among each of
the following, who, by its signature, each represents that it is fully
authorized to execute this Joint Proposal and, if executing this Joint Proposal
in a representative capacity, that it is fully authorized to execute it on
behalf of its principals.


                                       44
<PAGE>


                                 SIGNATURE PAGE

       The undersigned party to Public Service Commission Case Nos. 00-E-1273
and 00-G-1274 has participated in the negotiations among the parties which led
to the Joint Proposal dated August 15, 2001 and agrees to the provisions of such
Joint Proposal.

                                  Central Hudson Gas & Electric Corporation

                                  By:     /s/ ARTHUR R. UPRIGHT
                                      ------------------------------------------
                                            Arthur R. Upright

Dated: August 15, 2001

<PAGE>


                                 SIGNATURE PAGE

       THE UNDERSIGNED PARTY TO PUBLIC SERVICE COMMISSION CASE NOS. 00-E-1273
AND 00-G-1274 HAS PARTICIPATED IN THE NEGOTIATIONS AMONG THE PARTIES WHICH LED
TO THE JOINT PROPOSAL DATED AUGUST 15, 2001 AND AGREES TO THE PROVISIONS OF SUCH
JOINT PROPOSAL.

                                                      Consumer Protection Board


                                                      By: /s/ C. ADRIENNE RHODES
                                                          ----------------------

                                                          C. Adrienne Rhodes

Dated: August 17, 2001

<PAGE>


                                 SIGNATURE PAGE

       The undersigned party to Public Service Commission Case Nos. 00-E-1273
and 00-G-l274 has participated in the negotiations among the parties which led
to the Joint Proposal dated August 15, 2001 and agrees to the provisions of such
Joint Proposal.

                                   Multiple Intervenors

                                   By:  /s/ MICHAEL B. MAGER
                                        ----------------------------
                                            Michael B. Mager, Esq.
                                            Couch White, LLP
                                            Attorneys for Multiple Intervenors




          Dated: August 17, 2001

<PAGE>


                                 SIGNATURE PAGE

       The undersigned party to Public Service Commission Case Nos. 00-E-l273
and 00-G-1274 has participated in the negotiations among the parties which led
to the Joint Proposal dated August 15, 2001 and agrees to the provisions of such
Joint Proposal.

                                       Staff of the Department of Public Service

                                       By:     /s/ LEONARD VAN RYN
                                          --------------------------------------
                                                   Leonard Van Ryn

Dated: August 20, 2001

<PAGE>


                                 SIGNATURE PAGE


       The undersigned party to Public Service Commission Case Nos. 00-E-l273
and 00-G-l274 has participated in the negotiations among the parties which led
to the Joint Proposal dated August 15, 2001 and agrees to the provisions of such
Joint Proposal.

                                          Strategic Power Management, Inc.

                                          By: /s/ DANIEL P. DUTHIE
                                              ----------------------------------
                                              Daniel P. Duthie
                                              Vice President and General Counsel

Dated:August 16, 2001

<PAGE>


                               LIST OF ATTACHMENTS

         1.  Attachment A:   Electric Income Statements

         2.  Attachment B:   Gas Income Statements

         3.  Attachment C:   Cost of Capital, Debt and Preferred Redemption
                             Costs and Related Expenses

         4.  Attachment D-l: Estimate of Benefit Fund Balance

         5.  Attachment D-2: Electric Department Deferred Items Included
                             on Attachment D-l

         6.  Attachment E:   Gas Department Deferred Items for Balance
                             Sheet Offset

         7.  Attachment F:   Electric Department Revenue Allocation

         8.  Attachment G:   Low Income Program

         9.  Attachment H:   Rate Base Details, Gas and Electric

        10.  Attachment I:   Supplemental Environmental Assessment Form

<PAGE>


CASES 00-E-1273 and 00-G-1274                                       ATTACHMENT A

    Filing by: CENTRAL HUDSON GAS & ELECTRIC CORPORATION

    Amendments to Schedule P.S.C. No. 15 - Electricity
       Original Leaf No. 206.1

                    First Revised Leaves Nos. 4, 5, 14, 94, 104, 105, 106, 107,
          108, 123, 124, 136, 164, 165, 168, 169, 170, 171, 172, 185, 186, 199,
          200, 204, 209, 210, 211, 213, 215, 217, 219, 225, 237, 238, 239, 240,
          241, 242, 243, 244, 245, 246, 247, 253, 254, 255, 256, 273, 274, 275,
          276, 277, 278, 279, 281, 282, 283, 284, 285, 286, 287, 288, 289, 290,
          291, 292, 293, 294, 295, 296, 297, 298, 299, 300, 301, 302, 303, 304,
          305, 306, 307, 308, 309, 310, 311, 312, 313, 314, 315, 316, 317, 318,
          319, 320, 321, 322, 323, 324, 325, 326, 327, 328

          Second Revised Leaves Nos. 166, 205, 206, 212, 216, 218, 220
          Supplement No. 2
          Supplement No. 3
          Supplement No. 10
          Supplement No. 12
          Supplement No. 13

    Amendments to Schedule P.S.C. No. 12 - Gas

          First Revised Leaves Nos. 4, 63, 68, 69, 71, 72, 148, 149, 150, 151,
          152, 153, 154, 158, 188, 193

          Second Revised Leaves Nos. 70, 73

          Third Revised Leaves Nos. 186, 191

          Fourth Revised Leaf No. 159
          Supplement No. 2
          Supplement No. 4
          Supplement No. 7
          Supplement No. 8
          Supplement No. 9

<PAGE>


                                                                    ATTACHMENT A
                    CENTRAL HUDSON GAS & ELECTRIC CORPORATION
                         CASE NOS. 00-E-1273 & 00-G-1274
                 JOINT PROPOSAL - ELECTRIC REVENUE REQUIREMENTS

                                                  SETTLEMENT PERIOD $(000)
        OPERATING REVENUES:                    RY1          RY2          RY3
                                            --------     --------     --------
 Own Territory Base Revenues                 153,000      154,407      155,633
 Revenue (Surplus)/Deficiency                 (3,072)          (0)       3,072
                                            --------     --------     --------
 Total Revenue Requirement                   149,928      154,407      158,706

 NMP2 CTC                                     21,302       21,309       21,316
 Other Operating Revenues                      6,093        5,938        5,831
                                            --------     --------     --------
 Total Operating Revenues                    177,323      181,654      185,853

OPERATING EXPENSES:
 Non Fossil Production Maintenance               187          191          195
 Right of Way Maintenance                      4,838        4,944        5,123
 NMP2 Operations                              16,309       16,316       16,323
 Direct Labor                                 37,996       39,332       39,674
 Research and Development                      1,667        1,692        1,747
 Expenses Projected Based on Inflation         8,899        9,087        9,268
 Miscellaneous General Expenses                1,895        1,922        1,949
 Transportation Depreciation                   1,434        1,519        1,605
 Fringe Benefits                               4,666        4,825        4,869
 Other Post Employee Benefits (OPEB)           1,429        1,429        1,429
 Pension Plan                                (10,210)     (10,210)     (10,210)
 Major Rents                                   1,974        1,986        1,998
 Uncollectible Accounts                          784          791          798
 Regulatory Commission Expenses                1,278        1,305        1,333
 Data Processing Costs                         2,719        2,631        2,674
 Other Operating Insurance                       543          554          567
 Telephone                                     1,377        1,406        1,434
 Legal Services                                1,434        1,464        1,493
 Special Services                                951          971          991
 Injuries and Damages                          1,465        1,496        1,526
 Storms Expense                                2,900        2,961        3,023

<PAGE>


 Environmental                                   244          249          254
 Low Income Program                              306          530          995
 Expenses Allocated to Affiliates               (506)        (506)        (506)
                                            --------     --------     --------
          Total Operating Expenses            84,579       86,885       88,552
                                            --------     --------     --------

 OTHER DEDUCTIONS:
 NMP2 Decommissioning                            999          999          999
 Taxes Other Than Income Taxes:
        Property                              16,450       17,112       17,797
        Revenue                                6,805        6,812        6,842
        Payroll                                2,911        2,989        3,054
        Other                                  2,125        2,088        2,052
        NMP2                                   3,061        3,061        3,061
 Depreciation                                 19,035       19,888       20,696
                                            --------     --------     --------
        Total Other Deductions                51,386       52,949       54,501
                                            --------     --------     --------

 Federal Income Tax                           12,728       12,770       12,911
                                            --------     --------     --------

 Total Operating Revenue Deductions          148,693      152,604      155,964
                                            --------     --------     --------

