Exhibit 99

                                STATE OF NEW YORK
                            PUBLIC SERVICE COMMISSION

                                              At a session of the Public Service
                                                Commission held in the City of
                                                   Albany on July 19, 2006

COMMISSIONERS PRESENT:

William M. Flynn, Chairman
Patricia L. Acampora
Maureen F. Harris
Robert E. Curry, Jr.
Cheryl A. Buley

CASE 05-E-0934 -  Proceeding on Motion of the Commission as to the Rates,
                  Charges, Rules and Regulations of Central Hudson Gas &
                  Electric Corporation for Electric Service.

CASE 05-G-0935 -  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 RATE PLAN

                      (Issued and Effective July 24, 2006)

BY THE COMMISSION:

                                  INTRODUCTION

            This order establishes a three-year rate plan for electric and gas
service provided by Central Hudson Gas & Electric Corporation (Central Hudson,
the Company). The terms and conditions established by this order are generally
consistent with terms and conditions that were set forth in a contested Joint
Proposal submitted by Central Hudson, New York State Department of Public
Service Staff (Staff), Multiple Intervenors and the United States Department of
Defense and all other Federal Executive Agencies (DOD).

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CASE 05-E-0934, et al.

                               PROCEDURAL HISTORY

            On July 29, 2005, Central Hudson filed tariff amendments to increase
its electric and gas rates each of the next three rate years. For the initial
rate year, Central Hudson proposed to increase electric and gas total revenues
by approximately $52.8 million (13%) and $18.1 million (15%), respectively. The
filing was suspended and these cases were established to examine the Company's
proposals.(1)

            On November 21, 2005, testimony opposing the Company's submission
was filed by Staff, the New York State Consumer Protection Board (CPB), and
Multiple Intervenors. The Company filed supplemental testimony on November 28,
2005. Rebuttal testimony was filed on December 14, 2005 by Central Hudson, Staff
and Multiple Intervenors. Direct testimony was filed by DOD on December 19,
2005. In early January, the Company submitted additional supplemental testimony
in response to a Commission Order in Case 04-G-0463.(2)

            Central Hudson provided its notice of intent to enter into
settlement negotiations by letter dated January 6, 2006. In accordance with
applicable Commission rules, the notice was reported to the Commission on
January 10, 2006.(3)

            On January 12, 2006, four parties contacted the presiding officers
and proposed a one-month postponement of the evidentiary hearings scheduled to
commence on January 18, 2006. The evidentiary hearings were cancelled and a
procedural ruling

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(1)   Order Suspending Major Rate Filings (issued August 24, 2005); Further
      Suspension of Major Rate Filings (issued December 14, 2005).

(2)   Case 04-G-0463, Central Hudson Gas & Electric Corporation - Tariff Filing,
      Order Approving Real-Time Metering Plans, Adopting Daily Balancing Charges
      and Procedures, and Establishing Further Proceedings (issued November 29,
      2005) at 11 (directing Central Hudson to propose and support the permanent
      rate for daily balancing service in this gas rate case).

(3)   16 NYCRR 3.9(a)(2).


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CASE 05-E-0934, et al.

was issued that granted the postponement and established target dates for the
submission of a joint proposal.(4)

            Public statement hearings were held on March 13 and 14, 2006 in
Poughkeepsie, Fishkill, Newburgh and Kingston before Administrative Law Judge
Michelle L. Phillips. In addition, Commissioner Leonard A. Weiss attended the
public statement hearing in Poughkeepsie. In total, 33 people made statements on
the record. The speakers generally opposed the rate increases sought by Central
Hudson.

            Several speakers expressed concern that low and fixed income
customers could not afford any further increase. Many noted that their bills had
already shown significant increases due to the flow-through of commodity costs.
Still others stated that schools and businesses would have to pass along any
increases through higher taxes and increased prices for goods and services. Some
suggested that, if any increase was granted to Central Hudson, it should
approximate cost-of-living increases received by the average working person in
the Company's service territory. A few opined that the company's level of
service did not warrant an increase. Finally, some questioned whether the
requested increase was justified, especially given the Company's/CH Energy
Group's reported profits of approximately $40 million each of the last two
years.

            Numerous public comments also were received by the Commission
through the Department of Public Service Web site and the toll-free telephone
line, and through the U.S. Mail. The concerns expressed therein were similar to
those expressed at the public statement hearings.(5) In addition, resolutions
opposing the Central Hudson request were received from the Towns of Newburgh,
Plattekill, Poughkeepsie and Wappingers Falls.

----------
(4)   See Procedural Ruling on Revised Process and Schedule (issued January 17,
      2006).

(5)   One of the comments consisted of a petition, with approximately 25
      signatures, opposing the requested rate increase.


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CASE 05-E-0934, et al.

            At a conference held on March 9, 2006, the parties agreed to meet
with a settlement judge,(6) the Company agreed to further extend the suspension
period to the end of August 2006, and evidentiary hearings were rescheduled.

            At a procedural conference held on April 3, 2006, several of the
parties reported reaching an agreement in principle and proposed a new
procedural schedule that would allow them to finalize a joint proposal.(7)

            The Joint Proposal, originally filed with the Commission on April
18, 2006, was subsequently restated on April 19, 2006 and re-filed on April 20,
2006. It recommends a three-year rate plan that is supported by the Company,
Staff, Multiple Intervenors and DOD. The Joint Proposal is opposed by CPB,
Public Utility Law Project (PULP), Small Customer Marketer Coalition/Retail
Energy Supply Association (SCMC/RESA) and Select Energy New York, Inc. (Select
Energy).

            At evidentiary hearings held on May 4 and 5, 2006, witness panels
representing CPB, the Company and Staff were cross-examined concerning their
support of or opposition to the Joint Proposal. In addition, the prefiled
testimony and exhibits submitted by the Company, Staff, CPB, Multiple
Intervenors and DOD were moved into evidence. Statements in Support and in
Opposition were marked for identification but not placed into evidence. In all,
the record consists of 1672 transcript pages and 102 exhibits.

            Post-hearing briefs were filed by Staff, Central Hudson, Multiple
Intervenors, DOD, CPB, PULP and SCMC/RESA on

----------
(6)   Administrative Law Judge Jeffrey E. Stockholm was appointed as a
      settlement judge.

(7)   In light of the parties' report, the evidentiary hearings scheduled to
      commence on April 10, 2006 were postponed without date. Notice Postponing
      Evidentiary Hearings (issued April 4, 2006).


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CASE 05-E-0934, et al.

May 12, 2006. A revised post-hearing brief was submitted by Central Hudson on
June 5, 2006.(8)

            Public statement hearings on the Joint Proposal were held in
Poughkeepsie and Kingston on May 22, 2005. Seven people made statements on the
record. Most speakers stated that the Joint Proposal rates were too high. The
balance of the statements, for the most part, reiterated concerns that had been
expressed at the March public statement hearings (e.g., customers on fixed and
low incomes could not afford any increases; schools budgets would be affected
and local governments would have to pass along any increases through higher
taxes; and that, if any increase was granted to Central Hudson, it should
approximate cost-of-living increases received by the average working person in
the service territory). The written, telephonic and electronic comments that
were received on the Joint Proposal generally echoed the concerns expressed at
the May 22nd public statement hearings.

                 PROPOSED RATE PLAN AND THE ISSUES BY SECTION(9)

            The proposed rate plan consists of a three-year term beginning on
July 1, 2006 and ending June 30, 2009. Its most salient provisions are
summarized below.

Electric Revenues, Rates and Bill Impacts

            Electric delivery revenues would increase by about $41.4, $6.1 and
$5.5 million, respectively, each rate year.

----------
(8)   On May 22 and 23, 2006, respectively, CPB moved to strike, in part, and
      PULP moved to strike in its entirety, the Company's post-hearing brief,
      claiming that it included statements that violated Commission guidelines
      and rules. On May 26, 2006, the Company responded, opposing both motions.
      On June 5, 2006, a ruling was issued granting, in part, the motions to
      strike. In compliance with the ruling, the Company submitted a revised
      post-hearing brief.

(9)   In the following discussion, the terms of the Joint Proposal, along with
      any issues related thereto, are generally summarized and discussed. The
      term Joint Proposal refers to the Joint Proposal as restated April 19,
      2006.


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CASE 05-E-0934, et al.

However, by using a portion of electric depreciation reserve, the initial rate
year's increase would be moderated, producing three equal increases of
approximately $17.9 million each rate year.

            The revenue allocations among all service classifications, except
service classification 9, would be constrained to a minimum increase of 0.75
times the system average and a maximum of 1.25 times the system average. The
increase for service classification 9 would be constrained to 0.5 times the
system average and would include an additional $50,000 allocation of revenue
requirement responsibility.

            The resulting bill changes for each service classification and each
rate year are summarized in Appendix B. The delivery bill increases approximate
10.4%, 9.4% and 8.6%, respectively, each rate year. The delivery bill increases
for the residential service class would be about 12.9%, 10.5% and 9.5%,
respectively, each rate year. The typical residential electric customer (using
500 kWh per month) would experience a bill impact of about 5.4% in the first
rate year.

            Electric rates would be further unbundled to more accurately
separate and reflect commodity and delivery costs and components. The existing
Energy Cost Adjustment Mechanism, which is used to recover electric commodity
costs from Central Hudson customers, would be modified to remove New York
Independent System Operator Ancillary Services Charges and New York Power
Authority Transmission Access Charges. As of July 1, 2007, such costs will be
recovered in the Market Price Charges and Hourly Pricing Programs.

            Three Market Price Charges would be implemented on July 1, 2006. The
first would apply to service classifications 1 (residential), 2 (general), and 9
(traffic signal); the second would apply to service classification 6
(residential time-of-use); and the third would apply to service classifications
5 (area lighting) and 8 (public street and highway lighting). The proposed
Market Price Charges would be based on the average load shapes for each class.
As of July 1, 2007, the Market Price Charge for service classification 6 would
be further


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CASE 05-E-0934, et al.

differentiated into on- and off-peak rates. Also, as of July 1, 2007, Central
Hudson would cease reimbursing energy service companies (ESCOs) for ancillary
service costs and New York Power Authority Transmission Access Charges.

Gas Revenues, Rates and Bill Impacts

            Gas delivery revenues would increase by $8,003,000 (about 19%) and
by $6,057,000 (about 11.8%) in the first and second rate years, respectively.
There would be no increase in the third rate year. The proposed gas revenue
requirements are moderated by deferring and amortizing portions of the gas
revenue increases. They also include an interruptible profit imputation of $1
million.(10)

            Gas rates, like the electric rates, would be further unbundled to
reflect the transfer of additional commodity-related costs to the proposed
Merchant Function Charges.

            For residential gas customers, the minimum charge would increase
from $7.20 to $14 a month. As shown in Appendix F, the annual gas rate increase
for a typical gas heating customer (1100 Ccf per year) will be $92.45 (6.36%).

            A new subclass will be established in service class 11,
"Distribution Large Mains" ("SC 11DLM"), for customers using over 400,000
Mcf/year. The costs allocated to SC 11DLM are set forth in Appendix E and they
exclude, among other things, the cost of mains that are less than 6 inches in
diameter. The U.S. Military Academy at West Point (USMA) would receive service
in accordance with the provisions of the new SC 11DLM class after

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(10)  Because of the imputation, the Company is permitted each rate year to
      retain the first $1 million in revenues it receives from interruptible
      service and service to electric generators. However, if the margin does
      not reach $1 million in any rate year, the Company is authorized to
      surcharge ratepayers for 100% of the first $250,000 and 90% of the
      remaining shortfall. If the margin exceeds $1 million in any rate year,
      the Company must credit ratepayers for 100% of the first $250,000 and 90%
      of the remaining shortfall.


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CASE 05-E-0934, et al.

the execution of a contract between Central Hudson and the U.S. Department of
the Army on behalf of USMA.(11)

            The existing Gas Supply Charge (GSC), Firm Transportation Rate
(FTR), Interruptible Transportation Rate (ITR) and Interruptible Gas Rate (IGR),
which are related to the recovery of gas commodity supply costs, would continue,
subject to the proposed gas balancing modifications.

Gas Balancing

            Effective April 1, 2007, new gas balancing procedures would apply to
interruptible and firm transportation customers and to aggregated transport
customers. Applicable procedures described in the Company's July 2005 "Report on
Gas Balancing and Cashout Issues" would be followed in implementing the new gas
balancing procedures. Incremental software costs for implementing the procedures
would receive deferral accounting.(12)

            For the interruptible and firm transportation customers, the
volumetric balancing service charge would be implemented as two separate rates:
one for daily balanced customers and one for monthly balanced customers.(13) The
charges would be updated at least annually.(14) The updates would be based on
each service classification's total consumption and deliveries during the
preceding winter period and the Company's then most recently available gas
storage and other relevant costs.(15)

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(11)  Additional, non-rate provisions regarding Central Hudson and USMA are set
      forth in Section XVIII.

(12)  Any such amounts would be subject to carrying charges at the pre-tax
      authorized rate of return.

(13)  See Appendix K.

(14)  SC 11DLM rates would be excepted from the proposed April 1, 2007 update
      and would remain in effect until March 31, 2008. Effective April 1, 2008,
      the charges for SC 11 and SC 11DLM would be determined separately, based
      on the specific peak day history for each class.

(15)  The Company would file a statement of Gas Balancing Rates at least 30 days
      prior to the effective date of an update.


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CASE 05-E-0934, et al.

            Interruptible and firm transportation customers would be allowed to
designate an ESCO to make supply nominations and effectuate imbalance exchanges.
Commencing April 1, 2007, balancing service charges would be billed to the
customers, while imbalance penalties would be billed to the customer's ESCO.(16)
ESCOs will be required to enter into agreements with Central Hudson to pay for
such penalties. Prior to April 1, 2007, all charges would continue to be billed
to customers.

            There also are provisions for the treatment of customers under
negotiated contracts, the term of the option period, notification regarding a
customer's selected balancing option, the elimination of the current daily
balancing provisions, monthly and daily "cash-out" procedures, applicable
under-delivery index prices, revisions to over- and under-deliveries for monthly
balanced customers, purchasing of over-deliveries, and the delivery requirements
that would apply after Central Hudson issues an Operational Flow Order. Finally,
the Company will pursue withdrawal of its pending rehearing petition concerning
gas balancing.

            Gas balancing provisions for the aggregated transportation customers
include reconciliations and periodic true-ups. Starting April 1, 2007, ESCOs can
trade offsetting monthly imbalances as part of the semi-annual
reconciliation/true-up.

Rate Unbundling

            Existing electric backout credits and related treatment would be
maintained through June 30, 2007, except that the cost of the electric backout
credits will be charged against the excess electric depreciation reserve.
Commencing July 1, 2007, the electric backout credits would be replaced by four
Merchant Function Charge groups and by the lost revenue provisions.

----------
(16)  Balancing Service Charge revenues would be credited to the Gas Supply
      Charge.


                                      -9-
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CASE 05-E-0934, et al.

            The four electric Merchant Function Charge groups will be designated
MFC1, MFC2, MFC3 and MFC4. MFC1 applies to service classifications 1 and 6; MFC2
applies to service classifications 2 and 3; MFC3 applies to service
classifications 3 and 13; and MFC4 applies to service classifications 5, 8, and
9. The new MFCs include cost-based components to represent commodity-related
purchasing, credit and collection, call center costs, advertising and
promotions, and related Administrative and General (A&G) expenses and rate base
items allocated to each group.

            The existing gas backout credits will continue to be recovered
through the Gas Supply Charge through June 30, 2007. Gas delivery service MFCs,
analogous to those for electric delivery service, would be implemented on July
1, 2007, with MFC 1 applicable to service classification 1 and MFC 2 applicable
to service classification 2.

            Each MFC group will be further sub-divided into an MFC(A) and an
MFC(B). MFC(A) includes the allocated portion of credit and collection function
costs and 50% of procurement-related call center function costs, plus associated
A&G and rate base items. MFC(B) includes commodity purchasing function costs,
allocated portions of advertising & promotions function costs and 50% of
procurement-related call center function costs, plus associated A&G and rate
base items.

            Full service customers will be billed for both the MFC(A) and
MFC(B). Retail access customers will be billed by for MFC(A) only.(17)

            Should total monthly migration of electric or gas customers exceed
30%, short run avoided costs will be established through a collaborative effort
among the parties and

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(17)  Customers who purchase their commodity service from an ESCO that is not
      participating in the Company's POR Program would not be billed a MFC by
      Central Hudson. The discount rate charged to ESCOs that participate in
      Central Hudson's POR Program would be the same for all service
      classifications and would consist of an amount reflecting
      commodity-related uncollectibles costs and a time value of money factor of
      0.25%.


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CASE 05-E-0934, et al.

be submitted for Commission approval. Central Hudson will propose, no later than
October 1, 2006, an unbundled bill format for approval by the Commission.

Capital Expenditures

            Electric capital expenditures, excluding the Allowance for Funds
Used During Construction (AFUDC), would be set at $158.078 million ($51.944
million for the first rate year, $52.530 million for the second rate year, and
$53.604 million for the third rate year). If actual expenditures fall short of
$158.078 million by the end of the third rate year, the amount of the shortfall
multiplied by 1.5 times the average authorized pre-tax rate of return will be
deferred for ratepayer benefit.(18)

            Gas plant, excluding both the proposed gas infrastructure
enhancements (described in Section XIV.E of Joint Proposal(19)) and AFUDC, would
be set at $27.495 million ($10.397 million, $9.354 million and $7.744 million
for rate years one, two and three, respectively). If actual expenditures fall
short of $27.495 million by the end of the third rate year, the amount of the
shortfall multiplied by 1.5 times the average authorized pre-tax rate of return
will be deferred for ratepayer benefit.(20) If actual expenditures for gas
infrastructure enhancements exceed $15.75 million, the amount above $15.75
million may be applied to reduce the gas plant shortfall.

            The capital expenditures for common plant would be set, reflecting
AFUDC, at $21.693 million ($7.732 million, $7.031 million, and $6.930 million
for each rate year, respectively). Again, should actual expenditures fall short
of $21.693 million by the end of rate year three, the shortfall

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(18)  Commencing July 1, 2009, any such amount would be subject to carrying
      charges calculated at the authorized pre-tax rate of return.

(19)  The Joint Proposal erroneously refers to Section XIII.G. The correct
      reference is Section XIV.E.

(20)  Commencing July 1, 2009, any such amount would be subject to carrying
      charges calculated at the authorized pre-tax rate of return.


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CASE 05-E-0934, et al.

multiplied by 1.5 times the average authorized pre-tax rate of return will be
deferred for ratepayer benefit.(21)

Depreciation

            The average service lives, net salvage factors and life tables used
to calculate the theoretical depreciation reserve and to establish the
depreciation expense reflected in the revenue requirements are set forth in
Appendix J and will continue to be used until such levels are changed by the
Commission. No adjustments will be made to the depreciation rates used prior to
June 30, 2006.

            A new depreciation study will be filed by the Company when it files
the next major gas, electric or combined rate case. If a combination gas and
electric filing is made, the depreciation study would address gas, electric and
common plant accounts; if the filing is limited to only gas or only electric
issues, the study need only address the gas or the electric plant accounts.

Deferrals

            The Company will continue to use deferral accounting for certain
specified items.(22) In addition, the Company will be authorized to defer items
specified in and approved by this Order. The deferrals listed in Appendix I will
be subject to the Limitation of Deferral provision set forth under the Section X
(Earnings Sharing).

Earnings Sharing

            The Company's allowed return on equity would be 9.6%. If the Company
achieves a regulatory rate of return on common equity above 10.6% in either the
electric or gas department, the earnings would be shared as follows: above 10.6%
and up to 11.6%, equal (50/50) sharing between the Company and ratepayers;

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(21)  Commencing July 1, 2009, any such amount would be subject to carrying
      charges calculated at the authorized pre-tax rate of return.

(22)  See Section IX.


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CASE 05-E-0934, et al.

above 11.6% and up to 14.0%, shared 35%/65% between the Company and ratepayers,
respectively; and any earnings above 14.0% would be deferred for customers'
benefit.(23)

            If the Company achieves a return on common equity above 10.6% in
either the electric or gas department, and experiences an under-recovery of
migration-related net lost revenues, the net lost revenues will be offset by the
Company's portion of the earnings above 10.6%.(24)

Additional Rate Provisions

            There would be additional rate-related requirements and conditions,
including, but not limited to, the following: accounting procedures for gas
mains and services; permitted balance sheet offsets; cessation of the Benefit
Fund, but with the preservation and continuation of certain specified uses;
deferral conditions and reporting requirements regarding costs for the East
Fishkill Substation; a shortfall protection mechanism for electric transmission
right-of-way (ROW) maintenance costs; authorization to record gas and electric
revenues attributable to the extension of the suspension period to the end of
August; establishment of the rate allowances and the deferral and reporting
requirements for manufactured gas plant (MGP) site investigation and remediation
(SIR) costs; requirements for the deferral and sharing of property tax costs;
and the establishment of factors for common costs allocation, electric losses
and lost and unaccounted for gas. They are set forth in Section XI.

Low-Income Program

            A new low-income program, instituted in two phases, will replace
Central Hudson's current low-income program ("Powerful Opportunities" or "POP").
An interim program will

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(23)  Ratepayers' portions would be subject to carrying charges at the pre-tax
      authorized rate of return.

(24)  Any remaining net lost revenues would be deferred for future recovery
      subject to carrying charges calculated at the authorized pre-tax rate of
      return.


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CASE 05-E-0934, et al.

replace the POP Program and continue until the second phase ("Enhanced Powerful
Opportunities" or "EPOP") is operational. In both phases, the low-income program
will be directly administered and managed by the Company. Program funding will
be $1.148 million, $1.32 million, $1.50 million, for each of the three rate
years, respectively. Unless adjusted by Commission order, the funding will
continue at $1.5 million per rate year thereafter. Differences between the
funding level and actual expenditures during a rate year will be deferred.(25)
If such differences are due to over-expenditures, the deferral will be limited
to no more than 15% of the rate year funding level. If such differences are due
to under-expenditures, the remaining balance will be used in subsequent rate
years for low-income program expenditures.

            Design, implementation and other program issues for the Enhanced
Powerful Opportunities Program will be established through a collaborative
effort among the Company and other interested parties. This effort will begin
not later than 10 days after Commission action on the Joint Proposal. Working
with this collaborative, the Company will complete its development of a detailed
EPOP program proposal within 45 days of the Commission's action on this Joint
Proposal. The resulting proposal will be submitted for Commission approval and,
once approved, would be completely implemented no later than September 1, 2007.

            The interim program will replace the existing low-income program as
soon as reasonably feasible, so that there is no lapse in the availability of a
low-income program.

Customer Service Quality Performance Mechanism

            The current Customer Service Quality Performance mechanism will
remain in effect through December 31, 2006. A new Customer Service Quality
Performance mechanism will become effective on January 1, 2007. A maximum,
potential adjustment

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(25)  The deferred amounts would be subject to carrying charges calculated at
      the authorized pre-tax rate of return.


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CASE 05-E-0934, et al.

of 25 basis points, to be calculated on a combined electric and gas basis, will
be incurred if the specified service quality targets are not met.

Gas Safety

            Gas Safety targets and rate adjustment levels will continue at their
present levels. The targets will be changed for and after calendar year 2008 and
will remain at those levels until changed by the Commission. All gas safety
target metrics will be calculated on a calendar year basis. The targets and rate
adjustments apply to leak management, prevention of excavation damages, and
emergency response.

            Additional targets will be established for expenditures that enhance
the gas infrastructure, namely, the replacement of gas cast iron and steel pipe.
The target for such expenditures will be set at $15.75 million over the three
rate years, but not less than $4.5 million in each calendar year. If actual
expenditures fall short of the target level by the end of 2009, Central Hudson
would defer, for ratepayer benefit, the amount of the shortfall multiplied by
1.5 times the average authorized pre-tax rate of return.(26) This deferral would
be the sole remedy against the Company for failure to fully expend the forecast
level for replacement of certain cast iron and steel mains and services.(27)
There are also reporting and record keeping requirements related to the gas
safety mechanisms and targets.

Electric Reliability

            Effective January 1, 2006, the target for the Customer Average
Interruption Duration Index (CAIDI) will be 2.50, and the target for the System
Average Interruption Frequency Index (SAIFI) will be 1.45 for each calendar
year. A rate adjustment of 10 basis points (electric) will be assessed against
Central

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(26)  Commencing on January 1, 2010 such deferral will be subject to carrying
      charges calculated at the authorized pre-tax rate of return.

(27)  See Section XIV.E(1).


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Hudson for each failure to satisfy an annual target threshold. Certain events,
such as "major storm" outages or catastrophic events, would be excluded from the
indices' calculation.

            In addition to the SAIFI and CAIDI targets, reliability-oriented
targets for significant construction projects would be established. They include
rate adjustments for failure to: complete 100 circuit miles of enhanced
distribution line clearing during each respective rate year (5 basis points per
rate year); complete and energize the proposed East Kingston substation by June
30, 2007 (5 basis points, electric); and complete reliability-related
construction projects in calendar years 2007 and 2008, respectively(28) (5 basis
points per calendar year).

            The Company will pursue withdrawal of its rehearing petition
concerning electric reliability. The Joint Proposal also recommends a 37.5 basis
point penalty for not meeting reliability target thresholds in 2002 and 2004 and
would allow the Company to reverse the 2005 reliability penalty.

            The proposed rates support a workforce of 855 employees and allow
Central Hudson to hire additional line mechanics. Staff and the Company will
meet quarterly to discuss reliability, and employee levels and utilization, and
the Company will file compliance reports concerning the electric reliability
targets. The reliability performance mechanism will remain in place until the
Commission adopts a subsequent approach.

Meter Reading and Billing Studies

            A study of the costs and benefits of converting from bi-monthly
meter reading and billing to monthly meter reading and billing would be
developed by the Company and filed for Commission approval. It will identify the
costs associated with the conversion to monthly metering and billing and the net

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(28)  Such projects will be identified by Staff from among the electric
      reliability-related projects identified in the Company's updated capital
      forecasts.


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CASE 05-E-0934, et al.

revenue requirements effects, and include an implementation plan.

            An Automated Meter Reading (AMR) Pilot would be developed by the
Company and filed for Commission approval. It will include 5000 meters and be
funded from unused amounts that were set aside for such purposes. Total costs
will be capped at $1.5 million.

Retail Access

            The existing Market Match, Market Expo, ESCO Ombudsman, and ESCO
Referral programs would continue, as would the Competition Awareness and
Understanding Survey. In addition, one or two annual Energy Fairs would be
conducted by Central Hudson, in collaboration with Staff and ESCOs, prior to the
winter heating season. Finally, a Competition Education Campaign, aimed at
promoting customer migration, would be funded at $350,000 per rate year.(29)

                        PARTY COMMENTS ON JOINT PROPOSAL

Statements in Support(30)

      Central Hudson

            Central Hudson states that the Joint Proposal is a comprehensive
three-year rate plan that implements the Commission's policy objectives,
provides much needed rate relief, and proposes a rational outcome for these
proceedings. Central Hudson argues that the Joint Proposal should be adopted as
presented because it satisfies the Commission's criteria for proposed
settlements.(31)

            With respect to the requirement for consistency with law and policy,
Central Hudson asserts that the Joint Proposal

----------
(29)  Actual expenditure shortfalls below the $350,000 rate allowance will be
      deferred for expenditure on the same purposes in future rate years.

(30)  Statements in Support were marked for identification as Exhibits ("Ex.")
      63 (Multiple Intervenors), 65 (Central Hudson), and 66 (Staff) and are
      summarized below.

(31)  Ex. 65 at 2.


                                      -17-
<PAGE>

CASE 05-E-0934, et al.

provides just and reasonable rates that are based on extensively investigated
costs and found to be justified by the proponents. Central Hudson notes that the
settlement negotiations commenced after parties had engaged in extensive
discovery and filed their evidentiary cases, and that discovery continued
through negotiations. The Company contends that, as a result, parties were fully
aware of the revenues and costs used to develop the proposed rates.(32)

            The Company states that its cost elements increased in virtually
every area of its operations since the last time rates were increased. The
Company notes there have been significant negative rate allowances for pension
and other post-retirement benefit (OPEB) costs, which are no longer appropriate,
and therefore have been updated, consistent with applicable Commission
policy.(33)

            The Company observes that rate increases were moderated using the
book depreciation reserve in excess of the theoretical reserve, while still
preserving the previously established rate base. The Company continues that gas
rate moderation was achieved by reducing the size of the first year rate
increase and deferring the amortization of those assets to the beginning of the
second rate year.(34) The Company reports that electric and gas delivery rates
are fully unbundled, consistent with Commission policies.(35)

            Central Hudson argues that the Joint Proposal compares favorably
with the probable outcome of litigation and strikes a reasonable balance among
the parties' competing evidentiary positions.(36)

            The Company asserts that the Joint Proposal favors consumers. It
states that the allowed 9.6% rate of return on common equity is at the lower end
of a zone of reasonableness,

----------
(32)  Ex. 65 at 3-4.

(33)  Ex. 65 at 4.

(34)  Ex. 65 at 4-5.

(35)  Ex. 65 at 5.

(36)  Ex. 65 at 6-7.


                                      -18-
<PAGE>

CASE 05-E-0934, et al.

and is offset to a degree by the earnings sharing provisions. Central Hudson
argues that its ability to attain any return above 9.6% requires it to achieve
efficiencies in its operations. It adds that the opportunity for a return above
10.6% is restricted by the earnings sharing provisions and by a limitation on
future deferrals. According to the Company, these provisions, coupled with the
proposed rates and other provisions, favor consumers' interests.(37)

            The Company adds that the Joint Proposal precludes it from improving
earnings by deferring capital expenditures or electric transmission ROW
vegetation management programs because under-expenditures are subject to
requirements that the Company defer, for ratepayer benefit, 150% of the revenue
requirement equivalent of any shortfall over the three-year term.(38)

            According to Central Hudson, the rate increases should be viewed in
the context of recent rate decisions that have created a pent-up need for
increased rates and the amount of inflation since Central Hudson's delivery
rates were last increased. Central Hudson states that its delivery rates have
not increased in more than 12 years for electric service, and 15 years for
natural gas, and that its low electric rates, since 1993, have "saved customers
hundreds of millions of dollars compared to the state average."(39)

            In support of the proposed rate increases, Central Hudson states
that, over the last ten years, customers' use of electricity and natural gas has
risen by 20% and 27%, respectively; the percent of residential customers with
air conditioning increased from 52% in 1993 to more than 85% by 2005; average
household electricity use increased by 15 percent from 1993 to today; and since
1993, the consumer price index has risen by 39 percent, raising the costs
associated with providing service. Meanwhile, Central Hudson contends that its
employee levels (net of the former power plants) declined by nearly

----------
(37)  Ex. 65 at 7-8.

(38)  Ex. 65 at 8.

(39)  Ex. 65 at 8-9.


                                      -19-
<PAGE>

CASE 05-E-0934, et al.

25 percent since 1993, while the number of electric and gas customers increased
by 11% (30,000) and 17% (9,900), respectively. The Company claims that this
represents an average productivity trend of 4% per year and a customer to
employee ratio of 425 to one, placing Central Hudson in the top quartile among
utilities nation-wide.(40)

            Central Hudson also highlights its customer service, pointing to its
tree trimming programs' 33% reduction in the number of customers experiencing
storm outages between 2002 and 2004; its infrastructure improvements that
avoided outages to more than 28,000 customers per year; and its positive
customer surveys in which overall customer satisfaction rose from 90.2 percent
to 95.1 percent from 1998 to 2004.(41)

            The Company also asserts that the Joint Proposal has support from
generally adverse parties, including Staff, Multiple Intervenors, and DOD. In
addition, it reports that the proposed Low-Income Program reflects CPB and
PULP's active participation. Finally, Central Hudson argues these proceedings
provided an adequate record basis for the Commission to render a rationally
based decision.(42)

      Staff

            Staff asserts that the Joint Proposal should be adopted because it
satisfies the established criteria for judging the reasonableness of
settlements. Staff notes that a diverse group of parties support the Joint
Proposal, including Multiple Intervenors and DOD.(43)

            Staff states that the rate increases are necessary to meet
escalating pension and OPEB costs and other inevitable cost increases. To
mitigate the increases, it notes that various rate design and rate phase-in
mechanisms were devised to alleviate the rate shock that would otherwise occur.
Staff

----------
(40)  Ex. 65 at 9-10.

(41)  Ex. 65 at 10.

(42)  Ex. 65 at 11.

(43)  Ex. 66 at 8.


                                      -20-
<PAGE>

CASE 05-E-0934, et al.

continues that the three-year plan provides certainty on the magnitude and
timing of the increases, so consumers can effectively plan their energy usage
and so the Company can provide safe and adequate service. According to Staff,
the time between rate filings permits Central Hudson to reduce costs and
increase efficiencies, which will benefit ratepayers who share in the resulting
higher earnings.(44)

            Staff contends the record adequately justifies adoption of the Joint
Proposal's terms. It states that financial terms are derived from Central
Hudson's original testimony and from discovery. Staff asserts that parties had
ample opportunity to review the Company's support and to conduct extensive
discovery. Staff contends that the Joint Proposal's appendices demonstrate a
detailed agreement as to the costs and revenues underlying the proposed base
rates.(45)

            Staff observes that the proposed, successive electric rate increases
are moderated and phased-in. Staff contends that the income statements
demonstrate that the increase in revenue requirement is constrained, in part, by
providing for a reasonable, but modest, ROE.(46) Staff states that gas rates
will increase but the rate plan provides for moderation and for no increase in
the third rate year, both of which benefit customers.(47)

            Staff states that the rate increases are admittedly sizable, but
inevitable - mainly due to pension and OPEB obligations, which cannot be
escaped, and to preserving safe and reliable service, which requires
expenditures. Staff notes that a downturn in financial markets required the
Company to make substantial contributions to pension and OPEB plans, a trend
that is expected to continue. Staff states that rates must be adjusted to
recognize not only this fact, but the corresponding fact that earnings from
pension and OPEB plans are no longer

----------
(44)  Ex. 66 at 8-9.

(45)  Ex. 66 at 9-10.

(46)  Ex. 66 at 12.

(47)  Ex. 66 at 13-14.


                                      -21-
<PAGE>

CASE 05-E-0934, et al.

available as a rate offset. Staff points to its appendices to demonstrate that
these expenses account for 55% of the electric increase and 47% of the gas
increase, plus another 32% of the gas rate increase for recovery of prior
pension and OPEB expense deferrals. Staff continues that reliability
expenditures and other mandated costs amount to another 20% of the electric
increase and 8% of the gas increase. According to Staff, the overall impact of
such expenditures, 75% of the electric increase and 87% of the gas increase,
constitute the bulk of the rate increase.(48)

            Staff asserts that the bill impacts were constrained so that a
typical residential electric customer using 500 kWh per month will see a 5.4%
bill impact in rate year one, 5.0% in rate year two, and 4.6% in rate year
three, while a typical residential annual heating gas customer will see bill
impacts of 6.36% in the first rate year and 5.17% in the second rate year. Staff
argues that the proposed bill impacts are acceptable because the underlying
rates have been structured to satisfy obligations for pension/OPEBs and safety
and reliability, and to avoid hidden costs that would force rate increases at
the end of the three-year plan.(49)

            Staff contends that the proposed electric rate design accords with
Commission policy on hedging electric commodity costs by precluding new hedges
for Central Hudson's larger commercial and industrial customers who experience
real-time commodity prices and by recovering residential customers' hedging
through the commodity rate.(50)

            Staff notes that the Joint Proposal does not provide for a fixed
price option for gas or electric service, but asserts that requiring a
utility-provided fixed price option runs counter to Commission Policy and, thus,
is no reason to

----------
(48)  Ex. 66 at 14-16.

(49)  Ex. 66 at 16-17.

(50)  Ex. 66 at 17-18.


                                      -22-
<PAGE>

CASE 05-E-0934, et al.

withhold approval. Citing to a July 2005 Order,(51) Staff observes its statement
that a then-existing Central Hudson fixed price option for gas service distorts
the market, acts as a barrier against ESCO entry and is an obstacle to
innovation.(52)

            Staff notes that the new gas balancing program rectifies the current
situation under which Central Hudson was the only large local gas delivery
company in New York without daily balancing procedures for its largest
customer.(53) Staff asserts that providing daily and monthly gas balancing for
larger customers and resolving other outstanding gas balancing issues is
consistent with Commission orders.(54)

            Specifically, Staff argues that with the implementation of the
proposed balancing and cashout provisions, obsolete provisions in Central
Hudson's tariff will be eliminated and imbalances will be properly priced, thus
sending the correct price signals and encouraging accurate arrangements for
commodity delivery. Staff also asserts that the proposed changes will enhance
reliability and minimize deviations between proposed use and actual deliveries.
Staff claims that daily and monthly balancing rates have been revised to avoid
cross-subsidizations that might exist under the present system. Finally, Staff
contends that added opportunity to trade imbalances will allow customers to
avoid potential imbalance penalties during times when Central Hudson's overall
system is largely balanced.(55)

            Staff asserts that the Joint Proposal's resolution of the complex
and contentious dispute between Central Hudson and USMA over rates for gas
delivery service to West Point is one of its major benefits. Staff notes that in
addition to arriving at

----------
(51)  Case 05-G-0311, Small Customer Marketer Coalition, Order Directing the
      Future Termination, Subject to Conditions, of a Fixed-Price Offer (issued
      July 22, 2005) (July 2005 Order).

(52)  Ex. 66 at 19.

(53)  Ex. 66 at 20.

(54)  Ex. 66 at 20-21.

(55)  Ex. 66 at 21-22.


                                      -23-
<PAGE>

CASE 05-E-0934, et al.

cost-based rates for service to USMA, expensive and time-consuming litigation in
front of the Armed Services Contract Board of Appeals, and over possible appeals
from its initial decision, is averted.(56)

            Staff observes that the Joint Proposal provides for further rate
unbundling that conforms with Commission policies. Specifically, Staff notes
that existing backout credits are replaced with MFCs that are cost-based and are
set at tiered levels to recognize the cost differentials for supplying commodity
to ESCO customers within and without Central Hudson's Purchase of Receivables
(POR) program. Staff asserts that establishing and coordinating MFCs and POR
program expenses and charges this way complies with the recent policy
developments and would have been difficult to achieve in a litigated
proceeding.(57)

            Staff states the Joint Proposal resolves a highly contentious
dispute regarding the proper calculation of electric and gas depreciation, and
the size of excess electric depreciation reserve. In addition, Staff notes that
the contents and analyses required of a depreciation study to be filed in
subsequent proceedings are established, thus eliminating potential, future
dispute.(58)

            Staff argues that the provision to offset certain deferrals against
Central Hudson's share of any over-earnings is "of particular importance"
because it protects ratepayers by establishing a sharing mechanism that kicks in
if Central Hudson accumulates significant deferrals in its favor and also
over-earns. Staff argues that the recommended earnings sharing also conforms
with numerous other similar rate plan provisions the Commission has adopted and
that its allocation of benefits and risks is appropriate.(59)

----------
(56)  Ex. 66 at 22-23.

(57)  Ex. 66 at 23-24.

(58)  Ex. 66 at 25-26.

(59)  Ex. 66 at 27.


                                      -24-
<PAGE>

CASE 05-E-0934, et al.

            Staff asserts that the allowed 9.6% return is reasonable, noting
that it reflects several relevant updates, and is below that adopted in other
recent rate plans.(60)

            Staff notes that the rates provide funds to build a substation,
expand electric transmission ROW maintenance efforts, and replace gas cast iron
and bare steel pipe. Staff observes that such costs can no longer be offset, as
in the past, by the Benefit Fund, which has been depleted, and are required, in
part, by new Commission guidelines on ROW maintenance. Staff observes that any
shortfalls in these expenditure levels are deferred for ratepayer benefit, thus
encouraging Central Hudson to make the expenditures necessary to preserve
electric system reliability and gas system safety.(61)

            With respect to low-income programs, Staff notes that the Joint
Proposal provides for rapid implementation of an interim program that will
rectify the most serious deficiencies in Central Hudson's existing program and
for an enhanced program that is based on elements which represent the
Commission's most recent thinking on appropriate low-income program policies.
According to Staff, the enhanced program will carefully target assistance to the
customers most able to benefit from that assistance, and tailor the amount of
the assistance to meet the particular needs of a participating household. Staff
notes that program funding will be increased from $1.148 million in Rate Year 1,
to $1.32 million in Rate Year 2, and $1.50 million in Rate Year 3, and that any
unspent amounts will be deferred for low-income program use in subsequent
years.(62)

            Staff notes that the electric reliability mechanism has been the
source of considerable controversy. Staff states that the previous rate order,
in recognition of plans to install a new Outage Management System (OMS), allowed
Central Hudson to request appropriate adjustment of electric reliability indices
if it could show the introduction of OMS affected the

----------
(60)  Ex. 66 at 28.

(61)  Ex. 66 at 29-33.

(62)  Ex. 66 at 34-35.


                                      -25-
<PAGE>

CASE 05-E-0934, et al.

calculation of the reliability indices. Staff also notes that, following
implementation of OMS, Central Hudson had difficulty in meeting the SAIFI and
CAIDI reliability indices, which ultimately resulted in contested reliability
adjustments. Staff states that the Joint Proposal reasonably resolves these
issues by providing that the 2001 Commission rate decision will remain in effect
and by requiring the preservation of the 2002 and 2004 adjustments but excusing
the 2005 adjustment.(63)

            Staff observes that the Joint Proposal provides for several studies
on improving billing and metering that might benefit Central Hudson's customers,
including an AMR Pilot Program. Staff says the pilot will allow Central Hudson
to gain experience with AMR technology and learn more about the cost and
benefits of installing this type of metering, but will not impact bills as the
program would be funded from unused competitive metering funds and excess
electric depreciation reserve.(64)

            Staff asserts that the Joint Proposal's Retail Access provisions
advance the Commission's policies for creating competitive opportunities in
retail energy markets, while giving Central Hudson clear direction on the best
practices for furthering such policies.(65)

      Multiple Intervenors

            Multiple Intervenors state that the proposed rate increases
apparently cannot be avoided in this proceeding. First, they note that Central
Hudson's annual expense related to pensions and OPEBs has increased
substantially over the amounts contained in the current electric and gas rate
plan. Second, Multiple Intervenors note the need for Central Hudson to undertake
certain investments in its electric and gas systems in order to maintain and
improve reliability. Finally, they

----------
(63)  Ex. 66 at 37-40.

(64)  Ex. 66 at 40-41.

(65)  Ex. 66 at 41.


                                      -26-
<PAGE>

CASE 05-E-0934, et al.

observe that a material portion of the rate increases relate to programs
mandated by the Commission.(66)

            One of the primary reasons cited by Multiple Intervenors for their
support of the Joint Proposal is the considerable effort that was made to
moderate the rate increases to the maximum extent practicable. They argue that
the negotiated electric and gas rate moderation is beneficial to customers and
in the public interest.(67)

            Another factor highlighted by Multiple Intervenors is that the Joint
Proposal has been drafted in a manner that should allow it to continue after the
proposed three-year term without requiring immediate, material rate increases.

            Multiple Intervenors also cite to the resolution of electric revenue
and service classifications 3 and 13 rate design issues as a critical component,
stating that the allocations are consistent with the best available cost of
service evidence. They conclude that the provisions should be adopted, along
with the constraints proposed by the settling parties.

            Multiple Intervenors argue that the constraints on the revenue
allocation are appropriate in this instance because the rate increases are
substantial and, if unconstrained, would result in unacceptable customer
impacts. They add that the cost of service evidence does not indicate the need
for major shifts in revenue responsibility.(68)

            Multiple Intervenors support the proposed rate design for service
classifications 3 and 13, stating that it reflects: (i) cost-based monthly
customer charges; (ii) recovery of the residual revenue requirement through per
kW demand charges; and (iii) the elimination of per kWh energy charges. They
argue that, in this circumstance, energy charges are inappropriate because
almost all of Central Hudson's delivery-related costs

----------
(66)  Ex. 63 at 2-3.

(67)  Ex. 63 at 3.

(68)  Ex. 63 at 4.


                                      -27-
<PAGE>

CASE 05-E-0934, et al.

are fixed in nature and should not vary based on energy consumption.(69)

            Multiple Intervenors also note their express support for the
resolution of gas transportation balancing issues. They argue that the
Commission should accord substantial weight to the fact that numerous parties
with diverse interests were able to resolve a number of very complicated gas
balancing issues, including, but not limited to: (i) the appropriate monthly
balancing thresholds and rates for large transportation customers; (ii) the
appropriate daily balancing thresholds and rates for large transportation
customers; (iii) the transition period for the implementation of daily balancing
service; (iv) the rules governing the cash-outs of imbalances; and (v) the rules
regarding how imbalances, and imbalance penalties, are calculated. They assert
that the proposed revenue allocation is reasonable and consistent with the cost
of service evidence.

            Multiple Intervenors urge consideration of the fact that the Joint
Proposal is an integrated agreement and the moderation of the electric and gas
rate increases, electric revenue allocation, service classification 3 and 13
electric rate design, gas balancing provisions affecting large transportation
customers, and gas revenue allocation are critically important and inextricably
linked to their decision to execute and support the proposal.(70)

----------
(69)  Ex. 63 at 5.

(70)  Ex. 63 at 5-6


                                      -28-
<PAGE>

CASE 05-E-0934, et al.

Statements in Opposition(71)

      CPB

            CPB opposes the Joint Proposal, claiming it does not satisfy the
Commission's settlement guidelines and requires improvement to properly benefit
customers. First, CPB recommends that the residential and small commercial
customers be allowed to purchase electric and gas commodity service from the
Company at a fixed price.(72) Though recognizing that the July 2005 Order
directed Central Hudson to terminate its gas fixed price option, CPB argues that
the order is not binding because the basis upon which the Commission acted,
namely that retail competition would be inhibited if utilities offered fixed
price options, is not supported by the current retail market in Central Hudson's
service territory. CPB claims that ESCOs generally have not met consumers'
interest in fixed price offerings, despite the absence of utility-provided fixed
price options.(73) CPB also claims that Commission policy offers the flexibility
to pursue utility-provided fixed price options where, as here, the retail market
has not met customers' needs. CPB contends there is a compelling need to provide
utility fixed price options to consumers so that they have an additional tool to
manage their energy bills.(74)

            CPB expresses concern that the Joint Proposal devotes inadequate
resources to outreach and education on high energy prices. CPB notes that
$350,000 will be spent annually on a Competition Education Campaign, but the
Joint Proposal is silent on the outreach and education to be conducted for
purposes other

----------
(71)  Statements in Opposition were marked as Exhibits 61 (SCMC/RESA), 62
      (Select Energy), and 64 (PULP) and are summarized below. CPB submitted its
      opposition as direct testimony (Tr. 698-775), however, in response to
      Central Hudson's motion to strike (Tr. 792-795), CPB agreed to redact and
      submit portions of its opposition as Exhibit 102 (Tr. 1614-1617).

(72)  Tr. 713.

(73)  Tr. 718-720.

(74)  Tr. 720-721.


                                      -29-
<PAGE>

CASE 05-E-0934, et al.

than retail competition. CPB recommends that customers be provided information
on the cause of high energy prices, actions they can take to manage their energy
bills, and how to obtain bill payment assistance, and that $175,000 of the
amount earmarked for the Competition Education Campaign be redirected
therefor.(75)

            CPB recognizes that the electricity and gas delivery rate increases
are necessary and appropriate, but it asserts that the Joint Proposal overstates
revenue requirements and does not balance the Company's and customers'
interests. CPB recommends modifications to the construction expenditures, ROW
maintenance expenditures, the discount rate used in pension and OPEB expense
projections, the automated meter reading program, outreach and education
expenses, the structure of the Company's pension plan, retail access
expenditures, the treatment of certain customer money set aside for metering
purposes, and the excess depreciation reserve surplus. CPB contends that its
modifications would not affect the Company's earnings but would benefit
customers. CPB also recommends modifications that would affect the Company's
earnings, including reductions to storm expense, MGP remediation expense and the
allowed return on equity.(76)

            With respect to capital expenditures, CPB claims they would increase
by 27.6% in the 18-month period between 2005 and the 2006 rate year and far
exceed any party's recommendations. CPB recommends that capital expenditures be
projected at the average of the expenditures made in the last four years
adjusted for twice the overall inflation level since 2005.(77)

            Concerning ROW maintenance expenses, CPB claims there is substantial
uncertainty regarding the level of such expenditures and ratepayers are not
protected if actual spending is less than projected. CPB also claims that cost
savings or other benefits expected to result from such expenditures are not

----------
(75)  Tr. 721-723.

(76)  Tr. 723-724.

(77)  Tr. 725-730.


                                      -30-
<PAGE>

CASE 05-E-0934, et al.

reflected and it doubts that a 107% increase in annual spending is needed at
this time.

            CPB also notes that, unlike transmission ROW expenditures, there is
no shortfall protection for distribution ROW maintenance expenditures. CPB
asserts that shortfall protection is needed for expenses that account for 78.4%
of total ROW maintenance expenditures. CPB recommends that the ROW maintenance
expenditures be revised downward by $3 million each rate year, to reflect recent
historical spending levels, and that the Company provide ratepayer protection if
actual distribution ROW maintenance expenditures fall short of the rate
allowances. If the Company makes ROW maintenance expenditures beyond the amount
that CPB advocates, it recommends deferral accounting for such amounts, with any
requests to recover such deferrals accompanied by a comprehensive report
explaining the need for the expenditures.(78)

            CPB also takes issue with the projected storm expense. While
recognizing that the projections were derived from a four-year average of
historical expenditures (adjusted for inflation), CPB claims that, given the
substantial increases in ROW maintenance expenditures, all else being equal,
storm expense should continue to decline. It therefore recommends that projected
storm expense be reduced $2 million, to reflect the average of such expenditures
beginning in 2004.(79)

            With respect to MGP remediation costs, CPB asserts that the Company
should be responsible for a portion of the associated program expenses. CPB
states that where, as here, the utility is embarking on a program involving many
projects and significant cost, there is a compelling need to constrain rates and
to encourage cost minimization. CPB therefore recommends that the Company absorb
10% of such costs, and cites to previous PSC orders as support for both cost
sharing and deferral limitations.(80)

----------
(78)  Tr. 730-737.

(79)  Tr. 737-738.

(80)  Tr. 738-742


                                      -31-
<PAGE>

CASE 05-E-0934, et al.

            CPB notes that the proposed rates use a 5.5% discount rate for
pension and OPEB obligations. It asserts that a 5.5% discount rate likely
overstates pension/OPEB expense and therefore should be increased to 5.75% for
this Company. CPB asserts this recommendation is fair to the Company and reduces
the revenue requirement by more than $1 million per year.(81)

            CPB also takes issue with the allowed cost of equity. Specifically,
it disagrees with the removal of the CH Energy Group from the proxy group and
with changing the weighting between the traditional and zero-beta CAPM methods
from 75/25 to 50/50. Finally, CPB disagrees with a 38 basis point stay-out
premium. CPB states that the methods developed in the Generic Finance Proceeding
indicate that the return should be reduced.(82)

            CPB acknowledges that pension and OPEB expense is one of the main
drivers of the rate increases. It notes that Central Hudson continues to offer a
defined benefit pension plan to its management and executive employees, subject
to certain eligibility requirements. CPB asserts that defined benefit pension
plans are more expensive and that many employers have replaced them or have
begun to transition away from them. CPB is concerned that if the Company follows
other large employers and transitions away from a defined benefit pension plan,
it will retain all associated savings. CPB therefore recommends that the Joint
Proposal be modified to provide ratepayers two-thirds of any savings from
transitioning away from the current defined pension plan. CPB asserts that this
approach is fair to the Company because it provides a financial incentive to
pursue cost reductions and also is fair to the ratepayers who would share in the
cost savings.(83)

            CPB notes that funds reserved for metering initiatives will be kept
and preserved for that purpose. CPB instead recommends the amount (approximately
$466,000) be used to mitigate bills. CPB notes that it has been two and one-half

----------
(81)  Tr. 742-744.

(82)  Tr. 744-747.

(83)  Tr. 748-750.


                                      -32-
<PAGE>

CASE 05-E-0934, et al.

years since the Commission originally established the funds, and no reasonable
metering proposal has been advanced in that time. It therefore asserts that the
funds are better used to mitigate increases.(84)

            CPB also opposes the AMR Pilot Program, stating that no party
proposed such a program in their initial testimony. CPB contends that the
magnitude of the proposed delivery rate increases and the high energy costs that
currently exist argue against its implementation at this time. CPB claims that
the program is not needed to provide safe and reliable service. It also claims
that ratepayers would be required to pay its costs but the Company retains any
resulting cost savings. CPB also asserts that this program may be inconsistent
with the Commission's competitive metering agenda. Accordingly, CPB recommends
that the pilot program be eliminated and any associated funds be used to
mitigate the rate increases.(85)

            CPB also takes issue with a provision that would allow the Company
to reverse a ratepayer credit established when the Company failed to meet 2005
electric reliability targets. CPB claims that this result would not occur in a
litigated proceeding and could reduce future incentives for utilities'
compliance with regulatory standards and targets.(86)

            CPB also opposes several retail access provisions, including the
Market Match Program, Market Expo, Energy Fairs, ESCO satisfaction mechanism,
ESCO ombudsman, competition awareness and understanding survey, the Competition
Education Campaign, and the ESCO referral program. It claims that, with the
exception of the Competition Education Campaign, the program costs are not
quantified. With respect to the ESCO Referral Program, CPB asserts that there is
an apparent lack of participation in the program and a failure to meet the
requirement that at least two ESCOs participate. CPB asserts the revenue
requirement impact of these provisions should be

----------
(84)  Tr. 750-755.