 Operating Income                             28,630       29,050       29,889
                                            --------     --------     --------

 Rate Base                                   380,215      386,309      399,582
 Rate of Return                                 7.53%        7.52%        7.48%
 Return on Common Equity                       10.30%       10.30%       10.30%

<PAGE>


                                                                    ATTACHMENT B

                    CENTRAL HUDSON GAS & ELECTRIC CORPORATION
                         CASE NOS. 00-E-1273 & 00-G-1274
                    JOINT PROPOSAL - GAS REVENUE REQUIREMENTS

                                                  Settlement Period $(000)
        OPERATING REVENUES:                    RY1          RY2          RY3
        ------------------                  --------     --------     --------

 Own Territory Base Revenues                  36,597       37,007       37,378
 Revenue (Surplus)/Deficiency                   (885)          (0)         885
                                            --------     --------     --------
 Total Revenue Requirement                    35,712       37,007       38,263

 Interruptible Sales to Generators             1,900        1,900        1,900
 Other Operating Revenues                      2,077        2,002        1,921
                                            --------     --------     --------
 Total Operating Revenues                     39,689       40,909       42,084

OPERATING EXPENSES:
 Labor                                         9,007        9,285        9,632
 Research and Development                        331          303          303
 Expenses Projected Based on Inflation         2,302        2,350        2,399
 Miscellaneous General Expenses                  287          291          294
 Transportation - Depreciation                   307          325          344
 Fringes                                         986        1,009        1,029
 Other Post Employee Benefits (OPEB)             307          307          307
 Pension Plan                                 (2,273)      (2,273)      (2,273)
 Environmental                                    43           44           44
 Major Rents                                     123          125          127
 Uncollectible Accounts                          210          220          227
 Regulatory Commission Expenses                  258          263          269
 Data Processing Costs                           423          481          526
 Other Operating Insurance                        90           92           94
 Telephone                                       201          206          210
 Legal Services                                  377          385          392
 Special Services                                171          175          178
 Injuries and Damages                            374          382          390
 Low Income Program                               48           82          153
 Expenses Allocated to Affiliates                (89)         (89)         (89)
                                            --------     --------     --------
          Total Operating Expenses            13,483       13,963       14,556
                                            --------     --------     --------
<PAGE>


 OTHER DEDUCTIONS:
 Taxes Other Than Income Taxes:
        Property                               4,559        4,737        4,923
        Revenue                                1,598        1,661        1,719
        Payroll                                  641          659          672
        Other                                    277          280          283
 Depreciation                                  5,757        6,013        6,227
                                            --------     --------     --------
        Total Other Deductions                12,832       13,350       13,824
                                            --------     --------     --------

 Federal Income Tax                            4,361        4,457        4,511
                                            --------     --------     --------

 Total Operating Revenue Deductions           30,676       31,770       32,891
                                            --------     --------     --------

 Operating Income                              9,013        9,139        9,193
                                            --------     --------     --------

 Rate Base                                   119,695      121,525      122,904
 Rate of Return                                 7.53%        7.52%        7.48%
 Return on Common Equity                       10.30%       10.30%       10.30%

<PAGE>


                                                                    ATTACHMENT C
                                                                    SHEET 1 OF 3

                    CENTRAL HUDSON GAS & ELECTRIC CORPORATION
                        CASE NOS. 00-E-1273 AND 00-G-1274
                        JOINT PROPOSAL - COST OF CAPITAL
                                     $(000)

                                                                        PRE-TAX
RATE YEAR 1:                                                  WEIGHTED  WEIGHTED
------------                   AMOUNT      RATIO     COST       COST      COST
                               ------      -----     ----     --------  --------
Long Term Debt                 257,887      48%      5.09%      2.46%     2.46%

Customer Deposits                4,436       1%      6.00%      0.05%     0.05%

Preferred Stock                 21,005       4%      4.61%      0.18%     0.28%

Common Equity                  251,153      47%     10.30%      4.84%     7.45%
                               -------     ---                  ----
     Total Capitalization      534,481     100%                 7.53%    10.23%
                               -------     ---                  ----     -----

                                                                        PRE-TAX
RATE YEAR 2:                                                  WEIGHTED  WEIGHTED
------------                    AMOUNT      RATIO     COST      COST      COST
                                ------      -----     ----    --------  --------
Long Term Debt                 268,450      49%      5.15%      2.54%     2.54%

Customer Deposits                4,470       1%      6.00%      0.05%     0.05%

Preferred Stock                 21,042       4%      4.61%      0.18%     0.28%

Common Equity                  251,176      46%     10.30%      4.75%     7.31%
                               -------     ---                  ----
     Total Capitalization      545,138     100%                 7.52%    10.17%
                               -------     ---                  ----     -----

                                                                        PRE-TAX
RATE YEAR 3:                                                  WEIGHTED  WEIGHTED
------------                    AMOUNT      RATIO     COST      COST      COST
                                ------      -----     ----    --------  --------
Long Term Debt                 281,778      50%      5.21%      2.63%     2.63%

Customer Deposits                4,412       1%      6.00%      0.05%     0.05%

Preferred Stock                 21,057       4%      4.61%      0.17%     0.26%

Common Equity                  251,282      45%     10.30%      4.63%     7.12%
                               -------     ---                  ----
     Total Capitalization      558,529     100%                 7.48%    10.06%
                               -------     ---                  ----     -----

<PAGE>


                                                                    ATTACHMENT C
                                                                    SHEET 2 OF 3
                    CENTRAL HUDSON GAS & ELECTRIC CORPORATION
                        CASE NOS. 00-E-1273 AND 00-G-1274
                     JOINT PROPOSAL - COST OF LONG-TERM DEBT
                                     $(000)

<TABLE>
<CAPTION>
                                            OUTSTANDING             MONTHS     AVERAGE    INTEREST
COST OF LONG TERM DEBT - RY1:         RATE   8/30/01   CHANGES   OUTSTANDING OUTSTANDING   EXPENSE
----------------------------          ----   -------   -------   ----------- -----------   -------
<S>              <C>                  <C>     <C>       <C>           <C>       <C>         <C>
    PCB - August 1, 2027 Series A     5.45%   33,400        --        12        33,400      1,820
    PCB - August 1, 2034 Series B     2.80%   33,700        --        12        33,700        944
    PCB - August 1, 2028 Series C     2.65%   41,150        --        12        41,150      1,090
    PCB - August 1, 2028 Series D     2.64%   41,000        --        12        41,000      1,062
    PCB - December 1, 2028            4.20%   16,700        --        12        16,700        701
    MTN - September 10, 2001          5.93%   15,000   (15,000)        2         2,750        163
    MTN - July 2, 2004                7.85%   15,000        --        12        15,000      1,178
    MTN - January 1, 2007             6.50%       --    65,000        10        54,187      3,522
    MTN - January 15, 2009            6.00%   20,000        --        12        20,000      1,200
                                                                                ------     ------
    Totals                                                                      257,887    11,701

    Amortization of Debt Discount & Expense                                                 1,414
                                                                                           ------
    Total Cost of Debt                                                                     13,115
                                                                                           ------
    Cost Rate                                                                                5.09%
                                                                                           ------
</TABLE>

<TABLE>
<CAPTION>
                                            OUTSTANDING             MONTHS     AVERAGE    INTEREST
COST OF LONG TERM DEBT - RY2:         RATE   6/30/01   CHANGES   OUTSTANDING OUTSTANDING   EXPENSE
----------------------------         -----  --------  --------  ------------ -----------  --------
<S>              <C>                  <C>     <C>       <C>           <C>       <C>         <C>
    PCB - August 1, 2027 Series A     5.45%   33,400        --        12        33,400      1,820
    PCB - August 1, 2034 Series B     2.80%   33,700        --        12        33,700        944
    PCB - August 1, 2028 Series C     2.65%   41,150        --        12        41,150      1,090
    PCB - August 1, 2028 Series D     2.64%   41,000        --        12        41,000      1,082
    PCB - December 1, 2028            4.20%   16,700        --        12        16,700        701
    MTN - January 1, 2007             6.50%   65,000        --        12        65,000      4,225
    MTN - July 2, 2004                7.85%   15,000        --        12        15,000      1,178
    MTN - April 1, 2008               6.50%       --    10,000         3         2,500        162
    MTN - January 15, 2009            6.00%   20,000        --        12        20,000      1,200
                                                                              --------    -------
    Totals                                                                     268,450     12,403