(85)  Tr. 756-757.

(86)  Tr. 757-758.


                                      -33-
<PAGE>

CASE 05-E-0934, et al.

stated and the retail access provisions should be reduced by $100,000 each
year.(87)

            With respect to the $350,000 earmarked for the Competition Education
Program, CPB asserts that there is no demonstration that previous retail access
related outreach and education efforts have been cost effective. As a result of
this omission and coupled with the alleged lack of ESCO interest in the ESCO
Referral program, CPB recommends that the ratepayers fund no more than $175,000
annually for retail competition outreach and education programs.(88)

            CPB also recommends that the any funds remaining in the electric
depreciation reserve account be used to further moderate the proposed rate
increases and the amortization of large and unusual losses that Central Hudson
incurred in 2001 and 2002 on its retirement plan assets be extended. CPB asserts
that both these proposals are fair to the company, in that they do not affect
the company's earnings, and to ratepayers, in that they represent a better use
of ratepayer money.(89)

      PULP

            PULP opposes the Joint Proposal for failing to include
utility-sponsored fixed price options and for an alleged improper use of
ratepayer funds to promote private energy service company interests.

            Observing that the July 2005 Order precludes Central Hudson from
continuing to offer a fixed price option, PULP advocates an end to this
prohibition. PULP contends that the fixed price option from the Company is
preferred by residential customers and is highly valuable to low-income
customers. Further, PULP asserts the discontinuance of this option was not
necessary to support Commission policy, and reinstitution will not frustrate
Commission policy. Consequently, PULP urges that

----------
(87)  Tr. 758-762.

(88)  Tr. 762-765.

(89)  Tr. 766-767.


                                      -34-
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CASE 05-E-0934, et al.

the fixed price option be reinstated in time for the 2006-2007 heating season.

            PULP also argues that ratepayer funds should not be used to promote
retail access. According to PULP, it is unnecessary, and, in the context of the
increases proposed here, unjustifiable. PULP states that, if such expenditures
are allowed, they should be funded by energy service companies.(90)

      Select Energy

            Select Energy opposes the balancing, cash-out and delivery proposals
for service classifications 6, 12, and 13. It asserts that the method for
monthly cashouts involves significant estimation and does not guarantee
improvement over the current method. It claims that, because ESCOs are relying
on the accuracy of such calculations, a monthly cashout program based on actual
meter reads is preferable.

            Select Energy further contends that there are inequities between the
proposed cashout index points for under-and over-deliveries in winter months.
Specifically, it argues that the proposed under-delivery cashout "defaults to
the worst case scenario instead of actual costs" and imposes costs on ESCOs that
the Company may not have incurred. Select Energy states that Central Hudson only
includes actual costs in its monthly supply costs and it should be required to
do the same when assessing charges to ESCOs.

            Select Energy asserts that the cashout proposal incorrectly assumes
that customers have a 100% thermal response every month. It claims that the
accuracy of the cashout proposal can be improved by implementing "Monthly
Thermal Response Adjustment Factors" to account for a typical heating customer's
response to heating degree days. It states that the implementation of such an
approach should be delayed until appropriate studies can be performed.

            Select Energy also opposes the incremental delivery requirement.
Select Energy contends it is inequitable and

----------
(90)  Ex. 64 at 2-3.


                                      -35-
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CASE 05-E-0934, et al.

discriminatory because the same requirements do not apply to sales customers and
the incremental deliveries are used to balance Central Hudson's system without
regard to actual usage. It also states that the requirement is unpredictable and
nearly impossible for marketers to recover from customers. At a minimum, Select
Energy argues that Central Hudson should be required to provide a quantitative
analysis of when incremental deliveries required and a justification why
individual marketers are required to makeup system shortfalls (typically during
periods of maximum prices) without any regard for their actual consumption.
Select Energy states that since ESCOs already pay for Storage Space, Storage
Service, and Peaking Service that are used to balance the system on peak days,
ESCOs should not be required to deliver incremental supply.(91)

      SCMC/RESA

            SCMC/RESA take issue with the proposed hedging provision, alleging
that it is at odds with Commission policy, acts to hinder competition and is
inherently illogical.(92)

            SCMC/RESA assert that the impact of existing or legacy hedges is
reflected in the PPA, a rate design component that is charged on an equivalent
basis to full service and retail access customers. SCMC/RESA state that this
practice will be maintained for the legacy hedges, but all new hedges for small
customers entered into after June 30, 2006 would be reflected in the Market
Price Charge mechanism, a commodity charge that will be applied only to utility
commodity sales customers. SCMC/RESA assert that this proposed rate design
change is inequitable, anticompetitive and unreasonable, and should not be
implemented.

            SCMC/RESA urge the Commission to ensure that the reflection of
utility hedging activity in rates is consistent with the utility's regulated
monopoly advantages and is equitable to ESCOs and retail access customers.
SCMC/RESA claim that the proposal to flow hedging costs through the Market Price

----------
(91)  Ex. 62.

(92)  Ex. 61 at 4.


                                      -36-
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CASE 05-E-0934, et al.

Charge ignores the utility's overwhelming competitive advantage, as well as the
fact that retail access customers, through their delivery rates, help sustain
and fund utility hedging procurement activity.

            SCMC/RESA claim that the utilities competitive advantage with
respect to hedging was recognized and discussed by the Commission in connection
with Central Hudson's fixed price option for gas.(93) SCMC/RESA assert that, if
the Commission allows the Company to reflect the cost of hedging practices in
the commodity portion of the rate, it will reinforce the utility's market
dominance and undermine the development of workable competitive playing
field.(94)

            SCMC/RESA further claim that retail customers, through their
delivery rates, support and enable the utility to engage in hedging. SCMC/RESA
conclude that, given this reality, it is unjust and unreasonable to direct that
the impact associated with hedging procurement activities solely to full service
customers by the commodity charge rate mechanism.

            Finally, SCMC/RESA assert that if the Commission adopts the hedging
provision and directs Central Hudson to reflect the impact of hedging activities
only through the commodity charge, it will be difficult to achieve the eventual
withdrawal of utilities from the business of hedging.(95)

Post-Hearing Briefs

      Central Hudson

            Central Hudson asserts that applicable requirements for a proposed
settlement are fully satisfied here and that the opposition warrants no
alteration. Central Hudson compares this proposal with recent rate plans for
Consolidated Edison Company of New York, Inc. (Con Ed) and National Fuel Gas
Corporation (NFG), and finds that the proposed revenue requirements, return on
equity, equity ratio and earnings sharing provisions provide

----------
(93)  Ex. 61 at 5-9.

(94)  Ex. 61 at 10-11.

(95)  Ex. 61 at 11-15.


                                      -37-
<PAGE>

CASE 05-E-0934, et al.

its customers with comparable, if not superior, benefits and protections.(96)

            With respect to the specific modifications suggested by the
opponents, the Company first counters CPB and PULP's proposed fixed price
offering. The Company asserts that CPB and PULP should not be allowed to
collaterally attack the July 2005 Order directing the termination of its fixed
price offering. Given the Commission requirement that proposed settlements
conform to law and policy, the August 25, 2004 directive that "utilities should
not propose fixed rate commodity tariffs" in future rate proceedings, and the
specific directive of the July 2005 order, Central Hudson insists that the Joint
Proposal correctly excluded a fixed price offer.(97)

            The Company further insists that CPB and PULP's assertions about
customer preferences for utility fixed price offers are unsubstantiated and lack
empirical evidence demonstrating market failure. According to the Company, the
Joint Proposal allows the market to function; altering it to require fixed price
offerings by the Company would severely wound the competitive market.(98)

            The Company contests CPB's recommendation to reduce capital
expenditures, stating that CPB has not proposed specific quantitative levels.
The Company also argues that the CPB formula for setting a revised level of
capital expenditures is arbitrary because it is divorced from any assessment of
need. The Company asserts that the proposed expenditure levels were carefully
and thoroughly reviewed by Staff and Company engineers and revised upward to
include additional funds for necessary gas infrastructure enhancements.(99)

            Central Hudson argues against CPB's proposal to true-up distribution
ROW maintenance expenditures. The Company

----------
(96)  Central Hudson Post-Hearing Brief, Revised June 5, 2006 at 2-7.

(97)  Central Hudson Post-Hearing Brief at 7-8.

(98)  Central Hudson Post-Hearing Brief at 7, 10.

(99)  Central Hudson Post-Hearing Brief at 10-12.


                                      -38-
<PAGE>

CASE 05-E-0934, et al.

asserts that the scope of the program has not changed and history shows it
expended more than was allowed in rates. The Company further argues that CPB's
analysis erroneously excluded the enhanced tree trimming costs which undercuts
its premise for a true-up mechanism. Finally, the Company contends that the
reliability penalties already address the possibility that ratepayers could be
short-changed by any underspending.(100)

            The Company considers CPB's adjustment to storm expenditures an
attempt to cast aside the time proven methodology. It says that CPB's testimony
on this issue is varied and internally inconsistent. The Company urges rejection
of CPB's proposal for MGP and SIR costs, stating that it is inconsistent with
applicable policy. It also urges the rejection of CPB's discount rate for
pension and OPEB expenses, noting that the support provided is CPB's initial
brief in a currently ongoing NYSEG case in which the Company (NYSEG) and Staff
agreed to the same 5.5% discount rate proposed here.(101)

            Central Hudson asserts that CPB's proposal to decrease an already
low ROE is unreasonable. It claims that CPB failed to update its own
recommendations, and that, given CPB's concession that Con Ed and Central Hudson
face the same risks, it is promoting discrimination by advocating a lower ROE
for Central Hudson (8.84%) than it previously supported for Con Ed (10.3%). The
Company continues that CPB misapplies the Generic Finance Case principles
related to stay-out premiums.(102)

            Central Hudson claims that in the event of future pension plan
revisions, certain cost differentials would be captured and available for future
disposition by the Commission. It therefore concludes that CPB's proposal
regarding supposed cost savings from a change in the current pension plan is
inconsistent with the Commission Policy Statement and is premature.

----------
(100) Central Hudson Post-Hearing Brief at 14-17.

(101) Central Hudson Post-Hearing Brief at 18-21.

(102) Central Hudson Post-Hearing Brief at 22-25.


                                      -39-
<PAGE>

CASE 05-E-0934, et al.

            Central Hudson claims that CPB's objections to the proposed metering
pilot lack foundation because no funds have been actually committed to it and it
would proceed only if ultimately approved by the Commission. The Company
discounts CPB's opposition to the reversal of the 2005 electric reliability
penalty, stating CPB failed to recognize the provision in context with other
interrelated provisions.(103)

            Central Hudson claims that CPB and PULP's challenges and proposed
modifications to the retail access provisions lack justification and evidentiary
support, and are inconsistent with Commission policy. The Company continues that
the levels of these expenditures are addressed by the proposed deferral
mechanisms.(104)

            Central Hudson asserts that CPB's proposals for additional rate
mitigation ignore the nature of excess reserve and the increased risk of future,
possibly major rate increases that could flow from a decision to deplete the
excess reserve. The Company also claims that CPB's proposal to extend the
amortization of pension losses contradicts applicable policies.(105)

            Central Hudson asserts that SCMC/RESA's understanding of the current
treatment of legacy hedges is inaccurate, noting that while Constellation hedges
are flowed through the PPA, Entergy hedges are flowed through the Market Price
Charge to electric commodity sales customers only. Thus, Central Hudson denies
that the proposal to flow post-June 30, 2006 hedges through the Market Price
Charge to electric commodity sales customers is a rate design change or is
inequitable, anticompetitive or unreasonable. Instead, the Company asserts that
the proposed treatment accords with Commission policy articulated in the Retail
Energy Markets Policy Statement and warrants no alteration.(106)

----------
(103) Central Hudson Post-Hearing Brief at 25-27.

(104) Central Hudson Post-Hearing Brief at 27-30.

(105) Central Hudson Post-Hearing Brief at 30-32.

(106) Central Hudson Post-Hearing Brief at 32-33.


                                      -40-
<PAGE>

CASE 05-E-0934, et al.

            Finally, with respect to the proposed gas balancing provisions,
Central Hudson again argues that no alteration is warranted because the proposed
formula prevents gaming and is similar to provisions included in the NFG rate
plan.(107)

      Staff

            Staff urges rejection of the opponents' positions and adoption of
the proposal without modification.

            Staff claims that CPB's modifications should be rejected because
they would fundamentally alter the proposal's balancing of ratepayers and
shareholders interests, and are premised on misunderstandings and misstatements.
Staff insists that the available choice is between the proposed rate plan and a
litigated one-year rate determination. Staff contends that CPB's approach would
lead to the latter result and asserts that CPB has not demonstrated that its
one-year rate determination is superior to the Joint Proposal.

            Staff asserts that, if CPB's approach prevails, many of the proposed
plan's benefits, including promotion of retail access policies, rate unbundling,
inauguration of gas balancing and cash-out procedures, a new low-income program
that reflects best available practices, spending necessary to ensure safe and
reliable service, and resolution of a complex dispute between Central Hudson and
USMA, would be lost, replaced by a series of litigated one-year rate proceedings
where substantial rate increases would still be needed. Staff argues that since
the proposed plan funds all reasonably expected costs and leaves no hidden
costs, it could continue beyond its term, extending the time ratepayers and the
Company would realize the benefits of stable rates.(108)

            With respect to specific items, Staff asserts that CPB's and PULP's
arguments on a tariffed fixed-price option raise issues that were recently
decided and are beyond the scope of these proceedings. Staff adds that
reinstituting a fixed

----------
(107) Central Hudson Post-Hearing Brief at 32.

(108) Staff Post-hearing Brief, dated May 12, 2006 at 2-6.


                                      -41-
<PAGE>

CASE 05-E-0934, et al.

price offer is short-sighted and would engender long-term harm to consumers,
especially low-income customers.(109) Staff further contends that CPB and PULP
have not undermined the reasons for terminating Central Hudson's fixed price
option. Staff notes that Central Hudson's fixed price option was subsidized by
other customers, rendering its design unjust and unreasonable. Staff also notes
that the fixed price option distorted and retarded the development of the retail
market to customers' disadvantage. Staff claims that CPB and PULP have not
refuted the July 2005 Order's analysis of these points.

            Staff asserts that there is no demonstrated need or established
design parameters for a utility fixed price option. Staff notes that fewer than
2,000 customers (less than 3% of the customer base) subscribed to Central
Hudson's 2002-03 fixed price option, and, even at its peak, it attracted fewer
than 10,000 of Central Hudson's gas customers (less than 15% of its total
eligible customer base). Staff notes CPB's acknowledgment that the fixed price
option price could exceed standard tariff rates. Staff further states that, if
prices have stabilized, reinstituting a fixed price option is an unnecessary
response to a problem that no longer exists. Staff further suggests that, as has
happened in the past, interest in the fixed price option would quickly evaporate
when prices cease rising.(110)

            Staff argues that CPB and PULP's proposed fixed price option is
insufficiently detailed and cannot be successfully implemented. Staff asserts
that CPB's position that the fixed price option cannot be subsidized and cannot
allow for any utility profit ensures that it will be unworkable or unduly
expensive. Staff asserts it is unworkable, in part, because, its proponents
acknowledge that the hedging required to offer the option creates volume and
price risk, but fail to explain how such risk would be treated.(111)

----------
(109) Staff Post-hearing Brief at 2, 7.

(110) Staff Post-hearing Brief at 8-10.

(111) Staff Post-hearing Brief at 10-12.


                                      -42-
<PAGE>

CASE 05-E-0934, et al.

            Staff also contends that the detrimental impacts that could result
in the likely event of a fixed price option price substantially exceeding the
standard tariff price are ignored. Staff also argues that CPB and PULP have not
meaningfully challenged the impact of a utility-provided fixed price option on
competitive markets, even though they were identified and discussed in the July
2005 Order. Staff claims that instead of addressing such impacts, CPB and PULP
make unfounded criticisms that the competitive market has failed to respond
adequately. Staff says their criticisms are belied by the fact that ESCOs
offered fixed price options and nearly 25% of customers availed themselves of
such opportunities. Staff asserts that the competitive marketplace can tailor
offerings that better meet consumers' needs at reasonable prices, but only if
CPB and PULP's proposal is rejected.(112)

            With respect to CPB's opposition to the proposed levels of safety,
reliability and environmental spending, Staff states that CPB erroneously claims
that the proposed capital expenditures exceed the levels proposed by any party.
Staff responds that the capital expenditures are taken directly from the
Company's evidentiary presentation, and are increased by $1.2 million for
additional gas reliability expenditures and adjusted to reflect the increasing
amounts Central Hudson has actually spent in recent years.(113)

            Staff also argues that CPB misses important connections between the
capital budget spending and forecasts of utility activity (e.g., between
one-third and one-half of gas capital expenditures for Rate Years 1 through 3
are dedicated to the facilities needed to extend service to new customers).
Staff, like the Company, asserts that CPB has not connected its proposed
expenditures to levels needed to preserve safe and reliable service. Staff
asserts that as a result of these and other errors, CPB's proposal is
unreasonable.

----------
(112) Staff Post-hearing Brief at 12-15.

(113) Staff Post-hearing Brief at 16-17.


                                      -43-
<PAGE>

CASE 05-E-0934, et al.

            Staff asserts that similar errors afflict CPB's ROW and storm cost
analyses. Staff claims that CPB excludes distribution ROW expense expenditures
that were funded through the Benefit Fund and disregards the most recent data on
storm costs.

            Staff claims that CPB's arguments regarding the treatment of MGP
remediation expense are incorrect, noting that, contrary to CPB's assertions,
the existing approach to MGP expense and the related requirements of prior
orders would continue. Staff also argues that CPB, in its effort to shift some
MGP expense to Central Hudson, overlooks binding orders and instead points to
outmoded precedents that do not favor a clean environment.

            Staff argues that CPB's deferral proposals are factually inaccurate
and reflect a misunderstanding of the Joint Proposal's capital budget and ROW
expense deferral-based incentive mechanisms. Staff explains that under the
proposed rate plan, if Central Hudson fails to achieve a targeted level of
capital expenditure or transmission ROW expense, the difference is deferred for
ratepayer benefit. Staff contends that, since these expenditures are needed to
preserve safe and adequate service and since electric reliability at Central
Hudson has fallen below acceptable levels in recent years, every effort should
be made to encourage the utility to actually expend those funds. Staff claims
that CPB's proposed substitute, which would allow Central Hudson to defer
capital and ROW expenditures that exceed CPB's targets, might actually
discourage improved reliability because the expenditure levels CPB proposes are
insufficient and Central Hudson might not see an incentive sufficient to warrant
the expenditure of funds that exceed the inadequate allowances.(114)

            Staff asserts that it has fully justified moving from its initial
8.65% ROE position to the proposed 9.6% ROE. Staff explains that Central
Hudson's parent, CH Energy Group, Inc., was removed from the proxy group of
companies considered

----------
(114) Staff Post-hearing Brief at 17-20.


                                      -44-
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CASE 05-E-0934, et al.

comparable to Central Hudson because it yielded uncharacteristically low returns
in comparison to the other utility companies in the proxy group. Staff states
that the 8 basis point adjustment revised the weighting of the zero beta CAPM
calculation in the overall ROE determination from 25%/75% to 50%/50%, which it
notes is within the range of previously-accepted weightings.

            Staff argues that its stay-out premium is reasonable and that CPB's
arguments to the contrary rely upon a misunderstanding of the Generic Finance
Case methodology, which is not binding in any event. Staff asserts that the
difference in the yield between one-year and three-year U.S. Treasury Securities
is sufficient to support its risk adjustment for a three-year plan. Moreover,
Staff argues that this three-year plan is eligible for a stay-out premium
because its prices are set and not updated, and the Generic Finance Case
methodology provides an approach to calculating the stay-out premium that yields
38 basis points.(115)

            Staff urges rejection of CPB's arguments concerning pension and
OPEBs. Staff asserts that updating the discount rate now would be superfluous
since the rate will be updated when a new actuarial report is filed in January
2007. Staff adds that an earlier update would be immaterial in the context of
the overall expense.(116)

            As to the length of the deferral period, Staff claims that extending
it conflicts with the Pension and OPEB Statement and Order,(117) and might also
result in inter-generational inequities.

            In response to CPB and PULP's claims that retail access expenditures
are excessive, Staff insists such spending has been constrained to the levels
that are necessary to

----------
(115) Staff Post-hearing Brief at 22-24.

(116) Staff Post-hearing Brief at 25.

(117) Case 91-M-0890, Accounting and Ratemaking Treatment for Pensions and
      Post-Retirement Benefits Other Than Pensions (OPEB), Order and Statement
      of Policy Concerning Pension and Other Post-Employment Benefits (issued
      September 7, 1993).


                                      -45-
<PAGE>

CASE 05-E-0934, et al.

implement Commission policies. Responding to CPB's claim that the expenditures
related to the ESCO Referral Program are questionable because the program has
not yet commenced operations, Staff asserts that the program has been
successfully launched, and that initial indications are that it will achieve its
intended objectives. In addition, Staff notes that the Commission has repeatedly
expressed its support for ESCO referral programs and rejected all objections to
their implementation only six months ago.(118)

            Staff asserts that CPB's arguments against the proposed metering
were rejected in the 2004 Rate Plan Order. Staff contends that the proposed
metering initiative is a reasonable use of funds reserved therefor and is in
conformance with the prior rate orders.(119)

            As to CPB's opposition to excusing Central Hudson from making the
2005 reliability adjustment, Staff reiterates that both the 2001 and 2004 Rate
Plan Orders authorize Central Hudson to excuse a failure to satisfy reliability
targets if it could show that its OMS introduction was at the root of its
compliance failures. Staff notes that Central Hudson repeatedly maintained that
installation of the OMS system adversely affected its ability to meet
reliability targets in 2005, 2004 and 2002 and has complied with the prior
orders. Staff contends that the Joint Proposal also complies with the prior
orders because it provides for payment of the 2004 and 2002 rate adjustments,
and excuses only the 2005 adjustment.(120)

            Staff notes that, in order to further mitigate the proposed electric
rate increases, CPB would entirely deplete the remaining $20 million of excess
depreciation reserve. Staff argues that CPB incorrectly presumes $20 million
would reduce the electric rate increases by approximately $6 million each

----------
(118) Case 05-M-0858, State-Wide Energy Services Company Referral Programs,
      Order Adopting ESCO Referral Program Guidelines and Approving an ESCO
      Referral Program Subject to Modifications (issued December 22, 2005).

(119) Staff Post-hearing Brief at 26-28.

(120) Staff Post-hearing Brief at 28-30.


                                      -46-
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CASE 05-E-0934, et al.

rate year. Staff asserts that in order for CPB to achieve the reductions it
apparently intends, about $36 million in rate moderators would be required.
Staff also claims that the associated rate decreases would be of minimal
benefit. Staff concludes that the excess electric depreciation reserve balance
is best retained to offset future deferrals that are difficult to forecast.(121)

            Staff asserts that SCMC/RESA's position that Central Hudson should
recover the hedging costs for its smaller customers' supply through delivery
rates, rather than commodity rates contravenes applicable policy and would
dilute the hedge's value. Staff notes that SCMC/RESA misunderstand the current
treatment of existing hedges. It states that only the Constellation hedge, a
legacy of the divestiture of Central Hudson's generation plant, is recovered
from all ratepayers, while the existing Entergy hedge, entered into after
divestiture and unrelated to it, is recovered only from commodity customers, in
conformance with the 2004 Rate Plan Order.(122)

            With respect to Select Energy's position that use of Central
Hudson's actual gas costs for pricing purposes would be preferable to the use of
an index for pricing under-deliveries during the winter, Staff notes that winter
under-deliveries can threaten system reliability. Staff asserts that use of an
index to determine the pricing for under-deliveries results in setting that
price at the marginal cost of additional gas supply. Staff continues that
marginal cost pricing is the appropriate reference point because if additional
supplies were suddenly needed, the price charged would be at marginal cost
rather than at the utility's average cost.

            Staff states that Select Energy's proposed gas balancing mechanism
response adjustment factors disregard of the difficulties that may attend the
calculation, billing and implementation of such factors. Staff asserts that the
development and consideration of appropriate factors for Central

----------
(121) Staff Post-hearing Brief at 31.

(122) Staff Post-hearing Brief at 31-32.


                                      -47-
<PAGE>

CASE 05-E-0934, et al.

Hudson should wait for a time following successful implementation of the
proposed gas balancing procedures.

            In response to Select Energy's opposition to the incremental
delivery requirement, Staff says that the requirement is essential to preserving
system reliability and the suggested alternative won't work given current
metering.(123)

      Multiple Intervenors

            Asserting that the Joint Proposal represents an integrated whole,
reflecting numerous compromises by parties with diverse and often adverse
interests, Multiple Intervenors reiterates it should be adopted without
modification.

            With respect to the proposed electric revenue allocation and rate
design, Multiple Intervenors asserts that the testimony and exhibits of Dr.
Rosenberg support those provisions. They argue that, based on their witness'
testimony, as well as that proffered on revenue allocation and rate design
issues by Central Hudson and Staff, the provisions addressing those issues are
reasonable and well within the range of likely litigated outcomes. Multiple
Intervenor observe that none of the opponents challenged the electric revenue
allocation and service classification 3 and 13 rate design and concludes that
those provisions should be evaluated as negotiated, uncontested provisions with
ample record support.

      DOD

            DOD reiterates its request for adoption of the Joint Proposal,
asserting that it provides a reasonable resolution of these proceedings. DOD
argues that, in addition to resolving numerous and complex issues in these rate
cases, the Joint Proposal addresses many details regarding the provision of gas
transportation for USMA at West Point and use of the USMA gas distribution
system for service to Central Hudson's customers in Highland Falls, New York.
DOD asserts that the provisions relating to USMA are just and reasonable and
should provide a

----------
(123) Staff Post-hearing Brief at 32-35.


                                      -48-
<PAGE>

CASE 05-E-0934, et al.

constructive and stable basis for the provision of gas to USMA and other
affected customers. DOD notes that there is no opposition concerning these
provisions.(124)

      CPB

            CPB asserts that these proceedings provide an opportunity to address
the impact of near-record high commodity prices and the largest delivery
percentage rate increases to be proposed for any major energy utility in more
than a decade.

            CPB argues that the Joint Proposal as presented does not
satisfactorily address the impact of higher commodity prices, does not provide
for measures that would properly respond to today's circumstances, and does not
adequately reflect consumer interests. It continues that it does not satisfy the
Commission's Settlement Guidelines, nor question whether policies and practices
that may have been common before are appropriate now. CPB states the proposal
contains some positive elements, like the phase-in of rate increases, the
low-income program and the exclusion of the retail access incentive, but
overall, is not in consumers' interest.(125)

            CPB alleges that the Joint Proposal has not earned the support of
normally adverse parties, particularly CPB and PULP. It discounts the support of
Multiple Intervenors, claiming it is due exclusively to the resolution of
electric revenue allocation, electric rate design, and gas balancing and revenue
allocation issues. It also discounts DOD's support, contending it is due only to
the resolution of disputes regarding service to one customer.(126)

            CPB argues that the context for this proposal must be carefully
considered. It urges consideration of policies it says deny customers the
opportunity to purchase commodity from the utility at fixed prices, enable the
utility to retain ratepayer funds for unspecified purposes and unspecified
periods

----------
(124) DOD's letter in lieu of brief, dated May 12, 2006.

(125) CPB Post-hearing Brief, dated May 12, 2006 at 1, 5-6.

(126) CPB Post-hearing Brief at 2-4.


                                      -49-
<PAGE>

CASE 05-E-0934, et al.

of time, require ratepayers to fund projects that are not necessary for safe and
reliable service and permit unreasonably large increases in certain expense
categories that are inappropriate at this time. CPB argues for focusing on the
overall increases in delivery rates, not the impact on total bills.(127)

            CPB denies implications that its position in these proceedings is
contrary to the position it took in a case involving Con Ed, stating that it did
not support that proposal either and, as here, submitted a statement to help
identify and explain the pro-consumer provisions. CPB asserts that its panel
testimony acknowledges that consideration should be given to the fact that
Central Hudson's base delivery rates have not increased in many years, but it
also clearly explains that the benefit of past rate freezes cannot properly be
considered as a benefit of this proposal and that the presence of some
pro-consumer provisions does not mean that overall, the public interest is
satisfied.

            CPB asserts that it has demonstrated consumers need new tools to
help them manage high and volatile energy prices, including a fixed price option
from the utility and reliable information from the utility on the reasons for
high prices, conservation, and the availability of assistance programs, neither
of which, absent any record basis, is provided.(128)

            In response to Company and Staff assertions that (1) the Commission
directed Central Hudson to terminate its fixed price option and (2) this issue
cannot be relitigated in this proceeding, CPB asserts that New York State Public
Service Law and relevant New York State case law indicate that there is no legal
prohibition against considering fixed price proposals in this proceeding.

            As a threshold matter, CPB states that Company and Staff failed to
recognize that the July 2005 Order applies only to gas and that no such order
applies to an electricity fixed

----------
(127) CPB Post-hearing Brief at 4.

(128) CPB Post-hearing Brief at 6.


                                      -50-
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CASE 05-E-0934, et al.

price option offered by Central Hudson. CPB adds that the issue of whether
adequate electric service by Central Hudson requires offering a fixed price
option for electricity has not been litigated before the Commission.(129)

            CPB also points out that applicable rules expressly provide that
"[t]he rates, rules and regulations relating thereto that are in effect when the
proceeding is initiated will not be presumed to be just and reasonable." It
therefore contends that when Central Hudson filed its rate case, all of its
rates, rules and regulations became open to reconsideration. CPB asserts that,
by the Company's logic, the SCMC/RESA Petition should never have been considered
because the issue had already been determined in a previous order. CPB states
that the Commission, as a policy making entity, always has the discretion to
examine and modify rate policies as it sees fit, a fact that its regulations for
rate cases make explicitly clear.(130)

            CPB also argues that attempts to bar its fixed price option
testimony through collateral estoppel must fail because (1) the collateral
estoppel doctrine can only be utilized by a party after establishing that the
issue in the present proceeding is identical to that necessarily decided in a
prior proceeding, and that in the prior proceeding the party against whom
preclusion is sought was accorded a full and fair opportunity to contest the
issue and (2) it usually is not applied unless the administrative decision was
quasi-judicial in character and thus is not applied when an agency acts in a
ratemaking capacity. CPB argues that the July 2005 Order constituted ratemaking
and therefore can not be granted preclusive effect. CPB further asserts that in
administrative proceedings, the proponent, in this case Central Hudson, bears
the burden of identifying the issues as identical, and that burden was not met
here.(131)

----------
(129) CPB Post-hearing Brief at 7.

(130) CPB Post-hearing Brief at 8.

(131) CPB Post-hearing Brief at 7-11.


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CASE 05-E-0934, et al.

            CPB counters Company and Staff assertions that the record does not
support the adoption of its proposal by citing a recent study's finding that
consumers without substantial financial assets decrease spending on items such
as food by 40 cents for each unanticipated dollar increase in their home energy
bill. CPB cites to its panel testimony for evidence that the availability of a
reasonably priced fixed price option would provide a valuable tool to help avoid
this scenario. CPB acknowledges that a utility fixed price option will not
necessarily decrease bills but maintains it is a tool that should be available
to help consumers manage volatile energy bills.

            CPB asserts that it demonstrated that ESCO fixed price options are
not reasonably priced and that ESCO products that are so-identified may in fact
permit the ESCO to increase the price without recourse by the customer. CPB
continues that of the 8,504 customers who subscribed to Central Hudson's gas
fixed price option when it was terminated on October 1, 2005, only 21% had
chosen ESCO service six months later. According to CPB, this record evidence
demonstrates that the vast majority of fixed price customers in Central Hudson's
territory would rather pay the utility's variable price than take service from
an ESCO.(132)

            CPB also claims to have demonstrated that its proposal is consistent
with the Commission's orders on retail competition. It asserts that, since the
competitive market has not responded adequately and Central Hudson can be
distinguished from other utilities, the Commission has new facts and
circumstances to consider in evaluating utility fixed price options. CPB adds
that, contrary to Staff assertions, there is no Commission directive against
utilities offering fixed price products.(133)

----------
(132) CPB Post-hearing Brief at 12-13.

(133) CPB Post-hearing Brief at 13. CPB cites to the NYSEG and RG&E FPO
      offerings and to Case 00-M-0504 (Statement on Policy on Further Steps
      Toward Competition in Retail Energy Markets (issued August 25, 2004), page
      3) to support its assertions.


                                      -52-
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CASE 05-E-0934, et al.

            CPB reiterates that consumers should be provided accurate and timely
information on the cause of high energy prices, actions they can take to manage
their energy bills, and how to obtain assistance in paying their bills. CPB
argues that the fact that CPB and Staff played key roles in delivering such
information to consumers this past winter, demonstrates that such information
can be delivered to consumers without interfering with the Commission's
competitive agenda.(134)

            In response to proponents' claims that using electric reserve
depreciation to further mitigate the proposed rate increases would set the stage
for rate increases after the funds expire, CPB insists there is no better use
for such funds. CPB further claims that the two potential uses for this surplus
that are set forth in the Joint Proposal either should not be conducted at this
time (i.e., the AMR pilot) or are minimal (i.e., covering cost of electric
backout credits).(135)

            CPB states that, in the current environment of high energy prices
and a proposed series of large delivery rate increases, the Commission should
carefully consider the appropriateness of funding any projects - like the AMR
pilot, retail access programs, and the Competition Education Campaign. CPB
claims that its testimony in this regard was not challenged on cross
examination.(136)

            CPB claims the Company's recent capital spending trends belie Staff
and Company claims that spending increases are necessary for safe and reliable
service, particularly since the Company's electric system earnings exceeded the
sharing thresholds in the years 2001-2005.

            CPB states that even though it now understands that the Joint
Proposal reflects a projected increase of $5.571 million (126%) in annual ROW
maintenance spending beyond 2005 levels (about 2% less than the Company's
request in initial testimony), it remains concerned that an increase of this

----------
(134) CPB Post-hearing Brief at 13-14.

(135) CPB Post-hearing Brief at 15-16.

(136) CPB Post-hearing Brief at 16-20.


                                      -53-
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CASE 05-E-0934, et al.

magnitude may not be necessary, may not be spent in a cost effective manner, or
may not be spent at all. It therefore adheres to its ROW recommendations. CPB
contends that its proposed measures are necessitated by the magnitude of the
projected spending (even under its proposal), and by the high degree of
uncertainty concerning the appropriate level of such spending. CPB notes, that
in 2005, the Company chose to spend less on ROW maintenance than it had in any
year since before 2000, even though it had excess earnings and failed to meet
minimum reliability standards in 3 of the last 4 years. It also highlights Staff
testimony that there is no disadvantage to proposed shortfall mechanism.

            With respect to storm expense, CPB adds to its previous arguments
its assertion that the proponents failed to meet their burden to demonstrate
that the reasonableness of the proposed costs.(137)

            In response to the proponents' challenge to its position regarding
the reversal of the 2005 reliability penalty, CPB responds that that it is
unlikely that the Commission would have reversed its order regarding the 2002
and 2004 penalty, but the Joint Proposal guarantees that the Company could avoid
any consequences for its failure to meet applicable 2005 standards.

            CPB reiterates that shareholders should bear some portion of the MGP
costs. It reasons that ratepayers were not responsible for the Company incurring
those costs; the expenses at issue are extremely large; it is important to
constrain rates; and the Company should be provided an incentive to seek
recovery of these expenditures from other responsible parties. CPB also claims
that no party challenged its proposal on cross examination.(138)

            With respect to changing the pension and OPEBs discount rate to
5.75%, CPB claims that, unlike the Company, it used the most recent data
available to calculate its recommended rate. CPB also counters the proponents'
assertion that large

----------
(137) CPB Post-hearing Brief at 24-25.

(138) CPB Post-hearing Brief at 26-27.


                                      -54-
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CASE 05-E-0934, et al.

pension and OPEB expenses are inevitable with its claim that the Joint Proposal
does nothing to prevent such a situation from recurring. CPB claims despite the
trend away from defined benefit plans, if the Company transitions away from
defined benefit pension plans in the next three years as expected, the Joint
Proposal would allow it to retain all associated savings. CPB asserts that its
proposal to capture any such savings is consistent with the outcome in
competitive markets, is fair to the Company and would help reduce the likelihood
that Central Hudson will request another large rate increase based primarily on
the need to fund employee pensions.

            With respect to ROE, CPB clarifies that, with the exclusion of the
adjustments to account for interest rate changes or to reflect 2005 as the
starting point for calculating the stock valuation adjustment, the proposed
adjustments should not be adopted. It maintains that use of Generic Finance
Methodologies results in a cost of equity of approximately 8.95% for Central
Hudson.

            Specifically, CPB claims that removal of CH Energy Group from the
proxy group is atypical, was not made in the Generic Finance case, and both
Central Hudson and Staff included CH Energy Group in their proxy groups in this
proceeding. CPB adds that changing the weighting of the Traditional and
Zero-Beta Capital Asset Pricing Model ("CAPM") from 75/25 to 50/50 is contrary
to the approach taken in the Generic Finance case, which has been used in most
cases approved by the Commission. Finally, CPB asserts that a stayout premium is
inappropriate here because the revenue requirement calculations under the Joint
Proposal are essentially equivalent to three one-year rate cases, which would
not get a premium under the Generic Finance Case methodology. CPB asserts that
the record establishes that removing the results of Consolidated Edison and two
other companies from Central Hudson's DCF estimate in these circumstances, as
the Company did, was completely arbitrary and served no other purpose but to
inflate the Company's estimates.

            Finally, with respect to possible further rate increase mitigation,
CPB reiterates its claims that extending


                                      -55-
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CASE 05-E-0934, et al.

the amortization of large and unusual losses incurred by Central Hudson in 2001
and 2002 on its retirement plan assets for an additional 10 years is within the
Commission's authority and should be considered if additional rate mitigation is
appropriate.(139)

      PULP

            In its post-hearing brief, PULP reaffirms its opposition to the
Joint Proposal, citing the absence of a fixed price option and the proposed
retail access expenditures.

            At the outset, PULP argues that the motion, made by the Company and
supported by Staff, to remove the fixed price option proposal was unjustified
and untimely. PULP asserts that, even if the motion could be justified, it
should have been made when the proposal was first advanced in CPB's November
2005 testimony. PULP adds that even if the "surprise" motion had been timely, it
would have failed because (1) the CPB and PULP proposal is to establish fixed
price options for gas and electric service, while the July 2005 Order and the
underlying petition addressed gas only and (2) the information provided here in
support of the fixed price offer proposal is information which was unavailable
to the Commission at the time of its July 2005 decision.(140)

            PULP argues that this record establishes several reasons why the
decision in to terminate the fixed price option should be evaluated anew. PULP
cites a discovery response provided by Central Hudson which reports that over
8,500 customers were purchasing gas under its fixed price option in October
2005.(141) PULP notes that under the then-applicable Central Hudson tariff,
customers could only receive such service if they affirmatively sought it prior
to the heating season. PULP thus concludes that thousands of customers
demonstrated in

----------
(139) CPB Post-hearing Brief at 27-33.

(140) PULP Post-hearing Brief, dated May 12, 2006 at 3, n. 3.

(141) PULP Post-hearing Brief at 4, citing Ex. 67, Sch. 2.


                                      -56-
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CASE 05-E-0934, et al.

the clearest possible way that they wished to receive gas service from Central
Hudson under a fixed price option.(142)

            PULP argues that unrefuted data shows that after the discontinuance
of the fixed price option, over 6700 of the 8500 customers who had been taking
the Central Hudson fixed price offer continued as Central Hudson customers. PULP
thus concludes that even when their preference is eliminated, these customers
choose not to move to an ESCO supplier. PULP contends that renewal of the offer
of a fixed price option from Central Hudson will provide these customers with
"what they want - a fixed price option from their chosen supplier - Central
Hudson." PULP claims that refusal to provide a fixed price option from Central
Hudson is a market failure.

            PULP further asserts that the continued unavailability of a fixed
price option from Central Hudson is not necessary to implement a Commission
policy. PULP claims that since customer migration after the elimination of the
fixed price option from Central Hudson did not materially increase the number of
customers taking commodity service from ESCOs, its reinstitution will not
materially reduce the number of customers who may switch to ESCOs.

            PULP also argues that, at the time of the July 2005 Order, the
Commission believed that seven or more ESCOs would be making fixed price offers
to residential customers in the Central Hudson service territory, and that, as
of May 2, 2006, actual numbers were far less than the Commission anticipated in
July. PULP asserts that this reason alone should warrant reconsideration of
these issues.(143)

            PULP adds that the record now shows that the fixed price offers that
are available to residential consumers do not actually provide a fixed price. It
asserts that the purpose of a fixed price offer is to shift the risk of
commodity price fluctuation from the customer to the commodity supplier. PULP
claims that the contracts used by the four ESCOs identified as

----------
(142) PULP Post-hearing Brief at 4.

(143) PULP Post-hearing Brief at 5-6.


                                      -57-
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CASE 05-E-0934, et al.

providing a fixed price offer to residential gas customers provide the ESCO with
one or more escapes.(144) PULP claims that there is no indication that the
Commission was aware in July 2005 of these types commitments and, had it known
of them, it could not have concluded that the ESCO's fixed price offers were
comparable to the Central Hudson's. PULP concludes that, with the information
now in this record, reestablishing the Central Hudson fixed price offer as soon
as possible is fully justified.(145)

            PULP, like CPB, refers to an April 2005 research paper concerning
the harmful effects that volatile energy prices can have for low-income
households to argue that record in this case now shows that the absence of a
fixed price offer for residential customers is particularly harmful to Central
Hudson's low income customers.(146) PULP states that the April 2005 paper
analyzes data over a 12 year period from more than 50,000 households and shows
that, for most customers, a sharp rise in energy costs will be met from savings
or by lengthening their credit card or other credit accounts. PULP states that
low income customers, however, cannot respond to sharp rises in energy costs in
this way, so they will meet the energy cost crisis by reducing consumption of
other necessities. PULP argues that for these customers, a fixed price offers
some assurance that volatile energy bills will not become a source of life
threatening instability. PULP contends that since this research had not been
made available last July, it also represents new information that warrants
reconsideration of the availability of utility fixed price options.(147)

----------
(144) PULP Post-hearing Brief at 7. PULP states that the four ESCOs making a
      fixed price gas offer to the Central Hudson residential customers were and
      are Intelligent Energy, Interstate Gas Supply, MXenergy, and Energetix,
      while the one ESCO providing a fixed price electricity offer was and is
      Accent Energy.

(145) PULP Post-hearing Brief at 8-10.

(146) PULP Post-hearing Brief at 11.

(147) PULP Post-hearing Brief at 11-12.


                                      -58-
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CASE 05-E-0934, et al.

            With respect to the Joint Proposal's proposed funding for retail
access programs, PULP observes that support for retail access will increase from
$250,000 per year to $350,000 per year. PULP notes that previous such
expenditures were funded from a Benefit Fund and, as such, did not directly
impact rates. Now that the Benefit Fund has been exhausted, PULP concludes that
these expenditures now will have a direct impact in raising customer rates and
bills. PULP contends that when revenue requirements are rising at double digit
rates and both gas and electric customers will see dramatic price increases, the
continued and increased expenditure of ratepayer funds cannot be justified.(148)

            PULP argues that the Market Match and Market Expo programs, Energy
Fairs, ESCO/Marketer Satisfaction Survey, ESCO ombudsman and Competition
Outreach and Education Program, individually, and as a group, are intended
solely to give ESCOs better access to customers or to ease or facilitate their
participation in the service territory. PULP adds that there is no indication
that any of these programs have a material effect on residential customers'
migration to ESCO service. PULP contends that these programs have been operating
at least since July 2004, but as of November 2005, less than 800 residential
customers had migrated to ESCO service. PULP further contends that, while the
number of migrating customers increased to just over 5200 in March 2006, this
corresponds to the dramatic increase in energy prices over this past winter, and
not to these programs. PULP states that, in the absence of easily obtainable
data showing actual bill impacts of ESCO service as compared to utility service,
it must be assumed that residential customers have not benefited significantly,
or at all, from their decision to take ESCO service. PULP thus concludes that
use of ratepayer funds to promote retail access cannot be justified.(149)

----------
(148) PULP Post-hearing Brief at 12-13.

(149) PULP Post-hearing Brief at 13-15.


                                      -59-
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CASE 05-E-0934, et al.

            PULP claims that, as a new program, the overall effectiveness of the
Energy Switch program cannot be adequately judged. PULP adds, however, that what
can be determined is that its costs are excessive. PULP calculates that, under
this program, a minimum of $1750 is spent per day, to recruit, on average, 5
customers per day for ESCO service (or $350 per switched customer). PULP states
that the savings for these customers is limited in this program to 7% of the
Central Hudson bill for two months, which it calculates would be $18.55 and
$11.06 per month for typical gas and electric non-heating customers,
respectively. PULP concludes that any money spent by Central Hudson in support
of the residential retail access program should be recovered from the ESCOs
participating in that program and that any ratepayer funds supporting the retail
access programs should be removed and corresponding reductions made to revenue
requirement and rates.(150)

      SCMC/RESA

            SCMC/RESA respond to the CPB and PULP's assertions that a
utility-sponsored fixed price option should be reintroduced by claiming it is
unnecessary, unreasonable and inconsistent with established Commission policy.
SCMC/RESA cite to the Commission's Statement of Policy governing the
implementation of competition in retail markets, specifically its requirement
that " ... in future rate proceedings, utilities should not propose fixed rate
commodity tariffs or tariffs creating a profit center for commodity sales."(151)
SCMC/RESA argue that the Commission has repeatedly underscored the position that
ESCOs rather than regulated utilities should be providing fixed price service.

            SCMC/RESA declare that the assertion that a fixed price option is
needed as a "bulwark" against rising energy cost

----------
(150) PULP Post-hearing Brief at 15-16.

(151) SCMC/RESA Post-hearing Memorandum at 4, citing Policy Statement at 40.


                                      -60-
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CASE 05-E-0934, et al.

is simplistic and unrealistic.(152) SCMC/RESA assert that historic data does not
support the view that a fixed price option will better shield customers from the
impact of rising energy prices than variable rates. SCMC/RESA cite as an
example, the existing NYSEG's rate plan, claiming that NYSEG's variable rate has
generally been lower than its fixed price option. SCMC/RESA expressly counter
the CPB and PULP claim that the levels of migration show a preference for a
utility-sponsored fixed price option, stating that the numbers could just as
easy represent a conscious choice by customers to accept pricing variation
instead of the higher costs associated with a fixed price option.

            SCMC/RESA contend that the Joint Proposal contains recommendations
(e.g., a portfolio purchasing strategy, including hedging) that have the
potential to moderate swings in supply costs. SCMC/RESA also note the
availability of budget billing, as authorized by law, which affords customers
the opportunity to pay an equivalent amount each month for energy charges.

            SCMC/RESA argue that criticism of the ESCOs' fixed price offerings
is misguided. SCMC/RESA further assert that ESCOs will respond to market
conditions and customers preferences, and will provide products in accordance
with the demand therefor.(153)

            With respect to retail access funding, SCMC/RESA claim that
proposals to reduce such expenditures are short-sighted and should be rejected.
SCMC/RESA assert that competitive choice should be promoted and aggressively
pursued as a means of helping customers deal with fluid energy markets. They add
that changing customer habits takes time. They contend that the incremental
efforts to date have borne fruit, as evidenced by the migration of 1 million
customers (state-wide) to retail access service.

----------
(152) SCMC/RESA Post-hearing Memorandum at 5-7.

(153) SCMC/RESA Post-hearing Memorandum at 7-9.


                                      -61-
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CASE 05-E-0934, et al.

            With respect to the Staff argument that adopting SCMC/RESA's hedging
proposal would dilute the hedge's value and require more purchases to achieve
the same pricing level, SCMC/RESA say it is unconvincing. SCMC/RESA assert that
maintenance of a certain price range is a function of the actual movement in
market prices and, thus, the number of hedges will depend on the movement in
market prices. SCMC/RESA continue that since Staff cannot predict how prices may
actually move, its argument against the SCMC/RESA proposal is speculative.
SCMC/RESA add that on a total bill basis, their proposal would not impair rate
stability or require the Company to purchase additional hedges to maintain the
same level of overall rate stability. Finally, SCMC/RESA aver that, since ESCO
customers help sustain and fund the Company through their delivery rates, it is
entirely reasonable and equitable to flow the impact of hedging through the
delivery component of rates.(154)

                                   DISCUSSION

            The Joint Proposal in these proceedings is the product of settlement
negotiations that were noticed and executed in accordance with our settlement
guidelines and rules of procedure. We therefore have evaluated it under our
standards for reviewing joint proposals.(155) In general, a joint proposal is
reviewed for determination that it achieves a reasonable balance among the
protection of the ratepayers, fairness to investors, and the long term viability
of the utility; consistency with sound environmental, social and economic
policies; and results that are within the range of the likely results of a fully
litigated proceeding. Moreover, in judging a joint proposal, the Commission
gives weight to the fact that it reflects agreement among normally adversarial
parties.

            We have reviewed the terms of this Joint Proposal in the context of
the parties' pre-filed testimony and exhibits, the public comments we have
received, the parties' statements

(154) SCMC/RESA Post-hearing Memorandum at 9-11.

(155) 16 NYCRR 3.9; Opinion No. 92-2, supra.


                                      -62-
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CASE 05-E-0934, et al.

and post-hearing briefs, and the testimony and exhibits introduced at the
evidentiary hearing held on May 4 and 5, 2006. Based on that review, we find
that the terms of the Joint Proposal, as modified herein, will establish just
and reasonable rates, terms and conditions and that approval, consistent with
the discussion herein, is in the public interest.

            We note that the Joint Proposal is endorsed by Central Hudson,
Staff, Multiple Intervenors and DOD and is opposed by CPB, PULP, SCMC/RESA and
Select Energy. CPB and PULP propose the addition and formulation of
utility-provided fixed price options and they generally oppose the level of rate
increases reflected in the Joint Proposal. Select Energy's and SCMC/RESA's
opposition is limited, seeking, respectively, modification of certain gas
balancing and hedging provisions. As such, we find that the Joint Proposal
reflects a reasonable compromise among ordinarily adversarial parties
representing a range of interests.

            The willingness of disparate parties to endorse the Joint Proposal,
particularly, where, as here, it calls for unavoidable rate increases, is a
strong indicator that the resultant rate plan satisfactorily addresses a variety
of interests. We note, in this regard, that CPB, though opposing the Joint
Proposal as presented, acknowledges both the inevitability of rate increases in
these proceedings and the fact that the proposal, as presented, contains
positive elements. Moreover, we received extensive public criticism of the
Company's initial proposed rate increases and our call for public comments on
the Joint Proposal elicited similar comments. The bulk of the concerns expressed
in the public comments, however, are addressed by the rate and service terms and
conditions we are adopting, including, in particular, the enhanced low-income
program and the phase-in and moderation of the proposed rate increases.

            The overall electric and gas revenue increases of $53,033,000
million and $14,060,000 million, respectively, are well within the range of
litigation outcomes in these proceedings. The revenue requirements were
vigorously


                                      -63-
<PAGE>

CASE 05-E-0934, et al.

contested. Central Hudson initially proposed electric and gas revenue increases
of approximately $72.1 million and $22.2 million, respectively, over a
three-year period. Staff initially proposed a one-year plan with electric and
gas revenue increases of approximately $40.4 million and $8.8 million,
respectively.

            Key elements in dispute included, not only the rate plan's term and
the level of revenue increases, but also the allowed return on equity, future
sales forecasts, depreciation expenses and reserve, rate design issues, the cost
and timing of MGP/SIR expenditures, and the proper service quality targets.
Moreover, significant disputes were not limited to the Company and Staff, but
also included CPB, the Department of Defense and Multiple Intervenors. The
dispute between the Company and the Department of Defense was very contentious
and complex and concerned service to USMA and use of USMA's gas distribution
system for service to Central Hudson's customers in Highland Falls. If left
unresolved, it could have caused prolonged uncertainty and confusion regarding
Central Hudson's rates and rate design.