    Amortization of Debt Discount & Expense                                                 1,420
                                                                                          -------
    Total Cost of Debt                                                                     13,823
                                                                                          -------
    Cost Rate                                                                                5.15%
                                                                                          -------
</TABLE>

<PAGE>

<TABLE>
<CAPTION>
                                            OUTSTANDING             MONTHS     AVERAGE    INTEREST
COST OF LONG TERM DEBT - RY3:         RATE   6/30/01   CHANGES   OUTSTANDING OUTSTANDING   EXPENSE
----------------------------         -----  --------  --------  ------------ -----------  --------
<S>              <C>                  <C>     <C>       <C>           <C>       <C>         <C>
    PCB - August 1, 2027 Series A     5.45%   33,400       --         12        33,400      1,820
    PCB - August 1, 2034 Series B     2.80%   33,700       --         12        33,700        944
    PCB - August 1, 2028 Series C     2.65%   41,150       --         12        41,150      1,090
    PCB - August 1, 2028 Series D     2.64%   41,000       --         12        41,000      1,082
    PCB - December 1, 2028            4.20%   16,700       --         12        16,700        701
    MTN - January 1, 2007             6.50%   65,000       --         12        65,000      4,225
    MTN - July 2, 2004                7.85%   15,000       --         12        15,000      1,178
    MTN - April 1, 2008               6.50%   10,000       --         12        10,000        650
    MTN - April 1, 2009               6.50%       --    8,742          8         5,828        379
    MTN - January 15, 2009            6.00%   20,000       --         12        20,000      1,200
                                                                              --------    -------

    Totals                                                                     281,778     13,269

    Amortization of Debt Discount & Expense                                                 1,425
                                                                                          -------
    Total Cost of Debt                                                                     14,694
                                                                                          -------
    Cost Rate                                                                                5.21%
                                                                                          -------
</TABLE>

<PAGE>


                                                                    ATTACHMENT C
                                                                    SHEET 3 OF 3

                    CENTRAL HUDSON GAS & ELECTRIC CORPORATION
                        CASE NOS. 00-E-1273 AND 00-G-1274
       JOINT PROPOSAL - AMORTIZATION OF DEBT AND PREFERRED STOCK EXPENSES

<TABLE>
<CAPTION>
                                                                                 TOTAL
                                                    ESTIMATED    UNAMORTIZED  UNRECOVERED
                                                    REDEMPTION     EXPENSE      COST OF                       AMORTIZATION - RYE
UNAMORTIZED DEBT EXPENSE:                            PREMIUM       6/30/01     REDEMPTION      6/30/02       6/30/03       6/30/04
                                                    ----------    ---------    ----------    ----------    ----------    ----------
<S>                                                    <C>          <C>            <C>           <C>           <C>       <C>
6 1/4% MORTGAGE BONDS - 2007                                         53,973        53,973         9,156         9,156         9,156
9 1/4% MORTGAGE BONDS - 2021                                        860,846       860,846        43,404        43,404        43,404
7.97% MTN 6/11/2003 SERIES A                                         28,587        28,587        15,516        13,071            --
7.97% MTN 6/13/2003 SERIES A                                         29,978        29,978        14,328        14,328         1,322
7.85% MTN 6/2/2004 SERIES A                                          47,665        47,665        15,528        15,528        15,528
8.12% MTN 8/29/22 SERIES A                                          146,034       146,034         6,888         6,888         6,888
8.14% MTN 8/29/22 SERIES A                                          146,005       146,005         6,900         6,900         6,900
6.46% MTN 8/11/03 SERIES A                                           41,891        41,891        19,332        19,332         3,227
Tax Exempt NYSERDA 4.20% Due 12/1/28                                537,586       537,586        19,608        19,608        19,608
6.00% MTN 1/15/09 Series C                                          176,915       176,915        23,580        23,580        23,580
5.45% Series A NYSERDA Bonds 8/1/27                                 646,345       646,345        24,780        24,780        24,780
Var Rate Ser B NYSERDA Bonds 7/1/34                                 570,240       570,240        17,477        17,477        17,477
Var Rate Series C NYSERDA Bonds 8/1/28                              643,020       643,020        31,332        31,332        31,332
Var Rate Series D NYSERDA Bonds 8/1/28                              641,714       641,714        29,400        29,400        29,400
$65,000 MTN Issued 9/1/01 Due 1/1/07                   208,000           --       208,000        32,500        39,000        39,000
$10,000 MTN Issued 4/1/03 Due 4/1/08                    32,000           --        32,000            --         1,600         6,400
$10,000 MTN Issued 10/1/03 Due 4/1/09                   32,000           --        32,000            --            --         4,299
                                                    ----------    ---------    ----------    ----------    ----------    ----------

      Total                                            272,000    4,570,799     4,842,799       309,729       315,384       282,300
                                                    ----------    ---------    ----------    ----------    ----------    ----------

UNAMORTIZED LOSS ON REACQUIRED DEBT:

REDEMPTION 9 1/4% MTG. BONDS                                --      160,082       160,082        57,324        57,324        57,324
REDEMPTION 10 5/8% MTG BONDS 11/1/05                        --      381,108       381,108        87,948        87,948        87,948
REDEMPTION 10 3/4% MTG BONDS 9/15/09                        --      741,496       741,496        90,324        90,324        90,324
7 1/2% POLLUTION CONTROL NOTES - 2014                       --    1,850,442     1,850,442       139,656       139,656       139,656
ADJ RTE POLL CTRL NOTES - DUE 11/1/2020                     --      592,800       592,800       187,200       187,200       187,200
ADJ RATE POLL CTRL NOTES - DUE 5/1/27                       --      393,193       393,193        15,168        15,168        15,168
REDEEMED 11 1/4% POLL CTL BDS - 9/1/12                      --      298,284       298,284        26,712        26,712        26,712
5.375% MORTGAGE BONDS -2028                                 --      720,510       720,510        26,280        26,280        26,280
Redeem 9 1/4% Mortgage Bond                          2,856,000           --     2,856,000       144,000       144,000       144,000
Redeem 7.97% MTN Due 5/1/03                            300,000           --       300,000       150,000       150,000       150,000
Redeem 7.97% MTN Due 5/13/03                           300,000           --       300,000       150,000       150,000       150,000
Redeem 8.12% MTN Due 8/29/22                           500,000           --       500,000        23,810        23,810        23,810
Redeem 8.14% MTN Due 8/29/22                           500,000           --       500,000        23,810        23,810        23,810
Redeem 6.46% MTN Due 8/11/03                          (100,000)          --      (100,000)      (46,154)      (46,154)       (7,692)
                                                    ----------    ---------    ----------    ----------    ----------    ----------
      Total                                          4,356,000    5,137,915     9,493,915     1,076,077     1,076,077     1,114,539
                                                    ----------    ---------    ----------    ----------    ----------    ----------

UNAMORTIZED DISCOUNT ON L/T DEBT:

First Mtg. Bonds - 9 1/4% due 5/1/21                        --      512,640       512,640        25,632        25,632        25,632
5.45% Ser. A NYSERDA Bonds due 8/1/27                       --       78,045        78,045         2,976         2,976         2,976
                                                    ----------    ---------    ----------    ----------    ----------    ----------
        Total                                               --      590,685       590,685        28,608        28,608        28,608
                                                    ----------    ---------    ----------    ----------    ----------    ----------

Total Debt Issuance and Redemption Expenses          4,628,000    10,299,399   14,927,399     1,414,414     1,420,069     1,425,447
                                                    ----------    ---------    ----------    ----------    ----------    ----------

PREFERRED STOCK:
---------------

6.20% Cumulative Preferred                             675,000      412,554     1,087,554       150,007       150,007       150,007
6.80% Cumulative Preferred                           1,600,000      454,230     2,054,230        78,256        78,256        78,256
                                                    ----------    ---------    ----------    ----------    ----------    ----------

Total Preferred Stock Issuance
  and Redemption Expenses                            2,275,000      866,784     3,141,784       228,264       228,264       228,264
                                                    ----------    ---------    ----------    ----------    ----------    ----------
</TABLE>

<PAGE>


                                                                  ATTACHMENT D-1

                    CENTRAL HUDSON GAS & ELECTRIC CORPORATION
                         CASE NOS. 00-E-1273 & 00-G-1274
                          JOINT PROPOSAL - BENEFIT POOL

                                                      Settlement Period
                                                      ($000, Net of Tax)
                                                 RY1         RY2          RY3
                                              --------     --------     -------
NET BENEFIT FUND:
  Net Fossil Proceeds                           76,708
  Deferred Excess Earnings                       9,377
  Net Settlement Benefits                       41,621
  NMP2 Proceeds                                 36,500
                                               -------

  Total Benefit Pool                           164,206
  Less: Rate Base Credit                       (42,500)
                                               -------

  Net Benefit Fund Available                   121,706      100,692      88,204

  Identified Uses (net of tax):
    Reliability Program - $20 million,
      3 Yr Program                              (4,333)      (4,333)     (4,333)
    Offset of Gas Site Remediation
      Costs - $15 million                       (9,750)          --          --
    Refunds                                    (15,000)     (15,000)    (15,000)
                                              --------     --------     -------

  Remaining Balance                             92,623       81,359      68,871

  Add Cumulative Carrying
    Charges - Net of Tax                         8,069        6,845       5,875
                                              --------     --------     -------

  Net Benefit Fund Balance                     100,692       88,204      74,745
                                              --------     --------     -------

Identified uses include electric backout credits, and other new stranded costs;
potential uses include economic development fund, price spike mitigation, small
customer aggregation, other competitive initiatives and additional refunds.