            In its Statement in Support of the Joint Proposal, Staff presents
its view of the proposed electric and gas revenue increases. Staff has
demonstrated to our satisfaction that the revenue requirement and rate increases
are necessary and largely unavoidable. Staff highlights the fact that a
significant portion of the proposed increases - 55% of the electric rate
increase and 47% of the gas rate increase - are attributable to pension and OPEB
expenses;(156) while another 20% of the electric increase and 8% of the gas
increase are attributable to expenses that are necessary and, in some cases
mandated, to ensure safety and system reliability. The presentations by Central
Hudson, DOD and Multiple Intervenors further support our finding that the rate
levels proposed under the Joint Proposal are reasonable and necessary and
satisfy ratepayer and shareholder interests.

----------
(156) Indeed, another 32% of the gas increase is due to the recovery of
      regulatory assets for gas, in part, attributable to prior pension and OPEB
      deferrals.


                                      -64-
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CASE 05-E-0934, et al.

The Company's endorsement of the Joint Proposal supports our finding that the
revenue requirement is sufficient for Central Hudson to meet its obligations to
the public to operate and maintain a safe and adequate system. As such, we find
that the rate levels strike an appropriate balance between customer and Company
interests.

            A portion of electric depreciation reserve has been used to moderate
the electric increases. Gas increases are mitigated by deferring and amortizing
portions of the gas revenue increases. This addresses, to a degree, concerns
regarding the impact of the rate increases on residential customers,
particularly those on low and fixed incomes, and on schools and small businesses
in the Central Hudson service territory. Those with the least ability to pay
will benefit from the enhancement and expansion of the low-income program
provided by the Joint Proposal. These elements of the proposal are recognized by
opponents and proponents alike as positive elements.

            The Joint Proposal's revenue allocation and rate design
recommendations are consistent with our public policy objectives. Its allocation
of the revenue requirement increase reflects a reasonable distribution of the
increase across service classifications. The rate design reflects an appropriate
balance among competing considerations, including, but not limited to, the
avoidance of rate shocks, and furthering our policy for hedging electric
commodity costs.

            The new gas balancing program will provide daily balancing
procedures for Central Hudson's largest customers and bring the Company's
procedures into conformance with our recent balancing orders. With the
implementation of the balancing and cashout provisions, imbalances will be
properly priced, thus sending correct price signals to customers and enabling
them to accurately arrange for commodity delivery. In addition, reliability
should be enhanced as deviations between customers' proposed use and actual
deliveries are minimized.

            The resolution of the complex and contentious dispute between
Central Hudson and the USMA ensures cost-based rates for


                                      -65-
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CASE 05-E-0934, et al.

service to the USMA and avoids the expense, time and uncertainty associated with
the litigation that otherwise would have gone before the Armed Services Contract
Board of Appeals. These uncontested provisions are clearly in the public
interest.

            The implementation of further rate unbundling will, in conformance
with our Unbundling Policy Statement, replace the existing back-out credits with
cost-based Merchant Function Charges. The Merchant Function Charges are priced
at tiered levels to recognize the costs attributable to supplying commodity to a
customer of an ESCO that participates in Central Hudson's Purchase of
Receivables program and the costs for those ESCO customers who are outside the
ambit of this program.

            The portion of the rate increases related to maintaining system
reliability and enhancing gas safety is necessary to ensure safe and adequate
service. These allowances will be used to build a substation, expand electric
transmission ROW maintenance efforts (in conformance with our orders) and
replace gas cast iron and bare steel pipe. These improvements will enure
directly to the benefit of all customers.

            The expansion and enhancement of Central Hudson's low-income program
addresses concerns regarding the rate increases' impact on low-income customers.
The program carefully targets assistance to the customers who can benefit the
most and tailors assistance to meet the needs of participating households.
Program funding will increase from an initial level of $1.148 million in the
first rate year to $1.5 million in third rate year. These uncontested provisions
are in the public interest.

            The Customer Service Quality Satisfaction and Gas Safety service
metrics are reasonably designed and intended to encourage the Company to
maintain and improve service, safety, and reliability. The Company has
incentives to operate efficiently, while passing efficiency benefits along to
ratepayers, through the earnings sharing provision.

            As noted above, the contested elements of the Joint Proposal include
the overall level of the rate increases, the absence of utility-sponsored fixed
price offerings, and certain


                                      -66-
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CASE 05-E-0934, et al.

gas balancing and hedging provisions. We have carefully considered the merits of
the opposition, as discussed in detail below. Our analysis leads us to reject
most of the parties' proposed modifications.

            CPB recommends that capital expenditures be reduced to the average
of capital expenditures in the last four years adjusted for inflation. CPB also
recommends that the Company file a deferral petition to recover any expenditures
that exceed the amounts it advocates. Staff and the Company assert that the
modification is unnecessary because the Joint Proposal requires the Company to
defer, for ratepayer benefit, 150% of the return requirement equivalent of any
shortfall in expenditures over the three-year rate term. They argue that this
precludes the Company from seeking to improve its earnings by deferring capital
expenditures. They add that the CPB's proposed modification ignores the fact
that the increased funds are dedicated, in part, to constructing facilities
needed to extend service to new customers and to make necessary gas
infrastructure enhancements.

            We recognize the importance of constraining rate increases, but all
such efforts must be balanced against the equally important goal of ensuring
safe and reliable service. Just and reasonable rates include, in this instance,
ensuring that required utility infrastructure improvements are adequately
funded. We therefore reject CPB's proposal. The shortfall mechanism goes a long
way towards alleviating CPB's concerns as it ensures that the rate allowances
approved here will either be spent for the designated purpose or be returned
(150%) to ratepayers.

            CPB recommends that the Joint Proposal be modified to reduce ROW
maintenance amounts by $3 million per rate year, with any expenditures over the
rate allowance recovered, if at all, by deferral petition. CPB also recommends
the addition of shortfall protection with respect to the distribution ROW
maintenance amounts.

            Staff argues that a reduction is unjustified because CPB's
calculation excludes expenditures funded through the


                                      -67-
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CASE 05-E-0934, et al.

Benefit Fund. The Company adds that CPB's calculation excludes tree-trimming
costs. With respect to the deferral mechanism, Staff states that the extension
of deferral incentive mechanisms to encompass this expense can have adverse
consequences on the Company's incentive to control costs and pursue savings.

            In light of CPB's acknowledgement of errors made in calculating its
proposed reduction, the potential negative impacts associated with the reduction
to and imposition of a deferral mechanism for these costs, and the importance of
ensuring that funds for safe and reliable service are provided, the CPB's
proposals to reduce distribution ROW maintenance amounts and implement a
deferral mechanism are rejected.

            With respect to application of a shortfall mechanism to distribution
ROW costs, we do not find Staff's and Central Hudson's arguments persuasive. As
CPB notes, distribution ROW maintenance expenditures account for the vast
majority (about 78%) of total ROW maintenance expenditures. An incentive to
encourage the Company to actually use the amounts as intended makes good sense
and is consistent which the previously stated goal of ensuring a more reliable
system. Further, we note that, when questioned, Staff conceded "there is no
disadvantage" to subjecting the distribution ROW costs to the same true-up
mechanism that applies to transmission ROW costs.(157) If the Company operates
this routine portion of its business properly, the mechanism will not be
triggered as the subject allowance will be fully expended. Under the
circumstances presented here, adoption of the CPB-proposed shortfall mechanism
provides protection for ratepayers and helps ensure reliability, without harming
the Company. Accordingly, we require the rate allowances for distribution ROW
costs to be subject to the same shortfall mechanism that applies to the
transmission ROW costs.

            CPB asserts that storm expense should be reduced by $2 million from
the level reflected in the Joint Proposal. It claims that expected cost savings
and additional revenue will result from a reduction in the number and duration
of outages

----------
(157) Tr. 1601.


                                      -68-
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CASE 05-E-0934, et al.

and these benefits will offset some costs. Staff asserts that CPB's analysis
disregards the most recent data on storm costs. The Company characterizes the
CPB's proposed adjustment as an attempt to cast aside proven methodology and
claims that CPB's testimony actually confirms the expense levels are correct. We
find that the record supports a level of storm expense that is reasonably based
on the four-year average of historical expenditures, adjusted for inflation.
Consequently, we are not adopting the CPB proposal.

            CPB recommends that the Company be required to absorb 10% of MGP/SIR
costs. Staff and the Company counter that the CPB recommendation is based on
outmoded precedent and does not favor a clean environment. We consider the full
recovery of MGP/SIR costs to be a reasonable utility expense. Accordingly, we
reject the proposed modification.

            We note that these proceedings are the first to address and
incorporate the deferred and projected MGP/SIR costs into a rate plan. The Joint
Proposal provides that the carrying charges applicable to MGP/SIR deferrals
should be changed from the unadjusted customer deposit rate, currently 4.75%, to
a return that equals Central Hudson's pre-tax rate return, 10.01%.(158) CPB
opposes this provision. We, however, approve this proposed change based on our
finding that it properly recognizes the long-term nature of the MGP/SIR Program
and the difficulty of including current funding in the proposed rates. We note
the our approval ensures compensation for Central Hudson at its overall cost of
capital for cash expenditures that require financing, without increasing
proposed rates.

            CPB urges us to change the pension and OPEBs discount rate to 5.75%,
which it states is supported by recalculating the rate using the most recent
data available. CPB also recommends that the Joint Proposal be modified to
capture any savings that might result if the Company changes its defined benefit
pension

----------
(158) Central Hudson currently has authorization to defer MGP/SIR related
      expenditures and to accrue carrying charges on the deferred balance at a
      rate equal to the unadjusted customer deposit rate.


                                      -69-
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CASE 05-E-0934, et al.

plan during the three-year rate term. CPB further recommends extending the
deferral period for pension plan losses by an additional ten years. Staff
asserts a discount rate update now would be immaterial and superfluous and we
agree. We also share Staff's concern that extending the length of the deferral
period would conflict with the requirements of the Pension and OPEB Statement
and Order. Finally, we are also persuaded by arguments that there is no reason
or need at this time to attempt to prematurely capture savings that have not
even been estimated. We therefore decline to adopt CPB's proposed modifications
to pensions and OPEBs.

            CPB asserts that Central Hudson's cost of equity should be reduced
from 9.6% to 8.95%. Staff and the Company assert that the proposed 9.6% ROE is
fully justified. Central Hudson further asserts that CPB's efforts to decrease
an already low ROE are unreasonable and misapplies the Generic Finance Case's
guidance. The method employed to set the allowed equity return is within the
range of reasonable results that can be adopted here. In declining to modify the
proposed 9.6% equity return allowance, we recognize that this item is but one
many elements and interrelated provisions, including the associated but
uncontested earnings sharing mechanism and the limitation of certain deferrals.
We decline to upset the reasonable balance that has been established with
respect to these provisions.

            We also find that CPB's recommendations against an AMR pilot or a
metering study are premature. The Joint Proposal clearly provides that the pilot
and the study will be developed by the Company and filed for our approval. They
will only proceed if we approve them. Thus, CPB can pursue its objections to
such plans when they are filed. In addition, CPB's request to use funds
dedicated to the proposed pilot and study to further mitigate rates is likewise
rejected because (1) no rate allowances have yet been committed to either of
these proposals and (2) CPB has not persuaded us that a change to our prior
orders is warranted.

            CPB opposes the reversal of the 2005 reliability penalty. The
Company asserts that CPB's position fails to


                                      -70-
<PAGE>

CASE 05-E-0934, et al.

recognize the provision in context with other, interrelated provisions. Staff
contends that CPB's opposition ignores the fact that prior rate orders
specifically authorize excuse of a failure that is shown to be caused by the OMS
introduction. For the reasons provided by Staff and the Company, we reject CPB's
recommendation. We find that a reasonable compromise was made on this item in
the context of the many other related provisions. Also, given the uncertainty
attending this contested issue, the provision represents a reasonable compromise
and should not be disturbed.

            CPB recommends that funds remaining in the electric depreciation
reserve account be used to further moderate the proposed rate increases. Staff
argues that CPB's presumption as to amount of mitigation that could be funded in
this manner is incorrect. The Company asserts, inter alia, that CPB's proposal
ignores the nature of the assessment of excess reserve. Given the difficulties
associated with forecasting certain types of large, future deferrals and our
policies favoring rate stability, we are not persuaded that the several
disadvantages attending the complete depletion of excess depreciation reserve
outweigh the one and only identified (and purportedly minimal) benefit. We
therefore reject CPB's proposal.

            CPB and PULP oppose the level of expenditures for retail access
programs and seek reassignment of a portion of such amounts to outreach and
education for purposes other than retail competition. Central Hudson claims that
CPB's and PULP's challenges and proposed modifications lack justification and
evidentiary support, and are inconsistent with Commission policy. The Company
adds that any legitimate concern regarding the level of such expenditures is
addressed by the deferral mechanisms. Staff asserts that Central Hudson has only
made expenditures that are in conformance with the 2004 Rate Plan Order or that
are needed to implement the programs called for in the Retail Access Order.
SCMC/RESA claim that proposals to reduce such expenditures are short-sighted and
should not be adopted. We are persuaded by the proponents' and SCMC/RESA's
arguments that the funding for retail access programs is proper


                                      -71-
<PAGE>

CASE 05-E-0934, et al.

and conforms to and furthers our orders and policies favoring of development of
the competitive market.

            The offering of utility-sponsored fixed price options engendered
significant controversy in these proceedings. The first question presented is
whether utility-sponsored fixed price options can be raised and considered in
these proceedings. We are persuaded, mainly by the arguments in CPB's
post-hearing brief, that there is no bar to CPB and PULP presenting their
proposal in these proceedings. However, as the proponents of utility fixed price
options, they must demonstrate sufficient justification for their adoption.(159)

            CPB and PULP claim that consumers have a strong preference for fixed
price energy products from the utility. They state that consumers without
substantial financial assets decrease spending on items, such as food, to cover
unanticipated increases in their home energy bill. They assert that the
availability of reasonably priced fixed price products would help them avoid
such dilemmas. They also argue that ESCOs are not offering fixed price
electricity or gas products at reasonable prices nor have the number of such
providers increased as seemed to be expected in the July 2005 Order.

            CPB and PULP also claim to have demonstrated that reinstitution of
utility-provided fixed price options is consistent with Commission orders on
retail competition because the competitive market has not responded adequately
and because Central Hudson can be distinguished from other utilities that do not
offer fixed price options.

            On the other hand, Central Hudson, Staff and SCMC/RESA argue that
reinstituting utility fixed price offers would do little to remedy the impact of
commodity price increases but would cause long-term harm to low-income
customers, in particular. They argue it would also distort and retard the

----------
(159) In its post-hearing brief (at 8) CPB notes that it "may face a difficult
      burden in overcoming recent precedent set by the Commission's decision in
      the gas FPO case, but it is not precluded from making the effort."


                                      -72-
<PAGE>

CASE 05-E-0934, et al.

development of retail market to the disadvantage of consumers, and not yield
better prices for consumers.

            We agree with Staff that the design that has been suggested for the
proposed utility fixed price options lacks sufficient detail to be implemented
successfully, and we note that there is insufficient time to remedy such
deficiencies and implement utility sponsored fixed price options in time for the
2006-2007 heating season.(160) However, even if these deficiencies could be
remedied, we are not convinced that utility-provided fixed price options should
be required in these proceedings. We note, in particular, the CPB's testimony
that its main intent in proposing the options is to "provide customers a tool
for dealing with price volatility."(161) We further note CPB's recognition of
the fact that "there's no guarantee that fixed price option[s] will be better
for customers than a variable price."(162) Budget or levelized payment plans are
available, as required by law,(163) to all utility customers, and they already
provide a tool by which customers can achieve certainty with respect to their
monthly bills. Moreover, the record shows there is a competitive market in
Central Hudson's territory, which includes provision of fixed-price offers from
competitive suppliers. Our consideration of these factors, and of the concerns
that were raised by Staff, the Company and SCMC/RESA,

----------
(160) CPB acknowledges that, normally, a fixed price offer involves the
      announcement of such an offer and receipt of responses, which in turn
      permit determination of the required volume of hedging instruments and
      fixed price purchases. In addition, CPB indicates that cost issues - both
      as to the price to be set for the option and the method of recovering any
      differences between estimates and actuals, are not addressed by its
      proposal at this time but are implementation issues that should be
      addressed by the Commission. Given that the 2006-2007 heating season
      starts October 1, there would be insufficient time to properly conduct
      these necessary steps. Tr. 914-918.

(161) Tr. 919.

(162) Id.

(163) Public Service Law ss.38.


                                      -73-
<PAGE>

CASE 05-E-0934, et al.

result in our conclusion that the addition of utility-provided fixed price
options need not be required here.

            As discussed in more detail above, Select Energy opposes the Joint
Proposal's provisions on balancing, cash-out and delivery proposals for service
classifications 6, 12, and 13. Its suggested modifications are opposed by
Multiple Intervenors, the Company and Staff. We are persuaded by proponents'
arguments that Select Energy's position should be rejected.

            SCMC/RESA allege that the proposed hedging provision is at odds with
Commission policy, acts to hinder competition and is inherently illogical.
SCMC/RESA argue that until the Commission determines that residential and small
commercial classes have available equivalent hedge products, it must ensure that
the utility hedging activity reflected in rates is consistent with the utility's
regulated monopoly advantages and is equitable to ESCOs and retail access
customers. Staff asserts that SCMC/RESA's position contravenes Commission policy
and would dilute the value of the hedge. Staff states that the proposal as it
currently stands allows customers to accurately compare utility commodity
offerings to ESCO offerings. Parties on both sides of the issue raise policy
matters that merit further and more in-depth consideration. As these issues also
may be of state-wide relevance, they should be further explored and considered
in a new generic proceeding. Depending on the outcome of that generic
proceeding, its results could be incorporated into later years of this
multi-year rate plan, or deferred to the next rate proceeding. We will review
what, if anything, needs to be done for this rate plan at the conclusion of the
generic proceeding, after the views of the parties are solicited. However, the
treatment set forth in the Joint Proposal, which continues the existing Company
practice, will be adopted for now.

            We expressly note that our approval of the rate plan does not affect
our reserved authority to require a change in base rates, should we find that,
because of unforeseen circumstances, Central Hudson's actual return in any
annual


                                      -74-
<PAGE>

CASE 05-E-0934, et al.

period during the rate term is unreasonable or insufficient to support safe and
adequate service at just and reasonable rates.

            In sum, we conclude that the rate plan established here will provide
just and reasonable rates, terms and conditions and that approval, consistent
with the discussion herein, is in the public interest.

The Commission orders:

            1. The rates, terms, conditions, and provisions of the Joint
Proposal dated April 17, 2006 (Restated April 19, 2006), filed in this
proceeding and attached hereto as Attachment 1, are adopted and incorporated
herein to the extent consistent with the discussion in this Order.

            2. Central Hudson Gas & Electric Corporation shall file a written
statement of unconditional acceptance of this Order, as of the date of the
tariff filing required by ordering clause number three below.

            3. Central Hudson Gas & Electric Corporation is directed to file a
supplement, on not less than one day's notice, to be effective on July 31, 2006,
to cancel the tariff leaves and supplements listed in Attachment 2.

            4. Central Hudson Gas & Electric Corporation is directed to file, on
not less than one day's notice, to take effect on August 1, 2006 on a temporary
basis,(164) such tariff amendments(165) as are necessary to effectuate the terms
of this Order. Upon filing these tariff amendments, Central Hudson Gas &
Electric Corporation shall serve copies on all active parties to this
proceeding. Any party wishing to comment on the tariff amendments may do so by
filing an original and five copies of its comments with the Secretary and
serving its comments upon

----------
(164) Given the tariffs' August 1, 2006 effective date, the make whole approved
      in this Order applies to the month of July 2006.

(165) The tariff amendments that are required to effectuate this Order's gas
      balancing requirements should be filed on March 1, 2007 and March 1, 2008,
      to take effect April 1, 2007 and April 1, 2008 respectively.


                                      -75-
<PAGE>

CASE 05-E-0934, et al.

all active parties within ten days of service of the tariff 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.

            5. The requirement of the Public Service Law Section 66(12)(b) that
newspaper publication be completed prior to the effective date of the amendments
is waived; provided, however, that Central Hudson Gas & Electric Corporation
shall file with the Secretary, no later than six weeks following the effective
date of the amendments, proof that a notice to the public of the changes set
forth in the amendments and their effective date has been published once a week
for four consecutive weeks in one or more newspapers having general circulation
in the service territory of the Company.

            6. Upon acceptance by Central Hudson Gas & Electric Corporation of
this Order, the Company shall withdraw its pending petition in Case 04-G-0463
for rehearing concerning gas balancing.

            7. Upon acceptance by Central Hudson Gas & Electric Corporation of
this Order, the Company shall withdraw its pending petition in Case 00-E-1273
for rehearing of the Commission's Order issued September 30, 2005 concerning
electric reliability.

            8. These proceedings are continued.

                                            By the Commission,


            (SIGNED)                        JACLYN A. BRILLING
                                                  Secretary


                                      -76-
<PAGE>

                                  ATTACHMENT 1

<PAGE>

PUBLIC SERVICE COMMISSION
OF THE STATE OF NEW YORK
---------------------------------------
                                       :
Proceeding on Motion of the            :
Commission as to the Rates, Charges,   :
Rules and Regulations of Central       :            Case 05-E-0934
Hudson Gas & Electric Corporation for  :            Case 05-G-0935
Electric and Gas Service.              :
                                       :
---------------------------------------

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

                                 JOINT PROPOSAL

                                 APRIL 17, 2006
                            (Restated April 19, 2006)

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

<PAGE>

                                Table of Contents

I.       PROCEDURAL BACKGROUND ............................................    1

II.      TERM .............................................................    2

III.     ELECTRIC RATES ...................................................    3

   A. Electric Delivery Revenue Requirements ..............................    3

   B. Electric Revenue Allocation .........................................    3

   C. Electric Rate Design ................................................    3

   D. Electric Commodity ..................................................    4

IV.      GAS RATES ........................................................    5

   A. Gas Delivery Revenue Requirements ...................................    5

   B. Gas Cost of Service and Rate Design .................................    6

   C. SC-11 Distribution Large Mains Classification .......................    6

   D. Gas Commodity .......................................................   10

V.       GAS BALANCING ....................................................   10

   A. General .............................................................   10

   B. S.C. 9 and 11 .......................................................   11

   C. S.C. 6, 12 and 13 ...................................................   16

VI.      RATE UNBUNDLING ..................................................   17

   A. Electric Unbundled Rates and Backout Credits ........................   17

   B. Gas Unbundled Rates and Backout Credits .............................   17

   C. Two Tier MFCs .......................................................   17

   D. Full Service Customers ..............................................   18

   E. Retail Access Customers .............................................   18

   F. Calculation of MFCs .................................................   18

   G. Short Run Avoided Costs .............................................   18

   H. Forecasting Participation and Reconciliation of Lost Revenues .......   19

   I. Bill Format .........................................................   22

VII.     CAPITAL EXPENDITURES .............................................   22

   A. Electric Plant ......................................................   22



                                        i
<PAGE>

  B. Gas Plant, Exclusive of Gas Infrastructure Enhancements ..............   22

  C. Common Plant .........................................................   23

VIII.    DEPRECIATION .....................................................   23

  A. Depreciation Expense .................................................   23

  B. New Depreciation Study ...............................................   23

  C. Negative Salvage .....................................................   23

IX.      DEFERRALS ........................................................   25

  A. Authorization ........................................................   25

  B. Right to Petition ....................................................   26

X.       CAPITAL STRUCTURE AND EARNINGS SHARING ...........................   27

  A. Capital Structure ....................................................   27

  B. Earnings Sharing .....................................................   27

  C. Reporting ............................................................   29

XI.      ADDITIONAL RATE PROVISIONS .......................................   29

  A. Accounting for Gas Mains/Services ....................................   29

  B. Balance Sheet Offsets ................................................   29

  C. Benefit Fund Cessation and Continuing Uses ...........................   30

  D. Certain Rate Allowances ..............................................   31

  E. East Fishkill Substation Deferral ....................................   31

  F. Electric Transmission ROW Maintenance ................................   31

  G. Electric Water Heating ...............................................   32

  H. Make Whole ...........................................................   32

  I. MGP Site Investigation and Remediation Costs .........................   32

  J. Pension/OPEBs ........................................................   32

  K. Property Taxes .......................................................   33

  L. Ratemaking Factors ...................................................   33

XII.     LOW INCOME PROGRAM ...............................................   33

  A. New Low Income Program ...............................................   33

  B. Program Funding and Administration ...................................   34

  C. Enhanced Powerful Opportunities ......................................   34

  D. Interim Program ......................................................   37



                                       ii
<PAGE>

XIII.    CUSTOMER SERVICE QUALITY PERFORMANCE MECHANISM ...................   39

  A. Effective Date .......................................................   39

  B. Customer Satisfaction Index ("CSI") ..................................   39

  C. PSC Complaint Rate ...................................................   40

  D. Appointments Kept ....................................................   40

  E. Evaluation of Telephone System Enhancements: .........................   40

  F. Reporting ............................................................   41

XIV.     GAS SAFETY MECHANISM .............................................   42

  A. General ..............................................................   42

  B. Leak Management ......................................................   42

  C. Prevention of Excavation Damages .....................................   42

  D. Emergency Response ...................................................   43

  E. Gas Infrastructure Enhancement .......................................   44

  F. Reporting ............................................................   45

XV.      ELECTRIC RELIABILITY .............................................   45

  A. SAIFI And CAIDI Targets ..............................................   45

  B. Other Electric Reliability Targets ...................................   46

  C. Other Provisions .....................................................   46

XVI.     MONTHLY METER READING/BILLING STUDIES ............................   47

  A. Monthly Billing Study ................................................   47

  B. AMR Pilot ............................................................   47

  C. Reporting ............................................................   48

XVII.    RETAIL ACCESS ....................................................   48

  A. Market Match Program .................................................   48

  B. Market Expo Program ..................................................   49

  C. Energy Fairs .........................................................   50

  D. ESCO & Marketer Satisfaction Mechanism ...............................   51

  E. ESCO Ombudsman .......................................................   51

  F. Competition Awareness and Understanding Survey .......................   51

  G. Competition Education Campaign .......................................   51

  H. ESCO Referral Program ................................................   52


                                       iii
<PAGE>

XVIII.   Further Understandings Between Central Hudson and USMA ...........   52

  A. Best Efforts .........................................................   52

  B. Easement .............................................................   52

  C. Refunds of Taxes .....................................................   53

  D. Cost of Service Study ................................................   53

  E. Reporting ............................................................   53

XIX.     TERMS AND CONDITIONS .............................................   54

  A. Complete Resolution ..................................................   54

  B. Reservation ..........................................................   54

  C. Integrated Document ..................................................   54

  D. Dispute Resolution ...................................................   54

  E. Non-Precedent ........................................................   55

  F. Application for New Rates ............................................   55

  G. Safe and Adequate Service ............................................   55

  H. Continued Effect .....................................................   55

                                   APPENDICES

Appendix A: Electric Income Statements (for twelve month periods Ending June 30,
2007, 2008 and 2009)

Appendix B: Electric Customer Class Rates of Return

Appendix C: Table of Electric Delivery Rates Including MFCs

Appendix D: Gas Income Statements (for twelve month periods Ending June 30,
2007, 2008 and 2009)

Appendix E: Gas Embedded Cost of Service Summary (for twelve month period Ending
June 30, 2007)

Appendix F: Table of Gas Delivery Rates Including MFCs

Appendix G: Deferred Electric and Gas Items for Offset

Appendix H: Capital Structure and Allowed Rate of Return


                                       iv
<PAGE>

Appendix I: Certain Deferred Items Subject to Limitation

Appendix J: Electric, Gas and Common Depreciation

Appendix K: Gas Balancing Methodology Applicable to SC 9 & 11.