<PAGE>


                                                                  ATTACHMENT D-2

                ELECTRIC DEFERRED ITEMS INCLUDED IN BENEFIT FUND

     The June 30, 2001 balances of the following deferred debit and deferred
credit accounts, net of tax, are included in the Benefit Fund. No subsequent
deferrals to these accounts will be included in the Benefit Fund except for
those to make accounting adjustments to the June 30, 2001 balance.

                                 DEFERRED DEBITS

           Adjustable Rate PCB Notes
           Deferred DSM Costs
           Tax Rate Change - 1993
           Storm Costs - April 1997
           Restructuring Costs - Formation of Holding Company
           Lost Revenues - Job Retention Provision (COPS)
           Pension Carrying Charge
           Pension Fund Withdrawal

                            DEFERRED CREDITS

           Research & Development Costs
           Management Audit
           Adjustable Rate Preferred Dividends Over/Under Collection
           NMP-2 Vendor Litigation - Ratepayer
           NMP-2 Vendor Litigation Carrying Charge
           NMP-2 Deferred Settlement Agreement Costs
           Carrying Charge on NMP-2 Settlement Agreement Costs
           Carrying Charge on DSM Rate Base
           DSM Lost Revenues
           Customer Benefits Account (COPS)
           Royalty Charge (COPS)
           R&D 1994 Audit Adjustment
           Deferred Letter of Credit/Remarketing Fees
           Deferred Pension Cost Over/Under Collection
           Deferred OPEB Expense
           OPEB Carrying Charge
           Deferred Excess Earnings

<PAGE>


                                                                    ATTACHMENT E

                   GAS DEFERRED ITEMS FOR BALANCE SHEET OFFSET

     The following gas department deferred debit and deferred credit items will
be subject to balance sheet offset accounting to the extent that a net of tax
offset of zero is achieved using actual deferred amounts at June 30, 2001.

                                 DEFERRED DEBITS

           Adjustable Rate PCB Notes
           Amortization of Unbilled Revenue (Case 90-G-0673)
           Carrying Charge of Newburgh Site Investigation
           ULIEEP Over/Under Collection (Including Carrying Charges)
           Pension Carrying Charge


                                DEFERRED CREDITS

           Unamortized Interruptible Gas Depreciation
           Research & Development Costs
           Management Audit
           Gas Special Franchise Tax
           R&D 1994 Audit Adjustment
           Deferred Letter of Credit/Remarketing Fees
           Deferred Pension Cost Over/Under Collection
           Deferred OPEB Expense
           OPEB Carrying Charge

<PAGE>


                                                                    ATTACHMENT F

                    CENTRAL HUDSON GAS & ELECTRIC CORPORATION
                     ELECTRIC INTERCLASS REVENUE ALLOCATION
    ALLOCATION OF PROPOSED REVENUE INCREASE (DECREASE) EXCLUDING REVENUE TAX
                   USING 15% TOLERANCE BAND ON RATE OF RETURN
                        CASE 00-E-1273 COMPLIANCE FILING
                                     $(000)

<TABLE>
<CAPTION>
                                                           SC Nos                SC      SC No. 6     SC
                                                           2 & 12               No. 5  RESIDENTIAL   No. 8
LINE                                           SC No. 1     SMALL    SC NO. 3    AREA      TIME      STREET        SC No. 13
NO.                                  TOTAL    RESIDENTIAL  GENERAL   PRIMARY   LIGHTING   OF USE    LIGHTING SUBSTATION TRANSMISSION
----- ------------------------------ --------- ---------- --------  ---------- -------- ----------- -------- ----------- -----------
<S>   <C>                             <C>        <C>       <C>        <C>        <C>       <C>       <C>          <C>         <C>
1.    Net Income (1)                  $22,717    $10,984   $7,323     $1,708     $198      $1,232    ($34)        $345        $961

----- ------------------------------ --------- ---------- -------- ---------- -------- ----------- -------- ----------- -----------

2.    % Rate of Return                   5.34       4.58     5.89      11.67     4.51       10.08    (0.49)      10.73        5.02

----- ------------------------------ --------- ---------- -------- ---------- -------- ----------- -------- ----------- -----------

3.    5.34 +/- 15%                       5.09       4.58     5.89       6.14     4.54        6.14     4.54        6.14        5.02

----- ------------------------------ --------- ---------- -------- ---------- -------- ----------- -------- ----------- -----------

4.    Adjusted Net Income             $21,652    $10,985   $7,347       $898     $199        $750     $314        $197        $961

----- ------------------------------ --------- ---------- -------- ---------- -------- ----------- -------- ----------- -----------

5.    Adjusted to Initial             $22,717    $11,525   $7,708       $942     $209        $787     $330        $207      $1,009
          Net Income

----- ------------------------------ --------- ---------- -------- ---------- -------- ----------- -------- ----------- -----------

6.    Difference                                    $541     $385      ($766)     $11       ($445)    $364       ($138)        $48

----- ------------------------------ --------- ---------- -------- ---------- -------- ----------- -------- ----------- -----------

7.    Revenue                                       $819     $583    ($1,161)     $17       ($674)    $552       ($209)        $73
       (Line 7/.66)

----- ------------------------------ --------- ---------- -------- ---------- -------- ----------- -------- ----------- -----------

8.    Revenue Increase  (Decrease)-
      NET OF FUEL Excludes
      Revenue Tax                     ($2,297)   ($1,300)   ($692)      ($95)    ($12)       ($87)    ($37)       ($19)       ($55)


----- ------------------------------ --------- ---------- -------- ---------- -------- ----------- -------- ----------- -----------

9.    Total Revenue Decrease          ($2,297)     ($481)   ($109)   ($1,256)      $5       ($761)    $515       ($228)        $18

----- ------------------------------ --------- ---------- -------- ---------- -------- ----------- -------- ----------- -----------

10.   Present Rate Revenues          $149,179    $84,441  $44,966     $6,160     $758      $5,623   $2,406      $1,225      $3,600
       (Excluding Revenue Tax)

----- ------------------------------ --------- ---------- -------- ---------- -------- ----------- -------- ----------- -----------

11.   Percent Increase  (Decrease)
        Unconstrained                   (1.54)     (0.57)   (0.24)    (20.39)    0.66      (13.53)   21.40      (18.61)       0.50

----- ------------------------------ --------- ---------- -------- ---------- -------- ----------- -------- ----------- -----------

12.   Percent Increase  (Decrease)
        Constrained                     (1.54)     (1.52)   (1.52)     (1.93)   (0.79)      (1.94)   (0.79)      (1.96)      (1.50)

----- ------------------------------ --------- ---------- -------- ---------- -------- ----------- -------- ----------- -----------

13.   Total Revenue Increase
        Constrained                   ($2,297)   ($1,283)   ($683)     ($119)     ($6)       (109)    ($19)       ($24)       ($54)

----- ------------------------------ --------- ---------- -------- ---------- -------- ----------- -------- ----------- -----------

14.   DSM Adjustment                     ($42)       ($6)    ($29)       ($7)

----- ------------------------------ --------- ---------- -------- ---------- -------- ----------- -------- ----------- -----------

15.   Final Total Revenue Increase    ($2,339)   ($1,289)   ($712)     ($126)     ($6)      ($109)    ($19)       ($24)       ($54)

----- ------------------------------ --------- ---------- -------- ---------- -------- ----------- -------- ----------- -----------
</TABLE>

(1)  PRO FORMA COST OF SERVICE STUDY FOR THE RATE YEAR ENDING JUNE 30, 2002,
     WITH HYDRO CLASSIFIED 100% ENERGY AND TURBINES CLASSIFIED 100% DEMAND.

                                       51
<PAGE>


                                                                    ATTACHMENT G
                                                                    SHEET 1 OF 5



                    CENTRAL HUDSON GAS & ELECTRIC CORPORATION


                               LOW INCOME PROGRAM


                             POWERFUL OPPORTUNITIES


PLAN OBJECTIVES:

An effective low income program should provide a practical opportunity for
customers who, due to an illness or disability or loss of job, have fallen
behind in their utility payments and are struggling to pay their arrears. An
effective low income program should empower customers by developing a
comprehensive plan to improve their overall financial situation to become
self-reliant. An effective low income program should teach customers about the
cost of electricity -- and how energy conservation and energy efficiency does
make a difference for affordability. An effective low income program should
bring peace of mind to the customers -- that their utility bills can be worked
out at a level they can handle. An effective low income program should build a
stronger relationship between customers, Central Hudson and the community. And
lastly, an effective low income program should enable Central Hudson to focus
its collection efforts on customers who can but don't pay their utility bills.

PLAN DESIGN & ADMINISTRATION

Powerful Opportunities is a managed approach, designed to accomplish three
primary goals: (1) Provide customers with an affordable payment plan for past
and future utility bills; (2) Provide customers with the tools to obtain
long-term, overall financial stability and self-sufficiency; and (3) Provide
customers with the energy services and education required to enable them to
reduce their energy usage and potentially their payment amount. In addition, our
low income program is designed to include an incentive to encourage customers to
meet their Powerful Opportunities obligations.

To attain the first goal, "provide customers with an affordable payment plan for
past and future utility bills" the following actions are recommended:

<PAGE>


                                                                    Attachment G
                                                                    Sheet 2 of 5


     -    Place the customer on budget billing for future bills.

     -    Place the customer's arrears in suspend; no LPCs will be charged to
          this amount while the customer is a participant of the Program.

     -    Give an incentive: a $ for $ match on payments made above the current
          budget amount. The maximum match paid by Central Hudson will be $20
          per month per customer.

     -    If the customer is a heating customer, give one additional GNF benefit
          at the end of the Program (last $125 of arrears).

     -    Offer a lower basic service charge of $5.00 per month for both gas and
          electric customer participants.

It is recommended Central Hudson collaborate with community resources to attain
the second goal of "providing customers with the tools to obtain overall
financial stability and self-- sufficiency"; and the third goal, "providing
customers with the energy services and education required to enable them to
reduce their energy usage". A partnership with a community--based organization,
such as Dutchess County Community Action Agency (DCCAA), would contribute to the
overall integrity of the Program. DCCAA has established trust and credibility in
helping families with their self--sufficiency goals. In addition, DCCAA is a
well--known and respected entity within the network of community assistance
agencies. DCCAA can effectively coordinate community resources, educate
consumers, establish individual customer assessments and referrals, and provide
program administration and outreach to our mutual clients.

A partnership with DCCAA would provide:


     -    A multi-county network, which spans our entire service territory, with
          the ability to disseminate, support and monitor implementation of the
          program.

     -    Referrals to local, state and federal assistance programs, and
          coordinate with the NYS Weatherization Program.

<PAGE>


                                                                    Attachment G
                                                                    Sheet 3 of 5

     -    Expertise in assisting low income customers with the ability to gain
          greater competency in their household management through energy
          efficient products and consumer education.

     -    Family development training to promote greater self-sufficiency and
          self-reliance to the Program participants, and internal sensitivity
          training to our customer--contact employees.


CUSTOMER'S ELIGIBILITY AND OBLIGATIONS

Eligibility for participation in this Program is outlined below:

     -    Must be a CHG&E customer whose bills are not directly paid to the
          Company by a local department of social services office, and the
          account must be their primary residence.

     -    Customer must have an account that is 60 days or more in arrears.

     -    Customer who has a household income equal to or less than 200% of
          poverty level, as determined for that program year.

     -    Customers will be considered categorically eligible if they are
          enrolled in the New York State Home Energy Assistance Program or any
          other federal or state assistance program with similar or stricter
          income eligibility requirements than 200% of the poverty level.

     -    Customer must complete a Program application form and financial
          statement (DSS 3596), submit required documentation and be approved
          for participation.

     -    Customers in an energy crisis (locked for non-payment) at the time of
          application may be eligible to participate, however, the amount they
          are required to pay for turn-on will not be matched by Central Hudson.

<PAGE>


                                                                    Attachment G
                                                                    Sheet 4 of 5

     -    The maximum Program enrollment targets are:

                 YEAR                            TARGET
                   1                              250
                   2                              500
                   3                             1000

In order for the customer to become a participant of Powerful Opportunities,
they must agree (in writing) to the following terms and responsibilities:

     -    Only if consistent with a DCCAA assessment of an individual
          participant's ability to pay, participants shall pay at least an
          additional $5 per month (for $60 per year) on their arrears.

     -    Participate in energy conservation/efficiency training and budget
          counseling sessions as prescribed by their Family Development
          Specialist.

     -    Agree to the recommended follow-up schedule, and meet with their
          designated Family Development Specialist according to that schedule.

     -    Apply for community and government assistance as suggested by the
          Family Development Specialist.

     -    Customers who become delinquent on a current bill will be dropped from
          the Program after 60 days delinquency and will not be eligible for
          re-entry for the same arrears. A minimum $10/month DPA will be offered
          and then regular collection cycle will begin.

     -    Re-entry to the program, however, will be permitted if a participant
          who is dropped from the program for nonpayment of current bills
          subsequently receives emergency assistance through a Department of
          Social Services program and the amount of the delinquency after the
          customer's prior enrollment in the program is paid in full.

OTHER ASSISTANCE

     -    HEAP payments (regular and emergency) will be applied to the
          customer's current charges and will not be matched by Central Hudson.
          If a HEAP payment is more

<PAGE>


                                                                    Attachment G
                                                                    Sheet 5 of 5

          than the current amount due, the excess will be applied to the
          arrears, with no Company match.

     -    Other community assistance (i.e., Red Cross, Church Charities, etc.)
          will be matched by Central Hudson if the funding is paid to the
          customer for payment of bills, and the customer passes the payment to
          Central Hudson to be applied to their arrears. Community assistance
          payments made directly to Central Hudson on behalf of the customer
          will be applied to the current bill first, then to the arrears, with
          no match.

DCCAA ROLE:

DCCAA will work closely with Consumer Outreach to develop and maintain an
effective low income program. Upon approval of this draft proposal, DCCAA will
prepare and submit for our review and approval a Program outline and fee for
their part in Powerful Opportunities. The Program outline will include:

     -    Implementation Plan (including targeted outreach, toll- free number,
          etc.)

     -    Procedures (including forms, letters, follow-up, collaboration with
          neighboring Community Action Agencies located in our service
          territory, etc.)

     -    Community and Government Assistance Referrals

     -    Weatherization Plan (including appliance repair and replacement)

     -    Case Management:

              Family Development Training Outline (for long-term
              self--sufficiency)

              Energy Efficiency/Conservation

              Budget Counseling

     -    Sensitivity Training Outline (for CHG&E employees)

     -    Evaluation Process

<PAGE>


                                                                    ATTACHMENT H
                                                                    SHEET 1 OF 2


                    CENTRAL HUDSON GAS & ELECTRIC CORPORATION
                               RATE BASE - SUMMARY
                            FINAL SETTLEMENT POSITION
                                     ($000)

<TABLE>
<CAPTION>
                                                          ELECTRIC                                    GAS
                                           -------------------------------------     -------------------------------------
                                             RY 1           RY 2          RY 3          RY 1          RY 2          RY 3
                                           ---------     ---------     ---------     ---------     ---------     ---------
<S>                                        <C>           <C>           <C>           <C>           <C>           <C>
BOOK COST OF UTILITY PLANT                 $ 671,892     $ 703,930     $ 743,956     $ 190,346     $ 196,552     $ 204,205
LESS: ACCUMULATED PROVISION FOR
          DEPRECIATION AND AMORTIZATION     (244,559)     (256,038)     (270,252)      (69,798)      (72,956)      (78,056)
                                           ---------     ---------     ---------     ---------     ---------     ---------

NET PLANT                                    427,333       447,892       473,704       120,548       123,596       126,149