Appendix L: Detailed CSI Margin of Error Calculation


                                        v
<PAGE>

PUBLIC SERVICE COMMISSION
OF THE STATE OF NEW YORK
---------------------------------------
                                       :
Proceeding on Motion of the            :
Commission as to the Rates, Charges,   :
Rules and Regulations of Central       :        Case 05-E-0934
Hudson Gas & Electric Corporation for  :        Case 05-G-0935
Electric and Gas Service.              :
                                       :
---------------------------------------

                                 JOINT PROPOSAL
                   (April 17, 2006; Restated April 19, 2006)

I.      PROCEDURAL BACKGROUND

      On July 29, 2005, Central Hudson Gas & Electric Corporation ("Central
Hudson" or the "Company") filed amendments to its tariff schedules, P.S.C. No.
15 - Electricity, and P.S.C. No. 12 - Gas. By Order issued August 24, 2005, the
Commission initiated the above-captioned proceedings and suspended the operation
of the tariff amendments until December 26, 2005. The suspension period was
later extended to June 26, 2006. In addition, Central Hudson proposed a one
month extension by letter to the Secretary and an additional one month extension
on the record of a Pre-Hearing Conference held on March 9, 2006; both extensions
subject to make whole provisions.

      On September 30, 2005, the Presiding Administrative Law Judges ("ALJs")
issued a Ruling establishing the procedural schedule. In accordance with the
procedural schedule, Department of Public Service Staff ("Staff") and Intervenor
direct testimony was filed on November 21, 2005, and rebuttal testimony was duly
filed on December 14, 2005. The supplemental testimony of Company witness Paul
Haering was filed on November 19, 2005, and the Department of Defense (DOD), on
behalf of the United States Military Academy at West Point ("USMA" or "West
Point") filed the initial testimony of Kenneth Kincel on December 19, 2005.
Furthermore, the ALJs' Second Procedural Ruling in these proceedings, issued
November 5, 2005, determined that monthly gas balancing issues would be heard in
these proceedings and the Commission's Order of November 29, 2005 required that
Central Hudson make a filing addressing daily

<PAGE>

gas balancing in these proceedings. Supplemental testimony of Company witness
Glynis Bunt was duly filed on January 4, 2006 in response to those requirements.

      By Ruling issued January 13, 2006, the ALJs cancelled the hearings
scheduled for January 18, 2006, upon consideration of a telephone request by
several parties seeking additional time to negotiate the development of a Joint
Proposal. The procedural schedule was revised by the ALJs in a Ruling issued
January 17, 2006, granting a request for a postponement and extension of the
procedural schedule for the purpose of accommodating the progression of good
faith settlement negotiations. This Ruling established the target date of
February 28, 2006 for the parties to submit a Joint Proposal together with an
Executive Summary.

      Settlement discussions were conducted on January 12, 2006, in response to
a Notice of Impending Negotiations dated January 6, 2006 filed by the Company.
Additional negotiating sessions were conducted upon prior notice to all
participating parties on January 18, 19, 24, and 31, February 3, 7, 14, and 17.
On March 9, a Settlement Judge, Jeffrey Stockholm, was appointed and conducted
mediation of the negotiations commencing on March 10, 2006. Further negotiating
sessions were held on March 10, 17, 23, 27, 28, and 30, and April 4, 6, 11, 14,
and 17, 2006. On April 3, 2006 a revised schedule was established by the ALJs,
calling for the submission of the Joint Proposal on April 17, submission of
statements in support or opposition and any evidentiary presentations by parties
opposing the Joint Proposal on May 1, 2006, commencement of hearings on May 4,
2006 and submission of briefs (limited to thirty pages) on May 12, 2006.

      As a result of the extensive settlement processes, the parties listed at
the end hereof have reached the agreements on the outcome of these proceedings
reflected in this Joint Proposal, and they recommend to the Commission that it
approve this Joint Proposal.

II.      TERM

      This Joint Proposal is for a three-year electric and gas rate plan,
commencing July 1, 2006 and continuing through June 30, 2009 (see also Section
XVIII.H). "Rate Year" ("RY") means a 12-month period starting July 1 and


                                       2
<PAGE>

ending on the following June 30. RY1 is the twelve months ending June 30, 2007;
RY2 is the twelve months ending June 30, 2008 and RY3 is the twelve months
ending June 30, 2009.

III.      ELECTRIC RATES

       A.   Electric Delivery Revenue Requirements.

          1.   The electric delivery revenue requirements shown in Column A, B,
               and C, Line 2 of Appendix A, Schedule 1, are prior to rate
               moderation.

          2.   Electric delivery revenue requirements have been moderated
               through use of a portion of electric depreciation reserve that is
               in excess of the theoretical book reserve, to offset and "shape"
               the revenue requirement increases, so as to produce three
               approximately equal increases in revenue requirement over the
               three rate years. The revenue requirements have been moderated as
               shown Appendix A, Schedule 2.

          3.   The Income Statements for Electric Delivery Service set forth in
               Appendix A show that this Joint Proposal is reasonable.

       B.   Electric Revenue Allocation.

       For all rate years, the electric revenue allocation among service
       classifications (SC) is subject to constraints of a minimum increase of
       0.75x system average, and a maximum increase of 1.25x system average,
       with the exception of SC 9. For SC 9, a constraint of 0.50x system
       average has been applied and a specific allocation of an additional
       $50,000 of annual revenue requirement responsibility to SC 9 has also
       been made. The resulting percentage changes by class for each rate year
       are summarized in Appendix B.

       C.   Electric Rate Design

          1.   Class billing determinants are shown in Appendix C.

          2.   Central Hudson's electric rates had previously been separated
               into delivery and commodity components. As discussed in Section
               VI below,


                                       3
<PAGE>

               the electric delivery rates developed in this Joint Proposal
               reflect further unbundling, through transferring additional
               commodity-related costs to new Merchant Function Charges ("MFCs")
               also discussed in Section VI.

          3.   Beginning on July 1, 2006 (RY1), the rate design for SC 3 and 13
               will be changed to a two-part (customer charge and demand charge)
               rate design, exclusive of MFCs.

          4.   The electric delivery rates (including MFCs) are set forth in
               Appendix C.

       D.   Electric Commodity.

          1.   The existing Energy Cost Adjustment Mechanism ("ECAM") mechanisms
               being used to recover the costs of electric commodity from
               Central Hudson customers will continue, subject to the
               modifications described below.

          2.   The existing hedges (known as Constellation and Entergy) will be
               maintained in the Purchased Power Adjustment ("PPA") and Market
               Price Charge ("MPC") mechanisms, respectively, in accordance with
               current practices.

               a)   Hedges entered into post-June 30, 2006 will be reflected in
                    MPCs for residential and small commercial customer classes.

               b)   There will be no new hedges for SC 3 or 13, which are real
                    time pricing classes.

               c)   Nothing in this Joint Proposal is intended to alter the
                    pre-existing treatment of legacy hedges established in the
                    existing Commission-approved rate plan.

          3.   Three MPC Groups will be implemented on July 1, 2006.

               a)   The separate MPCs are: 1) for SC 1, 2 and 9; 2) for SC 6
                    (residential time-of-use); and 3) for SC 5 and 8.


                                       4
<PAGE>

               b)   MPCs will be based on each group's average load shapes.

               c)   Effective July 1, 2007, the SC 6 MPC shall be differentiated
                    into on-peak and off-peak rates, with the same on-peak rate
                    applied to all SC 6 on-peak rate periods and the same
                    off-peak rate applied to all SC 6 off-peak periods.

               d)   Recovery of NYISO Ancillary Services Charges and NYPA
                    Transmission Access Charges ("NTAC") will be moved from the
                    Miscellaneous Charges Factor of the ECAM into the MPCs and
                    Hourly Pricing Programs as of July 1, 2007.

               e)   As of July 1, 2007, the Company will cease reimbursing
                    Energy Service Company (ESCO) retail commodity suppliers for
                    ancillary service costs and NTAC.

               f)   Commodity-related uncollectibles and working capital costs
                    shall continue to be recovered through commodity charges.
                    There are no net lost revenues associated with the
                    uncollectibles or working capital costs.

IV.       GAS RATES

       A.   Gas Delivery Revenue Requirements.

          1.   The gas delivery revenue requirements, as shown in Columns A, B
               and C, Line 2 of Appendix D reflect rate moderation achieved
               through deferring a portion of the RY1 increase and amortizing
               it, along with revenue requirement increases in RY2 and 3, in an
               amortization commencing in RY2. This approach also permits a zero
               rate increase in RY3. The amortization of the gas net regulatory
               assets is addressed in more detail in Section X.B.2 and .3.

          2.   The Income Statements for Gas Delivery Service set forth in
               Appendix D show that this Joint Proposal is reasonable.


                                       5
<PAGE>

          3.   The Gas Income Statements include an interruptible profit
               imputation of $1.0 million each rate year. Because of the
               imputation, the Company is permitted to retain the first $1.0
               million in revenues in each rate year that it may receive from
               interruptible service and service to electric generators, subject
               to the following.

               a)   If the margin does not reach $1.0 million in any rate year,
                    the Company is authorized to surcharge ratepayers for 100%
                    of the first $0.25 million of the shortfall and 90% of the
                    remaining shortfall.

               b)   If the margin exceeds $1.0 million in any rate year, the
                    Company will credit ratepayers for 100% of the first $0.25
                    million of the excess and 90% of the remaining excess.

          4.   Central Hudson's gas rates had previously been separated into
               delivery and commodity components. As discussed in Section VI
               below, the gas delivery rates developed in this Joint Proposal
               reflect the transfer of additional commodity-related costs to new
               MFCs.

       B.   Gas Cost of Service and Rate Design.

          1.   Gas rates have been developed using the Embedded Cost of Service
               Study summarized as Appendix E.

          2.   Revenue Allocation. Class billing determinants and the resulting
               rates, including MFCs, are shown in Appendix F.

          3.   For residential gas customers, the minimum charge will be
               increased to $14 per month, and the volumetric delivery rates for
               the penultimate block and tail block will be set at a ratio of
               1.6:1, respectively.

       C.   SC-11 Distribution Large Mains Classification

          1.   A new SC-11 subclass, "Distribution Large Mains" ("SC11DLM")"
               will be established as of July 1, 2006.


                                       6
<PAGE>

               a)   The new SC11DLM subclass will be applicable to customers
                    using over 400,000 Mcf/year, taking service from Company
                    facilities below transmission pressures and from mains at
                    least 6" in diameter.

               b)   The rules and regulations of SC-11 apply to SC11DLM.

               c)   The costs allocated to SC11DLM are shown on Appendix E,
                    subject to the following:

                    (1)  The costs of mains below 6-inch in diameter are
                         excluded.

                    (2)  The operating expenses resulting from Central Hudson
                         payments to USMA are included in FERC/PSC Account 860
                         and are allocated to all classes of service other than
                         SC11DLM.

                    (3)  All other cost of service treatments applied to SC-11 D
                         are also applied to DLM.

                    (4)  The system average rate of return is used to develop
                         the revenue requirement for SC11DLM.

               d)   SC11DLM rate design follows SC11 D and is based on Maximum
                    Daily Quantity ("MDQ"). RY1 through RY3 rates for SC11DLM
                    are shown on Appendix F.

               e)   The SC11DLM MDQ that is in effect for a customer may be
                    revised downwards for permanent reductions to the gas load
                    on the customer's premises caused by installations of, or
                    modifications to, gas equipment, including the possible
                    installation of a propane-air facility. The amount of such
                    downward adjustment to the MDQ will be reasonably determined
                    based on engineering studies prepared by the Customer and
                    furnished to the Company and Staff, on the effect of the gas
                    equipment changes.

                    (1)  The downward adjustment to the MDQ shall be effective
                         during the first month for


                                       7
<PAGE>

                         which the changes in gas equipment are placed in
                         service.

                    (2)  Any customer proposing to reduce its MDQ based on a
                         propane-air facility will provide Staff and the Company
                         written notice at least six months in advance of the
                         date on which the proposed changes in gas equipment
                         will be placed in service.

                    (3)  In the event of reductions in MDQ based on customer
                         conservation measures, the Company will be permitted to
                         defer the lost revenues for future recovery, with
                         carrying charges at the pre-tax authorized rate of
                         return.

          2.   Treatment of USMA.

               a)   Central Hudson will install demand meters at Hotel Thayer
                    and at the Village of Highland Falls by November 1, 2006.

               b)   USMA will be provided service after June 30, 2006 in
                    accordance with the provisions of the SC11DLM class, and
                    after execution of a contract within 10 days of a Commission
                    decision on this Joint Proposal between Central Hudson and
                    the Department of the Army on behalf of USMA, incorporating
                    the provisions set forth below and filed with the
                    Commission. The contract (Modification P00050) will be a
                    further modification of the current Contract
                    DAAG60-91-C-0087 as modified through Modification P00049.
                    Modification P00050 will not contain the rates referenced in
                    Modification 49. Modification 50 shall include all FAR
                    clauses that were incorporated into the contract by
                    Modification P00049 (effective September 1, 2005) except for
                    FAR 52.241-8 (which shall be replaced by FAR 52.241-7,
                    Change in Rates or Terms and Conditions of Service for
                    Regulated Services (Feb 1995)) and the FAR clause
                    incorporated at Paragraph 10 of Modification P00049
                    (entitled "Requirement for Certificate of Procurement
                    Integrity (Nov 1990)."


                                       8
<PAGE>

               c)   The contract modification will:

                    (1)  Provide for firm transportation service in accordance
                         with all provisions of SC11DLM.

                    (2)  Incorporate the rules and regulations of SC11DLM,
                         including balancing.

                    (3)  Specify that the Standard SC11DLM tariff rules for
                         adjusting MDQ identified above will apply to USMA and
                         that the current USMA MDQ is 5833 mcf.

               d)   The contract modification will address the use of the USMA
                    system to deliver gas to Central Hudson's customers in the
                    Village of Highland Falls and to the Hotel Thayer as
                    follows.

                    (1)  Central Hudson shall credit to USMA $5.53 per Mcf of
                         MDQ for deliveries to Highland Falls and Hotel Thayer
                         during each month of RY1 through RY3.

                    (2)  The initial MDQ for Hotel Thayer shall be 27 Mcf. The
                         initial MDQ for Highland Falls shall be 904 Mcf.

                    (3)  The MDQ for any given month shall be the highest daily
                         volume delivered during the current month or the
                         preceding 11 billing months.

                    (4)  A loss factor of 2.564% shall be applied to the volume
                         of gas delivered to Highland Falls and Hotel Thayer
                         times the unit cost of the gas commodity to USMA for
                         the corresponding month. USMA will provide Central
                         Hudson with copies of invoices to establish the monthly
                         USMA unit cost of gas commodity.

               e)   The contract shall provide that, for the term of the
                    contract, Central Hudson will, subject to the provisions of
                    leaves 65 and 66 of its gas tariff (PSC No. 12), deliver up
                    to 500 Mcf per hour (relating to capacity, not MDQ) at 90
                    psig or greater at Crow's Nest at


                                       9
<PAGE>

                    no additional charge to USMA and at no premium upon the
                    rates specified in Appendix F. In addition, the contract
                    will further provide that, for the term of the contract,
                    USMA will maintain 30 psig at Thayer Gate provided that the
                    pressure at Crow's Nest is 90 psig or higher, and the flow
                    of gas to the Village of Highland Falls and the Hotel Thayer
                    does not exceed 50 Mcf per hour.

               f)   The contract Term shall be for a fixed term ending June 30,
                    2009.

       D.   Gas Commodity.

          1.   The existing mechanisms and practices under the Gas Supply Charge
               (GSC), Firm Transportation Rate (FTR), Interruptible
               Transportation Rate (ITR) and Interruptible Gas Rate (IGR) that
               are related to recovery of costs incurred in supplying gas
               commodity will continue, subject to the modifications described
               in Sections V and VI below.

          2.   Commodity-related uncollectibles and working capital costs shall
               continue to be recovered through commodity charges. There are no
               net lost revenues associated with the uncollectibles or working
               capital costs.

V.        GAS BALANCING

       A.   General.

          1.   The new gas balancing approach described below will become
               effective as of April 1, 2007 for interruptible and firm
               transportation classes (SC-9 and 11, respectively), and for the
               aggregated transport classes (SC-6, 12, and 13). Applicable
               portions of the procedures described in the Company's July 29,
               20005 "Report on Gas Balancing and Cashout Issues" will be
               followed in implementing balancing.

          2.   Incremental software costs for monthly and daily balancing will
               receive deferral accounting, for later recovery including
               carrying charges at the pre-tax authorized rate of return.


                                       10
<PAGE>

       B.   S.C. 9 and 11.

          1.   A separate volumetric Balancing Service Charge will be
               implemented as follows:

               a)   There will be two separate rates: one for daily balanced
                    customers and one for monthly balanced customers.

               b)   The methodology for calculating monthly and daily balancing
                    service charges is shown in Appendix K.

               c)   The charges will be updated at least annually, to be
                    effective April 1 of each year, using the methodology shown
                    in Appendix K. The updates will be based on each service
                    classification's total consumption and deliveries during the
                    preceding winter period and the Company's then most recently
                    available gas storage and other relevant costs. At least 30
                    days prior to the effective date of an update, the Company
                    will file a statement of Gas Balancing Rates.

               d)   Transition. The charges shown below have been developed
                    using the methodology depicted in Appendix K, based on
                    currently available information. These charges are scheduled
                    to be updated as of April 1, 2007, except for SC 11DLM. The
                    rates set forth below will remain in effect for SC 11DLM
                    customers until March 31, 2008.

                             Monthly           Daily
                             -------           -----
                              $/Mcf           $/Mcf
           SC-9               $0.0791         $0.0112
           SC-11               0.0463          0.0164
           SC11DLM             0.0463          0.0164

               e)   Effective April 1, 2008, the charges for SC 11 and SC 11DLM
                    will be determined separately, based on the specific peak
                    day history for each class.

          2.   Customers will be allowed to designate an ESCO retail supplier to
               be responsible for supply


                                       11
<PAGE>

               nominations and to effectuate the exchange of any imbalances
               hereunder with similarly situated customers.

          3.   Commencing April 1, 2007, Balancing Service Charges will be
               billed to the customer, and imbalance penalties will be billed to
               the customer's ESCO. Customers will be obligated to require their
               ESCOs to enter into an agreement with Central Hudson to pay for
               such penalties. Prior to April 1, 2007, all charges will continue
               to be billed to customers.

          4.   Balancing Service Charge revenues will be credited to the Gas
               Supply Charge.

          5.   Customers served under negotiated contracts will be rolled into
               the provisions applicable to similarly situated tariff customers
               upon the conclusion of contract negotiations or renegotiations.

          6.   The term of the balancing option period will be modified to
               provide customers with a semi-annual election of daily or monthly
               balancing for the periods November 1 - April 30 and May 1 -
               October 31.

               a)   An existing customer will be required to notify the Company
                    of its selected balancing option for an applicable period on
                    or before the date published in the Company's Calendar of
                    Gas Transportation Schedule (column 4 - deadline for
                    interruptible transport enrollment).

               b)   A customer taking service under SC 9 will maintain its
                    balancing option for the full balancing period regardless of
                    whether the customer switches to service under another
                    service classification or to its alternate fuel and
                    subsequently returns to SC 9 service.

               c)   Absent timely receipt by the Company, of notification from
                    the customer electing its


                                       12
<PAGE>

                    balancing option, the customer will placed in monthly
                    balancing by default.

          7.   The following daily balancing provisions in the current tariff
               will be eliminated:

               a)   If on any day a customer's over-delivery or under-delivery
                    is less than 10% of a customer's actual daily usage, the
                    customer may adjust subsequent daily deliveries to the
                    Company by an amount not to exceed 10% of any day's usage to
                    eliminate any over- or under-deliveries by the end of the
                    month.

               b)   If on any day a customer's cumulative over-delivery exceeds
                    125% of the customer's maximum daily quantity (MDQ), the
                    cumulative over-delivered volume in excess of 125% of the
                    MDQ will be purchased by the Company at a rate equal to 90%
                    of the daily Index Price for that day.

               c)   If on any day a customer's cumulative under-delivery exceeds
                    125% of the customer's MDQ, the cumulative under-delivered
                    volume in excess of 125% of the MDQ will be sold to the
                    customer by the Company at a rate equal to 110% of the daily
                    Index Price for that day.

          8.   For daily balanced customers, daily over- or under-deliveries
               will be "cashed-out" according to the existing tiering and
               pricing structure contained in the Company's tariff only when the
               combined over- or under-delivery for the "pool" of SC 9 and SC 11
               daily balanced customers is greater than 10%.

          9.   The month-end cashout provisions for both daily and monthly
               balanced customers will allow customers that have cumulative
               over- or under-deliveries ("imbalances") at the end of the month
               to exchange the imbalance with another SC 9 or SC 11 customer.
               Such exchanges of imbalances will be accomplished upon
               notification to the Company of the exchange by the applicable
               customer, or its designated supplier, prior to the imbalance
               resolution due date, which is five business days after the


                                       13
<PAGE>

               applicable month end. The imbalance resolution due date will be
               added to the Company's Calendar of Gas Transportation Schedule.
               The net effect of all imbalance exchanges must improve a
               customer's relative imbalance position. In no event will the
               Company process exchanges that result in a larger negative
               position for the customer.

          10.  The cash out will be according to the following revised tiering
               and pricing applicable to SC 9 and SC 11 daily balanced
               customers:

                      --------------------------------------------------------
                      November -          Over -               Under-
                        March           Deliveries           Deliveries
                      --------------------------------------------------------
                      0% to 5%         Index               Index
                      --------------------------------------------------------
                      5% to 10%        90% of Index        110% of Index
                      --------------------------------------------------------
                           >10%        80% of Index        120% of Index
                      --------------------------------------------------------

                      --------------------------------------------------------
                      All Other           Over -               Under-
                       Months           Deliveries           Deliveries
                      --------------------------------------------------------
                      0% to 10%        Index               Index
                      --------------------------------------------------------
                           >10%        80% of Index        120% of Index
                      --------------------------------------------------------

               The over-delivery Index Price will be equal to the average of the
               daily averages of the "Midpoint" rates for "Tennessee, zone 0"
               and Tennessee, zone 1" (500 and 800 legs) receipt points as
               published in Platt's gas Daily in the table "Daily Price Survey"
               for the applicable month, plus the Company's weighted average
               cost of transportation and fuel losses.

               The under-delivery Index Price will be equal to the average of
               the "Midpoint" rates of the higher of "Transco, zone 6 N.Y." and
               "Iroquois, zone 2" receipt points as published in Platt's Gas
               Daily in the table "Daily Price Survey" under the Citygates
               heading for the applicable month.

          11.  The month-end cashout provisions applicable to the resolution of
               over- and under-deliveries for SC 9 and SC 11 monthly balanced
               customers will be revised to correspond to the month-end


                                       14
<PAGE>

               cashout provisions applicable to SC 9 and SC 11 daily balanced
               customers:

               a)   Over-deliveries will be purchased according to the tiering
                    and pricing structure applicable to month-end cashouts for
                    daily metered customers. As a result, the SC 11 "banking"
                    provision will be eliminated and Company purchases will be
                    priced at the same rate regardless of service class, and
                    will be based on a published index.

               b)   Under-deliveries will be purchased according to the tiering
                    and pricing structure applicable to month-end cashouts for
                    daily metered customers. As a result, Company sales will be
                    priced at the same rate regardless of service class, and
                    will be based on a published index.

          12.  At such time as Central Hudson issues an Operational Flow Order
               ("OFO") to safeguard the operational integrity of its system:

               a)   Gas delivered to Central Hudson's system, less any LAUF
                    adjustment, for a daily balanced customer will be required
                    to be within two percent (2%) of the customer's daily usage;

               b)   The daily cashout tiering provisions of SC 9 and SC 11 will
                    be revised such that the first tier will apply to daily
                    over- and under-deliveries greater than 2% up to and
                    including 15%.

               c)   These requirements will remain in effect for the duration of
                    the OFO.

          13.  Upon the Commission's adoption of this Joint Proposal, the
               Company will request the Commission's permission to withdraw the
               Company's pending petition in Case 04-G-0463 for rehearing
               concerning gas balancing.


                                       15
<PAGE>

       C.   S.C. 6, 12 and 13.

          1.   Reconciliations and true-ups will be performed semi-annually;
               once for the 5 months ending March 31, and once for the seven
               months ending October 31.

          2.   Effective 4/1/07, ESCO retail suppliers will be allowed to trade
               offsetting monthly imbalances as part of the semi-annual
               reconciliation/true-up.

          3.   During the summer months, CHG&E will use the monthly average of
               the daily average of the "midpoint" rates for the Tennessee zone
               0 and Tennessee zone 1 (500 and 800 legs) receipt points, plus
               the company's weighted average cost of transportation and fuel
               losses, as the cashout price for both under-deliveries and
               over-deliveries.

          4.   The pricing for Winter Bundled Sales Service (WBS) gas would be
               based upon: Inside FERC Gas Market Report - First of Month Index
               for each month between April - October for the following trading
               points; 50% "Dawn Ontario" & 50% "TCPL Alberta, AECO" to produce
               a "blended index" for each month.

               a)   Individual months would be weighted by adding the following
                    monthly values and dividing the total by six:

                    April Blended Index divided by two
                    May Blended Index
                    June Blended Index
                    July Blended Index
                    August Blended Index
                    September Blended Index
                    October Blended Index divided by two


               b)   The above commodity cost would then be adjusted to include
                    storage charges, firm transportation charges, including
                    fuel, from market area storage to the Company's city gates,
                    and carrying charges on the cost of gas in storage.


                                       16
<PAGE>

VI.       RATE UNBUNDLING

       A.   Electric Unbundled Rates and Backout Credits.

          1.   The back out credits and related treatment contained in the
               Commission's October 25, 2001 Rate Plan (Sections IX.D and X.D.1)
               in Cases 00-E-1273 and 00-G-1274, and its June 14, 2004 Rate Plan
               in those proceedings will be maintained through June 30, 2007,
               except that the cost of the electric backout credits will be
               charged against the excess electric depreciation reserve.

          2.   At July 1, 2007, the electric backout credits will be replaced by
               four electric MFC groups, and the lost revenue provisions
               described below.

          3.   The four electric MFC groups are 1) MFC 1 for SC 1 and 6, 2) MFC
               2 for SC 2 , 3) MFC 3 for SC 3 and 13, and 4) MFC 4 for SC 5, 8,
               and 9. The new MFCs include cost-based components to represent
               commodity-related purchasing, credit and collection, call center
               costs, advertising and promotions, and related Administrative and
               General (A&G) expenses and rate base items allocated to each
               group.

       B.   Gas Unbundled Rates and Backout Credits.

          1.   From July 1, 2006 through June 30, 2007, the existing backout
               credits will continue to apply and will continue to be recovered
               through the Gas Supply Charge.

          2.   Gas delivery service MFCs, analogous to those described above for
               electric delivery service, will be implemented on July 1, 2007.
               The two gas MFCs are MFC 1 for SC 1 and MFC 2 for SC 2.

       C.   Two Tier MFCs.

       Each MFC group will be further sub-divided into an MFC(A) and an MFC(B).

          1.   MFC(A) will include the allocated portion of credit and
               collection function costs and 50% of


                                       17
<PAGE>

               procurement-related call center function costs, plus A&G and rate
               base items associated with each of the above.

          2.   MFC(B) will include commodity purchasing function costs,
               allocated portions of advertising & promotions function costs and
               50% of procurement-related call center function costs, plus A&G
               and rate base items associated with each of the above.

       D.   Full Service Customers.

       Customers taking commodity service from the Company will be billed by
       Central Hudson for MFCT, which is equal to the sum of MFC(A) and MFC(B).

       E.   Retail Access Customers.

       Customers that choose to purchase their commodity service from an energy
       services company (ESCO) that is participating in the Company's Purchase
       of Receivables (POR) Program will be billed by Central Hudson for MFC(A)
       only. The discount rate charged ESCOs that participate in Central
       Hudson's POR Program will be the same for all service classifications and
       will consist of an amount reflecting commodity-related uncollectibles
       costs and a time value of money factor of 0.25%. Customers that choose to
       purchase their commodity service from an ESCO that is not participating
       in the Company's POR Program will not be billed a MFC by Central Hudson.

       F.   Calculation of MFCs.

       The electric and gas MFCs calculated under this Joint Proposal are set
       forth in Appendices C and F, respectively. These MFCs will be effective
       as of July 1, 2007 and remain in effect until changed by subsequent order
       of the Commission. Incremental revenue requirement amounts for RY2 and 3
       will be recovered via delivery rate changes.

       G.   Short Run Avoided Costs.

       At such time as total migration for a month exceeds 30% for either
       electric (SC 1 and 6) or gas (SC 1)


                                       18
<PAGE>

       customers, the Company will notify the Commission and the parties and
       convene discussions among the parties to develop short-run avoided cost
       curves. For RY2 and subsequent rate years, actual net lost revenues will
       be offset by the short-run avoided cost calculated from the avoided cost
       curves, if any; provided however, that no retroactive adjustment will be
       made prior to the time at which an average 30% migration level is
       sustained for 6 consecutive months.

       H.   Forecasting Participation and Reconciliation of Lost Revenues.

          1.   The forecast total retail access participation sales level for
               RY2 and RY3 for MFC 3 (S.C. 3 & 13) will be equal to the product
               of 1) the level of total sales eligible to participate in retail
               access during RY2 and RY3, respectively, and 2) the forecast
               retail access participation factor. The forecast retail access
               participation factor is equal to the total SC 3 and 13 retail
               access participation level, in kWh, for the months of December
               2006 or 2007 (for, respectively, RY2 and RY3), divided by the
               level of SC 3 and 13 sales eligible to participate in retail
               access during the months of December 2006 or 2007 (for,
               respectively, RY 2 and RY 3).

          2.   For all other MFC categories, the forecast total retail access
               participation sales level for RY2 and RY3 will be calculated
               separately for each MFC category and will be equal to the product
               of 1) the level of total sales eligible to participate in retail
               access during RY2 and RY3, respectively, and 2) the forecast
               retail access participation factor. The forecast retail access
               participation factor will be separately calculated for each MFC
               category and is equal to the greater of a) the total retail
               access participation level, in kWh or Mcf, for the months of
               December 2006 or 2007 (for, respectively, RY2 and RY3), divided
               by the level of sales eligible to participate in retail access
               during the months of December 2006 or 2007 (for, respectively,
               RY2 and RY3) or b) the total retail access participation level,
               in kWh or Mcf, for the months of December 2006 or 2007


                                       19
<PAGE>

               (for, respectively, RY2 and RY3), divided by the level of sales
               eligible to participate in retail access during the month of
               December 2006 or 2007 (for, respectively, RY2 and RY3), plus
               one-half the change in the retail access participation factor
               experienced during calendar year 2006 or 2007 (for, respectively,
               RY2 and RY3).

          3.   The change in the retail access participation factor equals the
               total retail access participation level, in kWh or Mcf, for the
               months of December 2006 or 2007(for, respectively, RY2 and RY3),
               divided by the level of sales eligible to participate in retail
               access during the months of December 2006 or 2007 (for,
               respectively, RY2 and RY3),minus the total retail access
               participation level, in kWh or Mcf, for the months of December
               2005 or 2006 (for, respectively, RY2 and RY3), divided by the
               level of sales eligible to participate in retail access during
               the months of December 2005 or 2006 (for, respectively, RY2 and
               RY3).

          4.   At least 4 months prior to the beginning of RY2 and RY3, Central
               Hudson will serve on Staff and the parties to these proceedings
               its forecasts and calculations of the net lost revenues
               associated with the MFCs.

          5.   Forecast net electric and gas lost revenues for MFC 1 for RY2 and
               RY3 will be equal to the product of 1) the forecast total retail
               access participation sales level for RY2 or RY3, respectively, as
               calculated above, and 2) MFC(B). Such calculations assume that
               all residential retail access customers are served by an ESCO
               participating in the Company's POR Program and, therefore, are
               charged MFC(A).

          6.   Forecast net lost revenues for the remaining MFC categories for
               RY2 and RY3 will be equal to the product of 1) the forecast total
               retail access participation sales level for RY2 or RY3,
               respectively, as calculated above, and 2) the MFC(T).

          7.   Central Hudson will recover forecast net lost revenues associated
               with customer migration from


                                       20
<PAGE>

               delivery and full service customers during RY2 and RY3. Central
               Hudson will recover 50% of the forecast net lost revenues from
               full service customers, on an MFC category-specific basis, by
               adding a separate component for that cost to MFC(B). Central
               Hudson will recover the remaining 50% of forecast net lost
               revenues from electric delivery customers through a
               class-specific component of the Miscellaneous Charge Factor of
               the ECAM. For gas, Central Hudson will recover the remaining 50%
               of forecast net lost revenues from delivery customers through a
               new class-specific charge applicable to those customer classes
               subject to an MFC.

          8.   The actual net lost revenue for each MFC category for RY2 and
               RY3, respectively, will be equal to: 1) the actual total retail
               access participation sales level of customers taking service from
               ESCOs participating in Central Hudson's POR Program for RY2 or
               RY3, respectively, multiplied by 2) MFC(B), plus 3) the actual
               total retail access participation sales level of customers taking
               service from ESCOs not participating in Central Hudson's POR
               Program for RY2 or RY3, respectively, multiplied by 4) MFC(T).

          9.   At the end of RY2 and RY3, Central Hudson will calculate for each
               MFC category, the difference between the actual net lost revenues
               associated with retail access and the amount of net lost revenue
               recovered from customers.

               a)   If the sum of the cumulative differences across MFC
                    categories is negative (i.e., Central Hudson over-recovered
                    net lost revenues from customers), Central Hudson will defer
                    the over-recovery, subject to carrying charges calculated at
                    the authorized pre-tax rate of return, for future ratepayer
                    benefit.

               b)   If the sum of the cumulative differences across MFC
                    categories is positive (i.e., Central Hudson under-recovered
                    net lost revenues from customers), and the Company has not
                    earned above the 10.6% earnings sharing threshold, Central
                    Hudson will defer the


                                       21
<PAGE>

                    under-recovery, subject to carrying charges calculated at
                    the authorized pre-tax rate of return for future recovery.

               c)   If the Company has exceeded the 10.6% earnings sharing
                    threshold, it will offset against the under-recovered net
                    lost revenues its share of earnings that are in excess of
                    the 10.6% threshold as described in Section IX.B.1. The
                    amount of under-recovered net lost revenues remaining after
                    the offset, if any, will be deferred subject to carrying
                    charges at the utility's authorized pre-tax rate of return
                    for future recovery.

       I.   Bill Format.

       Central Hudson will propose, no later than October 1, 2006 an unbundled
       bill format for approval by the Commission. The schedule for cut-over to
       unbundled rates described above assumes prompt approval of the proposal,
       such that adequate time for programming changes will be available prior
       to July 1, 2007.

VII.      CAPITAL EXPENDITURES

       A.   Electric Plant.

       Central Hudson's electric capital expenditures, excluding the Allowance
       for Funds Used During Construction (AFUDC), will be set at a level of
       $158.078 million, reflecting $51.944 million for RY1, $52.530 million for
       RY2, and $53.604 million for RY3. If actual expenditures, excluding
       AFUDC, fall short of the cumulative total level of $158.078 million by
       the end of RY3, Central Hudson will defer for ratepayer benefit the
       amount of the shortfall multiplied by 1.5 times the average authorized
       pre-tax rate of return. Commencing on July 1, 2009, such deferral will be
       subject to carrying charges calculated at the authorized pre-tax rate of
       return.

       B.   Gas Plant, Exclusive of Gas Infrastructure Enhancements.

       For Gas Plant, exclusive of Gas Infrastructure Enhancements addressed in
       Section XIII.G, Central Hudson's capital expenditures, excluding AFUDC,
       will be set at a presumed level of $27.495 million,


                                       22
<PAGE>

       reflecting $10.397 million for RY1, $9.354 million for RY 2, and $7.744
       million for RY3. If actual expenditures, excluding AFUDC, fall short of
       the cumulative total level of $27.495 million by the end of RY3, Central
       Hudson will defer for ratepayer benefit the amount of the shortfall
       multiplied by 1.5 times average authorized pre-tax rate of return
       Commencing on July 1, 2009, such deferral will be subject to carrying
       charges calculated at the authorized pre-tax rate of return. If actual
       expenditures for Gas Infrastructure Enhancements exceed the $15.75
       million cumulative total established in Section XIII.G, the amount above
       $15.75 million may be applied by Central Hudson to reduce any shortfall
       in this "Gas, Exclusive of Gas Infrastructure Enhancements" target.

       C.   Common Plant.

       For Common Plant, Central Hudson's capital expenditures will be set,
       reflecting AFUDC, at a presumed level of $21.693 million, reflecting
       $7.732 million for RY 1, $7.031 million for RY 2, $6.930 million for RY
       3. If actual expenditures, excluding AFUDC, fall short of the total level
       of $21.693 million by the end of RY 3, Central Hudson will defer for
       ratepayer benefit the amount of the shortfall multiplied by 1.5 times the
       average authorized pre-tax rate of return. Commencing on July 1, 2009,
       such deferral will be subject to carrying charges calculated at the
       authorized pre-tax rate of return.

VIII.     DEPRECIATION

       A.   Depreciation Expense.

       The average service lives, net salvage factors and life tables used in
       calculating the theoretical depreciation reserve and in establishing
       depreciation expense in the revenue requirements are set forth on
       Appendix J. The Company is authorized to use these factors until new
       factors are approved by the Commission. With respect to the period prior
       to June 30, 2006, the depreciation rates used are appropriately
       represented and will not be adjusted.

       B.   New Depreciation Study.

       The Company will file a new depreciation study when it next files a major
       gas, electric or combined rate case.


                                       23
<PAGE>

          1.   If a combination gas and electric filing is made, the
               depreciation study will address gas, electric and common plant
               accounts; if the filing is limited to one line of business, the
               study need only address the plant accounts for that line.

          2.   The new study will include the following:

               a)   Rolling and shrinking band analyses for each account shown
                    in Appendix J that is applicable to the line of business
                    being studied.

               b)   The width of the rolling and shrinking bands analyzed may be
                    as determined by the Company, but in any event the rolling
                    bands will not be greater than 10 years or less than 5
                    years.

               c)   The shrinking band analysis will start with all the data and
                    decrease to one year of data.

               d)   Statistical results regarding Average Service Life each
                    account will include:

               e)   Analyses of either "h-type" or "Iowa-type" curve fitting
                    analyses and

               f)   The related "fit index" will be provided.

               g)   Plots of the observed and smoothed survivor curve for each
                    account along with the fitted "h-type" or "Iowa-type"
                    survivor curve.

               h)   The Depreciation Study will also include a Net Salvage Study
                    for each plant account showing historical Gross Salvage,
                    Cost of Removal and Net Salvage for each year of historical
                    data included in the Net Salvage Study along with rolling
                    band analysis results, with the width of the rolling band
                    being five years.

          3.   The Company retains the right to submit additional analyses, and
               any recommendations, of its choice.


                                       24
<PAGE>

       C.   Negative Salvage.

       The Company currently expenses the cost to remove gas mains and services
       when the cost exceeds 60% negative salvage.

          1.   During RY1 through RY3:

               a)   The 60% negative salvage limitation will not apply.

               b)   The Company will charge all costs associated with the
                    removal of gas mains and services to the appropriate
                    depreciation reserve account, and

               c)   The Company will charge to operating expense ratably over
                    each of RY1 through RY3, $228,000, $233,000 and $238,000,
                    respectively, with the offsetting credit to the same
                    depreciation reserve accounts charged above. This provision
                    expires at the end of RY3.

          2.   After the end of RY3, the Company will expense removal costs in
               excess of 60% negative net salvage absent the Commission's
               authorization to apply a different treatment; provided however,
               that the Company's agreement to apply such accounting after the
               end of RY3 in this Joint Proposal is understood to be without
               prejudice to any request the Company may make to the Commission
               to revise such accounting treatment after the end of RY3.

IX.       DEFERRALS

       A.   Authorization.

       The Company continues to be authorized to defer the following 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


                                       25
<PAGE>

               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 ("OPEB") under
                    Statement of Financial Accounting Standards No. 106;

               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 Commission Technical
                    Release No. 16(?).

               f)   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;

          2.   Changes in federal or state regulations that have an impact of
               more than 1% of net gas or electric income;

          3.   Stray Voltage Program; and

          4.   Others addressed in this Joint Proposal.

          5.   The uses of deferral accounting authorized herein shall continue
               and shall not terminate because of the end of the term of this
               Joint Proposal.

          6.   It is recognized that certain of the deferrals provided for in
               this Joint Proposal, as listed at Appendix I, are subject to the
               Limitation of Deferral provision set forth under the heading
               "Earnings Sharing."

       B.   Right to Petition.

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


                                       26
<PAGE>

X.        CAPITAL STRUCTURE AND EARNINGS SHARING

       A.   Capital Structure.

       Appendix H shows the capital structure and allowed rates of return that
       have been incorporated into Appendices A and D.

       B.   Earnings Sharing.

          1.   In the event that Central Hudson achieves a regulatory rate of
               return on common equity above 10.60% in either the electric or
               gas department, on a July 1 through June 30 twelve-month basis
               commencing July 1, 2006, the earnings above 10.60% and up to
               11.60% in such department(s) will be shared 50/50 respectively,
               between the Company and ratepayers.

          2.   In the event that Central Hudson achieves a regulatory rate of
               return on common equity above 11.60% in either the electric or
               gas department, on a July 1 through June 30 twelve-month basis
               commencing July 1, 2006, the earnings above 11.60% and up to
               14.00% in such department(s) will be shared 35%/65% between the
               Company and ratepayers, respectively.

          3.   Any earnings above 14.00% will be deferred for the benefit of
               customers.

          4.   Carrying charges at the pre-tax authorized rate of return will be
               applied to the ratepayers' portion.

          5.   In the event that Central Hudson achieves a regulatory rate of
               return on common equity above 10.60% in either the electric or
               gas department, on a July 1 through June 30 twelve-month basis
               commencing July 1, 2006, and experiences an under-recovery of
               migration-related net lost revenues in such department, the net
               lost revenues will be offset by the Company's portion of the
               earnings above 10.60%. Central Hudson will defer any remaining
               net lost revenues for future recovery subject to carrying charges
               calculated at the authorized pre-tax rate of return. This
               calculation shall be made prior to


                                       27
<PAGE>

               the Limitation of Certain Deferrals described below.

          6.   Limitation on Certain Deferrals: When calculating the level of
               earned common equity return that may be subject to sharing after
               the calculation of lost revenues described above, the Company
               will make the following adjustment if its earnings exceed a 11.00
               percent return on equity:

               a)   For earnings above 11.00 percent but less than or equal to
                    14.00 percent, the Company will reduce qualifying expenses
                    (debits) deferred for later recovery by netting in the
                    fashion described below, up to 50 percent of the deferral
                    against the shareholders' portion of the earnings above
                    11.00 percent, provided that such reduction in deferrals
                    will not cause the resulting earnings to decrease below an
                    11.00 percent return on equity.

               b)   The debit deferral amount for purposes of this provision
                    will be determined by netting any credit deferrals against
                    the qualifying debit deferrals.

               c)   The qualifying debit deferrals for purposes of this
                    limitation are comprised of stray voltage, Research and
                    Development, reductions to MDQ (as described in Section
                    IV.C.1.e), variable rate interest, asbestos litigation
                    costs, real property tax, gas balancing software, and
                    "general," meaning other deferrals not addressed in this
                    Joint Proposal that individually exceed 1% of net income.

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

               a)   Determinations of the achieved regulatory rate of return on
                    common equity by department, for gas and electric
                    operations, will be made separately for the twelve-month
                    periods ending June 30.


                                       28
<PAGE>

               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 exceeds
                    47%, then a 47% equity ratio will be used for this purpose.

               c)   The financial consequences of any regulatory incentives, and
                    other exclusions consistent with existing practices, will be
                    excluded in determinations of regulatory rate of return on
                    common equity.

       C.   Reporting.

       Within 90 days following the end of a rate year, Central Hudson shall
       provide the Director of the Office of Accounting and Finance with a
       computation of achieved regulatory rate of return on common equity by
       department for the preceding period.

XI.       ADDITIONAL RATE PROVISIONS

       A.   Accounting for Gas Mains/Services.

       As of January 1, 2006, Central Hudson will implement revised accounting
       procedures that identify the type of material (i.e., plastic, steel, cast
       iron, etc.) used in the gas transmission mains, gas distribution mains
       and gas services recorded in Accounts 367, 376 and 380, respectively.

       B.   Balance Sheet Offsets

            1.    Projected electric and gas deferred debits and credits to be
                  offset on June 30, 2006 are shown on Appendix G. The net
                  electric deferred balance as of June 30, 2006 will be offset
                  against the Excess Electric Depreciation Reserve. The actual
                  electric balances at June 30, 2006 will be used to record the
                  offset on July 1, 2006. The estimated net excess electric
                  depreciation reserve remaining after offsets and use for rate
                  moderation is also shown on Appendix G.


                                       29
<PAGE>

          2.   The net gas deferred balance as of June 30, 2006 will be
               recovered over a nominal seven-year period beginning July 1,
               2007, the start of RY2; subject to adjustment to the amortization
               period as may be required in light of variances between the
               forecast and actual June 30, 2006 balances and recognition of gas
               "make whole" revenues. Appendix G, Schedule 2 shows the projected
               net gas balances. The actual gas balances at June 30, 2006 will
               be used to establish the amount to be recovered.

          3.   The gas net debit balance shown on Appendix G, Sheet 2 is
               comprised of a non-interest bearing component and an interest
               bearing component.

               a)   The non-interest bearing component is amortized on a
                    straight-line basis over seven years beginning July 1, 2007,
                    the start of RY2.

               b)   The balance of the interest-bearing component at July 1,
                    2007, is amortized over seven years, on a levelized basis
                    recognizing accrued interest on the unamortized balance at
                    the authorized pre-tax rate of return, beginning July 1,
                    2006.

       C.   Benefit Fund Cessation and Continuing Uses.

          1.   The Benefit Fund ceases as of June 30, 2006, and the funding
               previously established for the programs listed below will be
               preserved.

          2.   The existing approved uses of the Benefit Fund will continue as
               follows:

               a)   Rate base offset: $42.5 Million credit continues per prior
                    Commission Order.

               b)   Economic Development: Central Hudson's Economic
                    Revitalization Discount and Economic Development Program
                    shall continue until revised by the Commission or program
                    funding is exhausted. The remaining balance from the $11
                    million pre-tax set aside in the Commission's Economic
                    Development Order issued October 3, 2002 in Case 00-E-1273,
                    currently estimated at a projected June 30, 2006 pre-tax
                    amount of $4.2 million, will


                                       30
<PAGE>

                    continue to be available to be utilized in accordance with
                    Central Hudson's Economic Revitalization Discount and
                    Economic Development Program until such funding is exhausted
                    or the Program is revised by the Commission. Central Hudson
                    will notify Staff at such time as the Company estimates that
                    the remaining unspent funds will be fully expended within
                    six months.

               c)   Competitive metering: Remaining metering funding balances
                    will be maintained as a stand-alone item reserved for
                    spending on metering purposes.

       D.   Certain Rate Allowances.

       The amounts shown on Appendix I will be used as the rate allowances for
       purposes of revenue matching accounting or other deferral purposes as
       appropriate.

       E.   East Fishkill Substation Deferral.

       The Company will defer the revenue requirement differences between actual
       costs and the rate allowance for the East Fishkill Substation
       incorporated into Appendix A, for future recovery, or return to
       customers, subject to carrying charges calculated at the authorized
       pre-tax rate of return in either event. The rate allowance in RY3 for the
       East Fishkill substation is a placeholder for the actual value, which
       will not be known until a later time. In the event that the actual costs
       exceed the estimated costs, the Company will submit a report within 120
       days of the project's in-service date detailing the reasons for the
       increased costs.

       F.   Electric Transmission ROW Maintenance.

       If actual Electric Transmission ROW Maintenance expenditures during RY1
       through RY3 are less than the total RY1 through RY3 level contained in
       rates of $6.723 million million by the end of RY3, Central Hudson will
       defer for ratepayer benefit the amount of the shortfall. Commencing July
       1, 2009, such deferral


                                       31
<PAGE>

       will be subject to carrying charges calculated at the authorized pre-tax
       rate of return.

       G.   Electric Water Heating.

       Central Hudson will file with the Commission, within 90 days following
       the Commission Order adopting this Joint Proposal, a proposed plan for
       unwinding the Company's electric water heating business and exiting from
       that business.

       H.   Make Whole.

       The Company is authorized to record gas and electric revenues
       attributable to the extension of the suspension period. The electric
       revenues will be offset against the excess depreciation reserve. The gas
       revenues will be added to the amortization calculation.

       I.   MGP Site Investigation and Remediation Costs.

          1.   The rate allowances shown on Line 30 of Appendix A and Line 27 of
               Appendix D are established for MGP Site Remediation Costs.

          2.   The Company is permitted to defer for future recovery the
               differences between actual costs for MGP Site Investigation and
               Remediation Costs and the rate allowances, with carrying charges
               on the deferred balance (net of tax) for both debit and credit
               balances at the pre-tax authorized rate of return, including any
               remaining balance from the Deferred Gas Balances Offset and
               excluding accrued liabilities. Deferrable expenditures shall
               exclude Company labor and overhead charges.

          3.   Annual reporting requirements continue per existing Commission
               orders, including the Order issued October 25, 2002 in Case
               01-G-1821.

       J.   Pension/OPEBs.

          1.   Central Hudson has been subject to the Commission's Case
               91-M-0890, Statement of Policy and Order Concerning the
               Accounting and Ratemaking Treatment for Pensions and Post-


                                       32
<PAGE>

               retirement Benefits other than Pensions (issued September 7,
               1993) ("Pension and OPEB Policy Statement") and remains subject
               to the Pension and OPEB Policy Statement.

          2.   The Company has adopted Staff's position on year end treatment,
               and made appropriate adjustments on its books. Staff has
               withdrawn its other objections to the Company's accounting for
               pensions and OPEBs.

       K.   Property Taxes.

       The Income Statements in Appendices A and D reflect forecasts of property
       taxes as rate allowances. The Company is permitted to defer the
       difference between actual property tax expenses and the forecasts for RY2
       and 3 reflected in the Income Statements for future recovery. The
       differences (positive or negative) will be shared 90/10: Over-collections
       90% customers/10% Company and under-collections 10% Company/90%
       customers. The Company will defer such under-collections and
       over-collections subject to carrying charges calculated at the Company's
       authorized pre-tax rate of return.

       L.   Ratemaking Factors.

          1.   The common cost allocation factor incorporated into Appendices A
               and D is 85% electric, 15% gas.

          2.   The electric loss factor incorporated into Appendix A is 1.0420.

          3.   The factor for lost and unaccounted for gas incorporated into
               Appendix D is 1.0159.

XII.      LOW INCOME PROGRAM

       A.   New Low Income Program.

       Central Hudson will institute a new Low Income Program to replace Central
       Hudson's current low income program ("Powerful Opportunities" or "POP").
       The new program will proceed in two phases. The first phase will be an
       Interim Program that will replace the POP Program and will continue until
       the second phase ("Enhanced Powerful Opportunities" or "EPOP") is
       operational.


                                       33
<PAGE>

       B.   Program Funding and Administration.

          1.   Effective with the commencement of the Interim Program and
               continuing with the EPOP Program, Central Hudson will directly
               administer and manage its low income programs. The costs of
               administration and management, including staffing, will be
               included in program expenses and will be paid for through program
               funding.

          2.   Program funding for RY1 is $1.148 million, for RY2 is $1.32
               million, and for RY3 is $1.50 million and, unless adjusted by
               Commission Order, for the rate years following will be $1.50
               million.

          3.   Differences between the funding level and actual expenditure
               during a rate year will be deferred, with carrying charges
               calculated at the authorized pre-tax rate of return. If such
               differences are due to over-expenditures, the deferral will be
               limited to no more than 15% of the rate year funding level, for
               future recovery by the Company. If such differences are due to
               under-expenditures, the remaining balance will be rolled over for
               use in subsequent rate years for low income program expenditures.