RELIABILITY CAPITAL PROGRAM                   (5,354)      (16,196)      (26,650)
NET SETTLEMENT BENEFITS                      (42,500)      (42,500)      (42,500)
NONINTEREST-BEARING CONSTRUCTION
     WORK IN PROGRESS                         30,160        28,731        29,088         8,434         8,501         8,556
CUSTOMER ADVANCES FOR UNDERGROUNDING            (603)         (615)         (627)
DEFERRED CHARGES                              17,559        15,948        14,228         4,290         4,010         3,919
ACCUMULATED DEFERRED TAXES                   (66,670)      (67,869)      (69,353)      (17,760)      (18,908)      (20,206)
WORKING CAPITAL                               23,507        24,135        24,909         5,181         5,324         5,484
                                           ---------     ---------     ---------     ---------     ---------     ---------

UNADJUSTED RATE BASE                         383,432       389,526       402,799       120,693       122,523       123,902
CAPITALIZATION ADJUSTMENT TO RATE BASE        (3,217)       (3,217)       (3,217)         (998)         (998)         (998)
                                           ---------     ---------     ---------     ---------     ---------     ---------

TOTAL RATE BASE                            $ 380,215     $ 386,309     $ 399,582     $ 119,695     $ 121,525     $ 122,904
                                           ---------     ---------     ---------     ---------     ---------     ---------
</TABLE>

<PAGE>


                                                                    ATTACHMENT H
                                                                    SHEET 2 OF 2


                    CENTRAL HUDSON GAS & ELECTRIC CORPORATION
              DEFERRED CHARGES, DEFERRED TAXES AND WORKING CAPITAL
                            FINAL SETTLEMENT POSITION
                                     ($000)


<TABLE>
<CAPTION>
                                                         ELECTRIC                                       GAS
                                          --------------------------------------       --------------------------------------
                                            RY 1          RY 2             RY 3          RY 1           RY 2           RY 3
                                          --------       --------       --------       --------       --------       --------
<S>                                        <C>           <C>           <C>           <C>           <C>           <C>
DEFERRED CHARGES
SOFTWARE PURCHASES                        $  2,647       $  2,221       $  1,564       $  1,197       $  1,253       $  1,349
MTA TAX                                      2,426          2,426          2,246            769            769            769
UNAMORTIZED DEBT EXPENSE                     8,211          8,459          7,710          1,337          1,337          1,255
INCREMENTAL DEFERRED DEBT EXPENSE            3,783          2,375          2,085            780            535            474
UNAMORTIZED DISCOUNT LONG-TERM DEBT            492            467            443             80             76             72
CARRYING CHARGE ON NEWBURGH SITE
   INVESTIGATION                                 0              0              0            127              0              0
                                          --------       --------       --------       --------       --------       --------


      TOTAL DEFERRED CHARGES              $ 17,559       $ 15,948       $ 14,228       $  4,290       $  4,010       $  3,919


DEFERRED TAXES
MTA TAX                                   ($   849)      ($   849)      ($   849)      ($   269)      ($   269)      ($   269)
NORMALIZED DEPRECIATION                    (59,588)       (62,728)       (66,162)       (18,639)       (19,993)       (21,439)
INVESTMENT TAX CREDIT                       (3,102)        (2,800)        (2,498)          (700)          (637)          (576)
COST OF REMOVAL                             (1,510)        (1,536)        (1,572)          (174)           (87)           (32)
CONSTRUCTION OVERHEADS                      (1,438)        (1,329)        (1,220)
CONTRIBUTIONS IN AID OF CONSTRUCTION         1,662          1,651          1,638            341            336            330
DEFERRED AVOIDED COST INTEREST
CAPITALIZED                                  1,303          1,288          1,276            294            299            302
UNBILLED REVENUE                             4,231          4,231          4,231          1,811          1,811          1,811
REPAIR ALLOWANCE                            (6,044)        (6,149)        (6,244)
ACRS METHOD CHANGE                             (97)           (87)           (77)           (24)           (22)           (20)
MORTGAGE TAXES                                (134)          (121)          (108)           (21)           (19)           (17)
BONDS REDEEMED                                (716)          (806)          (726)          (117)          (133)          (119)
CARRYING CHARGE ON NEWBURGH
SITE INVESTIGATION                               0              0              0            (45)             0              0
REDEMPTION PREMIUMS                         (1,230)        (1,097)        (1,005)          (217)          (194)          (177)
RELIABILITY EXPENDITURES                       842          2,463          3,963
                                          --------       --------       --------       --------       --------       --------

      TOTAL DEFERRED TAXES                ($66,670)      ($67,869)      ($69,353)      ($17,760)      ($18,908)      ($20,206)
                                          --------       --------       --------       --------       --------       --------


WORKING CAPITAL
OTHER MATERIAL AND SUPPLY WORKING
CAPITAL                                      4,248          4,336          4,422          1,408          1,437          1,466
PREPAID PROPERTY TAXES - OTHER               8,571          8,916          9,272          1,623          1,686          1,752
PREPAID INSURANCE - OTHER                      398            406            415            112            114            116
OTHER PREPAYMENTS                              592            605            617            105            107            109
OPERATION AND MAINTENANCE CASH
   WORKING CAPITAL                           9,698          9,872         10,183          1,933          1,980          2,041
                                          --------       --------       --------       --------       --------       --------

      TOTAL WORKING CAPITAL               $ 23,507       $ 24,135       $ 24,909       $  5,181       $  5,324       $  5,484
                                          --------       --------       --------       --------       --------       --------
</TABLE>

<PAGE>


                                                                    ATTACHMENT I

                   STATE OF NEW YORK PUBLIC SERVICE COMMISSION



CASE 00-E-1273 - PROCEEDING ON MOTION OF THE COMMISSION AS TO THE RATES,
          CHARGES, RULES AND REGULATIONS OF CENTRAL HUDSON GAS & ELECTRIC
          CORPORATION FOR ELECTRIC SERVICE

CASE 00-G-1274 - PROCEEDING ON MOTION OF THE COMMISSION AS TO THE RATES,
          CHARGES, RULES AND REGULATIONS OF CENTRAL HUDSON GAS & ELECTRIC
          CORPORATION FOR GAS SERVICE






                   SUPPLEMENTAL ENVIRONMENTAL ASSESSMENT FORM









                                  PREPARED BY:
                   CENTRAL HUDSON GAS & ELECTRIC CORPORATION,
               STAFF OF THE DEPARTMENT OF PUBLIC SERVICE, AND THE
                  OTHER SIGNATORY PARTIES TO THE JOINT PROPOSAL




Dated:  Albany, New York
        August 27, 2001

<PAGE>


I.   INTRODUCTION

     This document provides the substantive information solicited by Appendix A
of 6 NYCRR 617.20, part of the regulations promulgated by the New York State
Department of Environmental Conservation pursuant to the State Environmental
Quality Review Act ("SEQRA"), Article 8 of the New York Environmental
Conservation Law. An environmental assessment is an evaluation of the known or
potential environmental consequences of a proposed action. Such an assessment
also determines whether additional relevant information about such impacts is
needed. Environmental assessments help involved and interested agencies identify
their concerns about the action and provide guidance to the lead agency in
making its determination of significance.

     An Environmental Assessment Form ("EAF") provides an organized approach to
identifying the information needed by the lead agency to make its determination
of significance. A properly completed EAF describes a proposed action, its
location, its purpose and its potential impacts on the environment. The EAF is
the first step in the environmental impact review process and leads to either a
positive declaration (requiring further analysis of the potentially significant
adverse environmental impacts) or a negative declaration (requiring no further
analysis).

II.  ENVIRONMENTAL ASSESSMENT FORM INFORMATION (PART I OF EAF)

     A.   APPLICANT/SPONSOR:

               Central Hudson Gas & Electric Corporation
               ("Central Hudson" or "Company")
               284 South Avenue
               Poughkeepsie, New York 12601

     B.   NAME OF ACTION:

               Public Service Commission ("Commission") approval of the terms of
               the Joint Proposal for the resolution of Cases 00-E-1273 and
               00-G-1274

     C.   LOCATION OF ACTION:

               Central Hudson electric and gas service territories

     D.   DESCRIPTION OF ACTION:

     The Company and other Signatory Parties to the Joint Proposal are
petitioning the Commission under the Public Service Law of the State of New York
for approval of the terms of their Joint Proposal for the resolution of Cases
00-E-1273 and 00-G-1274. These cases relate to the rates, charges, rules and
regulations of the Company for electric and gas service, respectively, and to
the Commission's

<PAGE>


restructuring and competitive market development policies in Case 94-E-0952(1)
(electricity) and Cases 93-G-0932 and 97-G-1380(2) (gas). The Commission's
consideration of the rate-related aspects of the Joint Proposal is a "Type II
exempt rate action"(3) that does not require SEQRA analysis. Accordingly, the
Commission's consideration of the restructuring and competitive market
development-related aspects of the Joint Proposal is the potential action that
has been evaluated in this Assessment.

     The Joint Proposal does not require any construction activities which would
directly affect the environment. As a result, consideration of the terms of the
Joint Proposal is an "unlisted" action as defined in 6 NYCRR 617. While 6 NYCRR
617.6 generally calls for the use of the short EAF set forth at 6 NYCRR 617.20,
Appendix C, because this action does not involve physical construction as
contemplated by the short EAF, a narrative EAF has been utilized.(4)

     1.   CASE 00-E-1273

     Case 00-E-1273 was occasioned by the implementation of the Commission's
policy of supporting increased competition in electricity markets, which it
adopted in Opinion No. 96-12 in Case 94-E-0952. Case 00-E-1273 was preceded and
required by Case 96-E-0909(5) in which, by an Order issued February

----------
     (1)  IN THE MATTER OF COMPETITIVE OPPORTUNITIES REGARDING ELECTRIC SERVICE

     (2)  Respectively, PROCEEDING ON MOTION OF THE COMMISSION TO ADDRESS ISSUES
ASSOCIATED WITH THE RESTRUCTURING OF THE EMERGING COMPETITIVE NATURAL GAS MARKET
AND IN THE MATTER OF ISSUES ASSOCIATED WITH THE FUTURE OF THE NATURAL GAS
INDUSTRY AND THE ROLE OF THE LOCAL DISTRIBUTION COMPANIES

     (3)  Opinion No. 98-14 at 41.

     (4)  A narrative EAF has also been used in similar cases. See, Case
99-G-0336, NIAGARA MOHAWK POWER CORPORATION - GAS MULTI-YEAR RATE AND
RESTRUCTURING PROPOSAL, Opinion No. 00-9 issued July 27, 2000; Case 99-G-1469,
BROOKLYN UNION GAS COMPANY - MULTI-YEAR RESTRUCTURING AGREEMENT, Order
Establishing Interim Rate Plan issued December 26, 2000; Case 98-G-1589,
ROCHESTER GAS AND ELECTRIC CORPORATION - PLANS FOR GAS RATES AND RESTRUCTURING,
Order Adopting Terms of Joint Proposal issued February 28, 2001.

     (5)  IN THE MATTER OF CENTRAL HUDSON GAS & ELECTRIC CORPORATION'S PLANS FOR
ELECTRIC RATES AND RESTRUCTURING PURSUANT TO OPINION NO. 96-12

<PAGE>


19, 1998 and by Opinion No. 98-14 issued June 30, 1998, the Commission adopted
an electric rate and restructuring plan for the Company pursuant to the
Commission's policy of supporting increased electricity market competition as
adopted in Case 94-E-0952.

     Case 00-E-1273 and the Joint Proposal address ratemaking associated with
the restructuring of the Company from a vertically integrated utility to a
delivery service company, as envisioned by the Commission in Case 94-E-0952 and
implemented, to the extent of the Company's divestiture of its fossil fueled
generating units and measures to promote retail access, in Case 96-E-0909. This
is in the form of removing from rates those charges associated with the
Company's former interests in fossil fueled generating units and establishing
the methods and procedures for customer acquisition of and payment for electric
supply provided by marketers. Case 00-E-1273 and the Joint Proposal additionally
address the furtherance of the Commission's policy of supporting increased
competition in electricity markets by unbundling rate elements and providing
back-out credits to customers who take supply service from ESCOs or marketers,
funding increased customer understanding of competitive electricity supply
options and efforts to obtain input from ESCOs and marketers regarding the
furtherance of the development of a competitive retail electricity supply market
in the Company's service territory.

     On May 3, 1996, the Commission issued a Final Generic Environmental Impact
Statement ("FGEIS") in Case 94-E-0952 with respect to the proposed action of
adopting a policy supporting increased competition in electricity markets. In
adopting such policy in Opinion No. 96-12, the Commission found that the FGEIS
"did not identify reasonably likely significant adverse impacts" of the action
except with respect to air quality, energy efficiency and research and
development in response to which the Commission adopted mitigation measures
including monitoring the environmental impacts of the action.(6) By Opinion No.
98-14 in Case 96-E-0909, based on an EAF filed by the Company on June 17,
1997,(7) the Commission found the potential environmental impacts of the rate
and restructuring plan for the Company therein adopted to be "within the range
of thresholds and conditions set forth in the FGEIS" thereby requiring no
further SEQRA action, but, "as a matter of discretion," monitoring of the
Company's restructuring and environmental impacts was implemented.(8)

     2.   CASE 00-G-1274

     On November 3, 1998, the Commission issued its Policy Statement Concerning
the Future of the Natural Gas Industry in New York State and Order Terminating
Capacity Assignment in Cases 93-G-0932 and 97-G-1380 ("Gas Policy Statement").
In the Gas Policy Statement, the Commission articulated its vision of the future
of the natural gas industry, which is to "facilitate development of a
competitive market; eliminate barriers to competition; provide guidance to LDCs
and marketers, especially with regard to expiring capacity contracts; and

----------
     (6)  Opinion 96-12 at 76-81.

     (7)  Opinion 98-14, Appendix D.

     (8)  Opinion 98-14 at 41-42.


<PAGE>


address customer inertia.(9) The Commission conducted an analysis under the
State Environmental Quality Review Act, determined that there would be no
significant environmental impact from adoption of the Gas Policy Statement and
issued a Notice of Determination of Non-Significance.(10)

     Case 00-G-1274 and the Joint Proposal address the furtherance of the
Commission's policy of supporting increased competition in natural gas retail
supply markets by unbundling rate elements and providing back-out credits to
customers who take supply service from marketers, funding increased customer
understanding of competitive gas supply options and funding efforts to obtain
input from marketers regarding the furtherance of the development of a
competitive retail as supply market in the Company's service territory. In that
regard the Joint Proposal is similar in principle to gas restructuring
settlements pursuant to the Gas Policy Statement of other companies that have
been approved by the Commission.(11)

III. EVALUATION OF ENVIRONMENTAL IMPACTS (PART 2 OF EAF)

     Specific environmental impacts that might result from the Joint Proposal
are highly unlikely. The Joint Proposal will not cause direct environmental
effects because the Joint Proposal does not involve physical activities that
might have impacts on the environment. Instead, the Joint Proposal might
contribute to the creation of circumstances that subsequently induce activities
which might cause environmental effects.

     In preparing this environmental assessment, the Signatory Parties have set
out an evaluation of a range of potentially conceivable secondary consequences
of the Joint Proposal in order to assist the Commission in its evaluation of
this matter. The Signatory Parties have relied on qualitative judgments as to
the potential changes resulting from the proposed actions and the magnitude and
importance of the corresponding potential environmental impacts.

     A.   IMPACT ON AIR

     The Signatory Parties were unable to identify any direct effects on air
emissions resulting from the Joint Proposal. The Commission, however, clearly
contemplated the possibility that

----------

     (9)  Gas Policy Statement at 3-4.

     (10) Gas Policy Statement at 9.

     (11) Case 99-G-0336, NIAGARA MOHAWK POWER CORPORATION - GAS MULTI-YEAR RATE
AND RESTRUCTURING PROPOSAL, Opinion No. 00-9 issued July 27, 2000; Case
99-G-1469, BROOKLYN UNION GAS COMPANY - MULTI-YEAR RESTRUCTURING AGREEMENT,
Order Establishing Interim Rate Plan issued December 26, 2000; Case 98-G-1589,
ROCHESTER GAS AND ELECTRIC CORPORATION - PLANS FOR GAS RATES AND RESTRUCTURING,
Order Adopting Terms of Joint Proposal issued February 28, 2001.

<PAGE>


increased competition could promote increased energy usage and, thereby, have
adverse air quality impacts. The Signatory Parties believe that the provisions
of the Joint Proposal intended to further the Commission's policy of supporting
the development of competitive markets for retail energy will neither directly
nor indirectly affect the supply market prices in a manner that would encourage
increased energy usage not within the range of thresholds and conditions set
forth in the FGEIS in Case 94-E-0952 or not within that contemplated by the
Commission in its Determination of Non-Significance reached in connection with
the Gas Policy Statement. The Signatory Parties also believe that the associated
unbundling of the Company's rates as provided for in the Joint Proposal will not
result in delivery service rates that would encourage energy usage not within
the range of thresholds and conditions set forth in the FGEIS in Case 94-E-0952
or not within that contemplated by the Commission in its Determination of
Non-Significance reached in connection with the Gas Policy Statement. As a
result, the Signatory Parties believe that any impacts on air quality resulting
from the Joint Proposal are within the range of thresholds and conditions set
forth in the FGEIS in Case 94-E-0952 and within those contemplated by the
Commission in its Determination of Non-Significance reached in connection with
the Gas Policy Statement.

     B.   IMPACT ON WATER

     The Signatory Parties were unable to identify and direct effects on water
quality resulting from the Joint Proposal. As discussed in the Impact on Air
section above, the Joint Proposal could result in an increased demand for
electricity or natural gas. This increased demand in turn could contribute to
the need to construct new production, transmission or distribution facilities to
serve the increased demand. With such new construction there could be the need
to conduct work in environmentally sensitive areas such as wetlands or streams.
While this work could potentially impact the environment, it would be subject to
all applicable federal and state environmental regulatory requirements including
SEQRA review prior to construction. As a result and as the Commission found with
respect to gas restructuring, "these speculative impacts need not be considered
at this time."(12) With regard to electric restructuring, this similar potential
effect would be within the range of thresholds and conditions set forth in the
FGEIS in Case 94-E-0952.

     C.   IMPACT ON LAND

     The Signatory Parties were unable to identify any direct effects on land
use resulting from the Joint Proposal. However, as indicated above, new
construction or expansion of production, transmission or distribution facilities
could have potential environmental impacts. These impacts, however, would be
mitigated by regulatory requirements and SEQRA review at the time as noted by
the Commission in its Determination of Non-Significance reached in connection
with the Gas Policy Statement and within the range of thresholds and conditions
set forth in the FGEIS in Case 94-E-0952.

----------
(12) Gas Policy Statement, Notice of Determination of Non-Significance at 1-2.

<PAGE>


     D.   IMPACT ON PLANTS AND ANIMALS

     The Signatory Parties were unable to identify and direct effects on plants
and animals resulting from the Joint Proposal. However, as indicated above, new
construction or expansion of production, transmission or distribution facilities
could have potential environmental impacts. These impacts, however, would be
mitigated by regulatory requirements and SEQRA review at the time as noted by
the Commission in its Determination of Non-Significance reached in connection
with the Gas Policy Statement and within the range of thresholds and conditions
set forth in the FGEIS in Case 94-E-0952.

     E.   IMPACT ON AGRICULTURAL LAND RESOURCES

     The Signatory Parties were unable to identify any direct effects on
agricultural land resources resulting from the Joint Proposal. However, as
indicated above, new construction or expansion of production, transmission or
distribution facilities could have potential environmental impacts. These
impacts, however, would be mitigated by regulatory requirements and SEQRA review
at the time as noted by the Commission in its Determination of Non-Significance
reached in connection with the Gas Policy Statement and within the range of
thresholds and conditions set forth in the FGEIS in Case 94-E-0952.

     F.   IMPACT ON AESTHETIC RESOURCE

     The Signatory Parties were unable to identify any direct effects on
aesthetic resource resulting from the Joint Proposal. However, as indicated
above, new construction or expansion of production, transmission or distribution
facilities could have potential environmental impacts. These impacts, however,
would be mitigated by regulatory requirements and SEQRA review at the time as
noted by the Commission in its Determination of Non-Significance reached in
connection with the Gas Policy Statement and within the range of thresholds and
conditions set forth in the FGEIS in Case 94-E-0952.

     G.   IMPACT ON HISTORIC AND ARCHEOLOGICAL RESOURCES

     The Signatory Parties were unable to identify any direct effects on
historic and archeological resources resulting from the Joint Proposal. However,
as indicated above, new construction or expansion of production, transmission or
distribution facilities could have potential environmental impacts. These
impacts, however, would be mitigated by regulatory requirements and SEQRA review
at the time as noted by the Commission in its Determination of Non-Significance
reached in connection with the Gas Policy Statement and within the range of
thresholds and conditions set forth in the FGEIS in Case 94-E-0952.

     H.   IMPACT ON OPEN SPACE AND RECREATION

     The Signatory Parties were unable to identify and direct effects on open
space and recreation resulting from the Joint Proposal. However, as indicated
above, new construction or expansion of production, transmission or distribution
facilities could have potential environmental impacts. These impacts, however,
would be mitigated by regulatory requirements and SEQRA review at the time as
noted by the Commission in its Determination of Non-Significance reached in
connection with the Gas Policy Statement and within the range of thresholds and
conditions set forth in the FGEIS in Case 94-E-0952.

     I.   IMPACT ON TRANSPORTATION

     The Signatory Parties were unable to identify any direct effects on
transportation resulting from the

<PAGE>


Joint Proposal. However, as indicated above, new construction or expansion of
production, transmission or distribution facilities could have potential
environmental impacts. These impacts, however, would be mitigated by regulatory
requirements and SEQRA review at the time as noted by the Commission in its
Determination of Non-Significance reached in connection with the Gas Policy
Statement and within the range of thresholds and conditions set forth in the
FGEIS in Case 94-E-0952.

     J.   IMPACT ON ENERGY

     The Commission clearly contemplated the possibility that increased
competition could promote increased energy usage. The Signatory Parties believe
that the provisions of the Joint Proposal intended to further the Commission's
policy of supporting the development of competitive markets for retail energy
will neither directly or indirectly affect the supply market prices in a manner
that would encourage increased energy usage not within the range of thresholds
and conditions set forth in the FGEIS in Case 94-E-0952 or not within that
contemplated by the Commission in its Determination of Non-Significance reached
in connection with the Gas Policy Statement. The Signatory Parties also believe
that the associated unbundling of the Company's rates as provided for in the
Joint Proposal will not result in delivery service rates that would encourage
energy usage not within the range of thresholds and conditions set forth in the
FGEIS in Case 94-E-0952 or not within that contemplated by the Commission in its
Determination of Non-Significance reached in connection with the Gas Policy
Statement.

     K.   NOISE AND ODOR IMPACT

     The Signatory Parties were unable to identify any direct noise and odor
effects resulting from the Joint Proposal. However, as indicated above, new
construction or expansion of production, transmission or distribution facilities
could have potential environmental impacts. These impacts, however, would be
mitigated by regulatory requirements and SEQRA review at the time as noted by
the Commission in its Determination of Non-Significance reached in connection
with the Gas Policy Statement and within the range of thresholds and conditions
set forth in the FGEIS in Case 94-E-0952.

     L.   IMPACT ON PUBLIC HEALTH

     The Signatory Parties were unable to identify any direct effects on public
health resulting from the Joint Proposal because under the Joint Proposal the
Company would continue to have the responsibility to maintain its facilities for
the transmission and distribution of natural gas and electricity in conformance
with all applicable regulatory requirements.

     M.   IMPACT ON GROWTH AND CHARACTER OF COMMUNITY OR NEIGHBORHOOD

     The Joint Proposal's effect of reducing the cost of electricity and gas to
consumers will have a positive effect on the economic well-being of communities
in the Company's service territory. Price reductions along with the funding of
economic development initiatives as provided for in the Joint Proposal will
encourage local business growth and the retention and growth of employment. They
will also encourage the relocation of businesses to the Company's service
territory from outside New York State. In addition, the Joint Proposal includes
incentive regulation provisions which encourage the education of consumers
regarding energy competition to facilitate the development of the competitive
retail energy supply market.

     It is possible that lower gas prices could lead to a potential for gas
distribution franchise expansions, as the Commission has recognized previously.
The potential for such expansions under the Joint Proposal is

<PAGE>


limited, however, in light of the 20% penetration limitations on the
availability of the gas back out credits. Therefore, the potential impacts are
considered to be indistinguishable from those that would occur in the absence of
the Joint Proposal.

IV.  SIGNIFICANCE OF ENVIRONMENTAL IMPACTS

     After a review of the changes called for under the Joint Proposal, the
Signatory Parties conclude that no further environmental review is necessary
with respect to the Joint Proposal. No significant environmental impact which
would result from the subject Joint Proposal was identified. Any potential
effects are within the range of thresholds and conditions set forth in the FGEIS
in Case 94-E-0952 with respect to electric restructuring and within the
Commission's Determination of Non-Significance in Cases 93-G-0932 and 97-G-1380
with respect to gas restructuring.