       C.   Enhanced Powerful Opportunities.

       Central Hudson and interested parties will work through a collaborative
       process to finalize the specific program design, and address
       implementation and other program issues for the Enhanced Powerful
       Opportunities Program. Work in this collaborative on some or all aspects
       of the EPOP program design will begin as soon as possible and no later
       than 10 days after the Commission's adoption of this Joint Proposal.
       Working with this collaborative, the Company will complete its
       development of a detailed EPOP program proposal within 45 days of the
       Commission's adoption of this Joint Proposal, which will be submitted for
       Commission approval. Once approved, the EPOP program implementation will
       be completed as soon as possible but no later than September 1, 2007.

          1.   The EPOP program design elements that the parties have agreed
               upon are:


                                       34
<PAGE>

               a)   Eligibility Criteria. The customer must:

                    (1)  Use electricity or natural gas as the primary fuel for
                         space heating.

                    (2)  Be a HEAP recipient with the HEAP payment paid to
                         Central Hudson.

                    (3)  Have arrears of at least $100 remaining after the HEAP
                         payment is applied to the customer's account.

                    (4)  Enroll in the Central Hudson Budget Billing Program.

                    (5)  Provide a Department of Social Services ("DSS") release
                         for Central Hudson to receive income, expense and other
                         family size verification, and such other information
                         that may be necessary for implementation of the
                         Program.

                    (6)  Agree to be referred by Central Hudson to the New York
                         State Energy Research and Development's ("NYSERDA")
                         EmPower NY Program and to complete an application for
                         participation.

                    (7)  Renew HEAP eligibility annually.

               b)   Program Elements.

                    (1)  In administering the EPOP Program, Central Hudson will
                         refer participants to other local assistance programs
                         and to NYSERDA's EmPower New York Program.

                    (2)  The program will be initially designed to serve 800 to
                         1000 customers on an ongoing basis. Central Hudson will
                         manage participation enrollment to the annual funding
                         level available.

                    (3)  Central Hudson will work with DSS to obtain income,
                         expense and family size verification to determine
                         participant eligibility.

                    (4)  Central Hudson will have the discretion to include a
                         customer in the program who does not meet all the
                         eligibility criteria upon evidence that program
                         participation will increase the likelihood that the
                         customer will be able to maintain


                                       35
<PAGE>

                         continuous service without compromising other essential
                         household needs.

                    (5)  Arrears forgiveness incentive. Collection activity on a
                         participating customer's pre-program arrears will be
                         suspended while the customer is in the program. One
                         twenty-fourth (1/24) of a participating customer's
                         arrears balance, up to a maximum of $100 per month,
                         will be forgiven each month the customer pays current
                         charges on time and in full. A customer failing to make
                         a payment of current charges on time and in full will
                         not receive any arrears forgiveness for that month. The
                         customer may continue in the program for future months
                         by paying the late bill and any associated late payment
                         charges, and paying the bills in future months on time
                         and in full. The arrears forgiveness funded from the
                         program will be provided to program participants over a
                         24 to 36 month period, if the participant keeps the
                         account current and makes 24 budget bill payments on or
                         before their payment due dates.

                    (6)  Customers will not be charged a late payment charge on
                         their suspended arrears, but will be charged a late
                         payment charge if they pay their budget payments late.

                    (7)  Customers in the EPOP program will receive an annual
                         bill discount based on their income level and family
                         size. This annual discount amount will be provided over
                         12 months in monthly bills. The parties will develop
                         the discount amounts and criteria during the
                         collaborative process described above.

                    (8)  Participants will exit the program upon completion of
                         the arrears forgiveness provisions of the program or
                         after 24 months, whichever comes later.

                    (9)  The Program may be closed to further enrollment each
                         year based on program costs and participant levels.


                                       36
<PAGE>

               c)   The format and schedule for reports will be agreed upon by
                    the parties in the collaborative process described above. As
                    part of the collaborative program design process, the
                    Company and the parties also will describe the content for
                    these reports and the data they will include. An evaluation
                    plan will be developed by the parties for implementation
                    such that the findings are available for consideration for
                    planning regarding the Company's low income program
                    subsequent to Rate Year 3.

               d)   Central Hudson will agree to convene a meeting with Staff
                    and interested parties within 45 days of the conclusion of
                    each rate year to review program operations, accomplishments
                    and spending. If the parties and the Company agree that
                    program modifications are needed, the Company will petition
                    the Commission seeking approval to modify the Program
                    accordingly.

       D.   Interim Program.

       The parties agree that the Company's current POP program will be replaced
       by the Interim Program as soon as reasonably feasible. The Interim
       Program will be reflected in tariffs to be filed timely by the Company so
       that the Interim Program will be available to existing POP customers when
       the POP program ends. The Interim Program will have the following program
       design elements:

          1.   In administering the Interim Program, Central Hudson will refer
               participants to other local assistance programs and to the
               EmPower NY Program.

          2.   Interim Program Participants must agree to be referred by Central
               Hudson to NYSERDA's EmPower NY Program and to complete an
               application for participation.

          3.   The customers may participate in the program for up to 24 months
               or until the permanent program is in place, whichever is sooner.

          4.   Existing POP customers will be automatically enrolled into the
               interim program.


                                       37
<PAGE>

          5.   New participants must meet the eligibility requirements described
               above for the EPOP.

          6.   Participants must agree to budget billing for future bills.

          7.   Arrears forgiveness incentive. Collection activity on a
               participating customer's pre-program arrears will be suspended
               while the customer is in the program. One twenty-fourth (1/24) of
               the customer's arrears balance up to a maximum of $100 per month
               will be forgiven each month a participating customer pays current
               charges on time and in full. A customer failing to make a payment
               of current charges on time and in full will not receive any
               arrears forgiveness for that month. The customer may continue in
               the program for future months by paying the late bill and any
               associated late payment charges and paying the bills in future
               months on time and in full.

          8.   Customers will not be charged a late payment charge on their
               suspended arrears, but will be charged a late payment charge if
               they pay their budget payments late.

          9.   Discounted Customer Charge. The Interim Program will discount the
               customer charge for participants to $5.00 per month for gas
               service and to $5.00 per month for electric service ($10 total
               for dual service customers).

          10.  Central Hudson will have the discretion to include a customer in
               the program who does not meet all the eligibility criteria upon
               evidence that program participation will increase the likelihood
               that the customer will be able to maintain continuous service
               without compromising other essential household needs.

          11.  Reporting.

               a)   Quarterly Reports.

                    (1)  Central Hudson will provide Staff and other interested
                         parties with a quarterly report on the Interim Program
                         within 30 days of the end of each Program quarter. The
                         reports will show the following information by month:
                         the number of active program participants, the number
                         of


                                       38
<PAGE>

                         enrollments and departures, the total amount of
                         customer service charge credits provided, amount of
                         arrears forgiven, and administration costs.

                    (2)  The quarterly reports may include such other
                         information as the Company and the parties agree may be
                         useful to evaluate the program's impacts on customers
                         and on the Company.

                    (3)  An overview of the level of program spending to date
                         should be provided with the intent to keep a check on
                         the level of program spending and budget.

               b)   Annual Reporting. In lieu of a quarterly report for the
                    final operating quarter of the Interim Program in RY1,
                    Central Hudson will prepare an annual report which will
                    provide the same information as in the quarterly reports but
                    on a rate year basis, as well as Central Hudson's assessment
                    of program operations.

XIII.     CUSTOMER SERVICE QUALITY PERFORMANCE MECHANISM

       A.   Effective Date.

       The current mechanism set forth in the 2004 Rate Order will remain in
       effect through December 31, 2006. The new mechanism described below will
       become effective on January 1, 2007, for a potential total annual rate
       adjustment of 25 basis points. All basis point rate adjustments for this
       new mechanism will be calculated on a combined electric and gas basis.

       B.   Customer Satisfaction Index ("CSI").

          1.   Central Hudson will calculate its monthly and annual CSI
               performance consistent with the survey methodology defined in the
               Central Hudson document entitled "How Did We Do Survey" -
               Continuous Improvement through Monitoring Customer Satisfaction
               with Key Customer Processes.


                                       39
<PAGE>

          2.   Thresholds and rate adjustments for the CSI are:

                     ----------------------------------------------------
                      CSI Annual Performance         Basis Points Rate
                                                     Adjustment
                     ----------------------------------------------------
                      85 or Higher                   None
                     ----------------------------------------------------
                      84 = CSI < 85                  3.125
                     ----------------------------------------------------
                      83 = CSI <84                   6.25
                     ----------------------------------------------------
                      82 = CSI < 83                  9.375
                     ----------------------------------------------------
                      CSI <82                        12.5
                     ----------------------------------------------------

       C.   PSC Complaint Rate.

          1.   The PSC complaint rate is the annual average of the number of
               monthly complaints per 100,000 customers.

          2.   The thresholds and rate adjustments are:

                   PSC Annual                      Basis Point Rate
                   ----------                      ----------------
                   Complaint Rate                  Adjustment
                   --------------                  ----------

                  <2.5                             None
                   2.5                             6.00
                   2.6                             6.65
                   2.7                             7.30
                   2.8                             7.95
                   2.9                             8.60
                   3.0                             9.25
                   3.1                             9.90
                   3.2                             10.55
                   3.3                             11.20
                   3.4                             11.85
                   3.5                             12.50

       D.   Appointments Kept.

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

       E.   Evaluation of Telephone System Enhancements:

          1.   Central Hudson will conduct an evaluation of the "virtual hold"
               telephone enhancements it has made to its telephone answering
               procedures. The


                                       40
<PAGE>

               company will report on the results in July 2006, and January and
               June 2007.

          2.   Discussions among the parties will be held beginning in July 2007
               regarding a possible telephone response metric (and
               redistribution of the existing 25 Basis Point rate adjustment for
               CSI/PSC Complaint Rate) to go into effect prospectively.

       F.   Reporting.

          1.   The Company will provide annual reports to the Director of the
               Office of Consumer Services (OCS) on its performance under each
               customer service quality performance measure within 45 days of
               the end of the reporting period. The annual report shall include
               information on whether any revenue adjustments are warranted
               under the Customer Service Quality Performance Mechanism.

          2.   A Report on the CSI for the period ending December 31, 2006 will
               be submitted within 45 days of the end of that year. It will
               include the presentation of quantitative and qualitative analysis
               of results, and the factors that the Company expects influenced
               the results, as well as the following:

               a)   The CSI margin of error calculated as shown in Appendix L.

               b)   Number and percent of responses received by each survey
                    type;

               c)   Percent satisfaction for each survey question by survey
                    type;

               d)   Any planned changes in customer service operations due to
                    survey results; and

               e)   An appendix (based primarily on existing materials) that
                    describes in detail the survey and analysis methodology will
                    be included with the first annual report submitted.


                                       41
<PAGE>

          3.   Subsequent to the initial Report, the CSI Report will be filed on
               an annual basis with the Customer Service Quality Performance
               Mechanism Report. The company will convene a meeting with
               interested parties within 30 days of issuing the annual CSI
               Report to discuss the customer satisfaction survey and any
               changes in customer service operations proposed as a result of
               the survey.

XIV.      GAS SAFETY MECHANISM

       A.   General.

       All Gas Safety targets metrics are measured on a calendar year basis. The
       Gas Safety targets and rate adjustment levels applicable in calendar year
       2006 are set in the 2004 Rate Plan. The calendar year 2008 Gas Safety
       targets set forth below will continue until changed by the Commission.
       Basis point rate adjustments will be calculated on the gas equity
       component of gas rate base that is shown on Appendix H, Schedule 2.

       B.   Leak Management.

          1.   For the calendar year ending December 31, 2007, Central Hudson
               will incur a rate adjustment if a year-end total leak backlog of
               270 is exceeded, unless the Company repairs 340 leaks during that
               calendar year. The rate adjustment if the target thresholds are
               not met is 6 basis points.

          2.   For the calendar year ending December 31, 2008, Central Hudson
               will incur a rate adjustment if a year-end total leak backlog of
               250 is exceeded, unless the Company repairs 340 leaks during that
               calendar year. The rate adjustment if the target thresholds are
               not met is 8 basis points.

       C.   Prevention of Excavation Damages.

          1.   Overall Damages.

               a)   For the calendar year ending December 31, 2007, Central
                    Hudson will incur a rate adjustment if the year-end total of
                    5.9


                                       42
<PAGE>

                    excavation damages per 1000 One-Call Tickets is exceeded
                    during that calendar year. The rate adjustment if the target
                    threshold is not met is 2 basis points.

               b)   For the calendar year ending December 31, 2008, Central
                    Hudson will incur a rate adjustment if the year-end total of
                    5.8 excavation damages per 1000 One-Call Tickets is exceeded
                    during that calendar year. The rate adjustment if the target
                    threshold is not met is 3 basis points.

          2.   Mismark Damages.

               a)   Mismarks 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).

               b)   For the calendar year ending December 31, 2007, Central
                    Hudson will incur a rate adjustment if the year-end total of
                    0.9 excavation damages due to mismarks per 1000 One-Call
                    Tickets is exceeded during that calendar year. The rate
                    adjustment if the target threshold is not met is 5 basis
                    points.

               c)   For the calendar year ending December 31, 2008, Central
                    Hudson will incur a rate adjustment if the year-end total of
                    0.8 excavation damages due to mismarks per 1000 One-Call
                    Tickets is exceeded during that calendar year. The rate
                    adjustment if the target threshold is not met is 5 basis
                    points.

       D.   Emergency Response.

       For the calendar years ending December 31, 2007, and 2008, Central Hudson
       will incur a rate adjustment if the following targets for response to gas
       leak and odor calls are not met: (a) respond to 75% of all gas leak and
       odor calls within 30 minutes, (b) respond to 90% of all gas leak and odor
       calls within 45 minutes, and (c) respond to 95% of all gas leak and odor
       calls


                                       43
<PAGE>

       within 60 minutes. The rate adjustments if the target thresholds are not
       achieved, are as follows: 2007 - 3 basis points for the 30 minute
       response time and 2 basis points for each of the 45 and 60 minute
       response times; 2008 and thereafter - 3 basis points for each of the 30,
       45, and 60 minute response times.

       E.   Gas Infrastructure Enhancement.

          1.   A target of $15.75 million is established for expenditures on Gas
               Cast Iron/Steel pipe replacement over the three-year period of
               the Rate Plan, subject to expenditure of no less than $4.5
               million in each calendar year, ending 12/31/2009.

          2.   The $15.75 million amount is comprised of the costs of
               installation and removal of Gas Cast Iron/Steel pipe replacement
               associated among: (1) the total category of New Business Gas
               Service Replacements blanket work orders, (2) the total category
               of Distribution Improvements Cast Iron Main Replacements blanket
               work orders, (3) the total category of Distribution Improvements
               Main Replacement blanket work orders, and (4) the summation of
               individual Distribution Improvement specific projects involving
               the replacement of non-plastic gas main.

          3.   If actual expenditures fall short of the total $15.75 million
               target level by the end of 2009, Central Hudson will defer for
               ratepayer benefit the amount of the shortfall multiplied by 1.5
               times average authorized pre-tax rate of return. Such deferral
               shall represent the sole remedy against the Company for failure
               to make expenditures at the total forecast level for replacement
               of cast iron and steel mains and services in the categories set
               forth in subsection 1 above. Commencing on January 1, 2010 such
               deferral will be subject to carrying charges calculated at the
               authorized pre-tax rate of return.

          4.   The $15.75 million target exceeds Central Hudson's forecast of
               construction costs for


                                       44
<PAGE>

               these items by $1.15 million. That amount is included in the
               forecast rate base included in the Income Statements in Appendix
               D.

       F.   Reporting.

          1.   Central Hudson will, by January 31st of each year, file a report
               with the Director of the Office of Gas & Water on its performance
               in meeting each of the above Gas Safety mechanismss.

          2.   By August 1 of each calendar year under this Joint Proposal, the
               Company will file a progress report with the Director of the
               Office of Gas & Water on its performance in meeting each of the
               above Gas Safety mechanisms.

          3.   The Company will cooperate with Staff in making back-up records
               and documentation related to the targets available for review and
               verification.

XV.       ELECTRIC RELIABILITY

       A.   SAIFI And CAIDI Targets.

       Effective January 1, 2006, for each calendar year, the target for the
       Customer Average Interruption Duration Index (CAIDI) is set at 2.50, and
       the target for the System Average Interruption Frequency Index (SAIFI) is
       set at 1.45.

          1.   A rate adjustment of 10 basis points (electric) will be assessed
               against Central Hudson for each failure to satisfy an annual
               target threshold.

          2.   Outages caused by "Major Storms," as defined at 16 NYCRR ss.97.1,
               and the following events, are excluded from the calculation of
               the indices:

               a)   Any incident resulting from a strike or a catastrophic event
                    beyond the control of the Company, including but not limited
                    to plane crash, water main break, or natural disaster (e.g.,
                    hurricane, flood, earthquake). This exclusion does not
                    include heat-related outages.

               b)   Any incident where a problem beyond the Company's control
                    involving generation or the bulk transmission system is the
                    key factor in the outage, including, but not limited to,


                                       45
<PAGE>

                    NYISO mandated load shedding. This criterion is not intended
                    to exclude incidents that occur as a result of
                    unsatisfactory performance by the Company.

       B.   Other Electric Reliability Targets.

       In addition to the SAIFI and CAIDI targets, reliability-oriented targets
       for significant construction projects targets are established as follows:

          1.   Central Hudson will be assessed a rate adjustment of 5 basis
               points (electric) for RY1, RY2, and RY3, if it does not complete
               100 circuit miles of enhanced distribution line clearing during
               each respective RY. Lines eligible for enhanced clearing are the
               300 miles of circuits that were not cleared previously under the
               Full Circuit Mainline Program that was part of the Enhanced
               Reliability Program approved in the 2001 Rate Plan.

          2.   Central Hudson will be assessed a rate adjustment of 5 basis
               points (electric) if it does not complete and energize its
               proposed East Kingston substation by June 30, 2007.

          3.   Central Hudson will be assessed a rate adjustment of 5 basis
               points for failing to complete reliability-related construction
               projects in calendar years 2007 and 2008, respectively, similar
               to the project described in (2) above that will be identified by
               Staff by January 1, 2007 and 2008, respectively, from among the
               electric reliability-related projects identified in the
               Company's updated capital forecasts, which will be presented to
               Staff during the third quarter of 2006 and 2007, respectively, in
               the meetings referred to below.

       C.   Other Provisions.

          1.   The Company will, following the Commission's adoption of this
               Joint Proposal, petition the Commission for permission to
               withdraw the Company's pending petition for rehearing of the
               Commission's Order issued September 30, 2005 concerning electric
               reliability. The 37.5 basis


                                       46
<PAGE>

               points penalties for not meeting reliability target thresholds in
               2002 and 2004 are reflected in Appendix G. Upon Commission
               adoption of this Joint Proposal, the Company is authorized to
               reverse the previous entry of the 2005 reliability penalty.

          2.   A forecast of 855 employees was recognized in rates for the
               purpose of allowing Central Hudson to fund the hiring of
               additional line mechanics.

          3.   Staff and the Company will meet quarterly in Company operating
               areas to discuss reliability and employee levels and utilization.

          4.   The Company will report on its compliance with electric
               reliability targets within 45 days of the end of each calendar
               year.

          5.   This reliability performance mechanism will remain in place until
               a subsequent approach is adopted by the Commission.

XVI.      MONTHLY METER READING/BILLING STUDIES

       A.   Monthly Billing Study.

       Central Hudson will develop and file with the Commission within 150 days
       following Commission adoption of this Joint Proposal, a study of the
       costs and benefits of converting from bi-monthly meter reading and
       billing to monthly meter reading and billing for all customers using
       existing metering. The study will identify the one-time and on-going
       incremental costs associated with the conversion to monthly metering and
       billing and the net effect on the Company revenue requirements. The study
       will include an implementation plan detailing the period of time that
       would be needed to accomplish the conversion. The study maybe updated
       following the completion the AMR Pilot described below.

       B.   AMR Pilot.

       Central Hudson will develop and file with the Commission by January 1,
       2007, an Automated Meter Reading (AMR) Pilot proposal, which will have
       the following characteristics:


                                       47
<PAGE>

          1.   The AMR Pilot will include 5000 meters (gas and electric
               combined).

          2.   A fixed network meter technology will be utilized.

          3.   The Pilot will be funded from the unused competitive metering
               funds held in the Benefit Fund, or excess depreciation reserve,
               up to a total program cost of $1,500,000.

          4.   Quarterly status reports will be filed with the Director of OCS
               providing the program status and costs.

          5.   A final report summarizing the results of twelve months of
               operational experience, and making any appropriate
               recommendations, will also be submitted.

       C.   Reporting.

       Following completion of the final report on the AMR Pilot, Central Hudson
       may update the study discussed above, to reflect any demonstrated
       benefits to be realized from implementation of monthly meter reading and
       billing using AMR technology, and make any appropriate recommendations to
       the Commission.

XVII.     RETAIL ACCESS

       A.   Market Match Program.

       The Market Match Program will continue, consisting of following elements:

          1.   A system on Central Hudson's Web site enabling the exchange of
               customer usage data with ESCOs for customers interested in
               obtaining competitive price offers from ESCOS.

          2.   Notification informing all non-residential customers of the
               Program annually via bill inserts or other mailings.


                                       48
<PAGE>

          3.   Responses from customers via the Web site indicating their
               interest in receiving solicitations for competitive price
               commodity options, contact information, and authorization for
               Central Hudson to provide the customer's service class,
               historical demand, energy consumption, etc. to participating
               ESCOs.

          4.   ESCO access to Central Hudson's Web site via a secure Web page
               that will allow ESCOs to obtain participating customer
               information and solicit customers by providing competitive price
               options.

          5.   Provisions for customers to exit the Market Match Program at any
               time via the Web site.

        B.    Market Expo Program.

        The Market Expo Program will continue, consisting of the following
        elements:

          1.   The Market Expo will continue to bring the ESCOs, business
               customers, and Central Hudson together to provide a forum for an
               exchange of customer data for customers interested in obtaining a
               competitive price.

          2.   The Expo will also provide a setting for customers to meet with
               ESCOs during the day.

          3.   Staff and Central Hudson will work together to develop the work
               plan for the Market Expo Program.

          4.   The work plan will detail how a maximum of two Expos annually
               should be held, the dates of the Expos, and describe the
               customers that will be invited.

          5.   E-mail and/or program announcement letters for ESCOs and
               customers will be developed and sent out at least two weeks prior
               to the event(s).


                                       49
<PAGE>

          6.   Central Hudson will:

               a)   Invite all non-residential utility commodity customers sized
                    greater than 100 kW to the Expo.

               b)   Conduct Expos that include giving an overview presentation
                    on the status of the electricity and gas markets in New
                    York, along with an explanation of Central Hudson's retail
                    access rules.

       C.   Energy Fairs.

          1.   One or two Energy Fairs will be conducted annually by the
               Company, in collaboration with Staff and ESCOs, prior to the
               winter heating season in each rate year.

          2.   Staff, the Company, and ESCOs will meet at least one month prior
               to the Energy Fairs to discuss the administrative details and
               logistics of the event.

          3.   Central Hudson will:

               a)   Secure the location and fund the reasonable logistics costs
                    for the Energy Fair.

               b)   Provide for adequate signage at the location to direct
                    customers to the event.

               c)   Issue invitations to targeted residential and small
                    commercial customers to attend the event at least two weeks
                    prior to the event.

               d)   Issue a press release publicizing the event at least two
                    weeks prior to the event.

               e)   Invite ESCO participation and arrange for reasonable and
                    appropriate ESCO facilities at the event. At least two ESCOs
                    offering residential commodity service must agree to
                    participate in the Energy Fairs prior to advertising the
                    event to the public.


                                       50
<PAGE>

               f)   Current utility customer account data will be made
                    accessible to the customer by the Company at the site of an
                    Energy Fair.

       D.   ESCO & Marketer Satisfaction Mechanism.

          1.   Central Hudson will conduct annually a telephone or e-mail
               survey, with a goal of attempting to maintain its current 100%
               ESCO participation in the survey.

          2.   Central Hudson will report to the Office of Retail Market
               Development within 60 days after the survey is conducted, on the
               results of the survey and its plans for addressing marketer
               concerns, if any, which were expressed in the survey.

       E.   ESCO Ombudsman.

          1.   The existing Ombudsman program will continue.

          2.   Central Hudson shall report quarterly on all ESCO contacts to the
               Ombudsman to the Director of the Office of Retail Market
               Development, including a brief description of any issues and
               concerns expressed to the Ombudsman.

       F.   Competition Awareness and Understanding Survey.

          1.   Central Hudson will continue to survey a sample of its
               residential customers annually for the purpose of tracking
               changes in customer awareness and understanding of competition in
               electricity and gas markets.

          2.   The Company will report the results of the survey to the Office
               of Retail Market Development as a component of its report on its
               outreach and education plan.

       G.   Competition Education Campaign.

       Central Hudson's rate allowance includes $350,000 in each of the Rate
       Years ending June 30, 2007, June 30, 2008, and June 30, 2009 for spending
       on a competition education campaign aimed at promoting customer
       migration. The Company will develop the campaign in


                                       51
<PAGE>

       collaboration with Staff and interested ESCOs. Actual expenditure
       shortfalls below the $350,000 rate allowances will be deferred for
       expenditure on the same purposes in future rate years.

       H.   ESCO Referral Program.

       This Joint Proposal does not affect Central Hudson's ESCO Referral
       Program, which was approved in an Order issued December 22, 2005 in Case
       05-M-0332; provided, however, that incremental costs incurred in
       implementing the Energy Switch Program to July 1, 2006 will be deferred
       for future recovery subject to carrying charges at the authorized pre-tax
       rate of return.

XVIII.    Further Understandings Between Central Hudson and USMA.

       A.   Best Efforts.

       Central Hudson and USMA will mutually use best efforts to accomplish the
       following by June 1, 2006:

          1.   Provision by Central Hudson to USMA of a quit claim deed, in
               recordable form, to USMA for all regulators, valves and pipelines
               and all other natural gas facilities located between Crow's Nest
               and Thayer Gate, except for the existing six meters (5 for the
               material balance for USMA and one for Hotel Thayer) along with
               directly associated regulators and valves supporting these
               meters.

          2.   Provision by either USMA or the Army Corps of Engineers, on
               behalf of USMA, of a written authorization that confirming that,
               pending receipt of the easement referred to below, CHGE is
               authorized by the government to have installed its pipelines and
               other facilities up to Crow's Nest, and that CHGE has the right
               to enter for purposes of maintenance and repair, subject to
               reasonable notification procedures.

       B.   Easement.

       USMA will support CHGE's request for a 50 year standard government
       easement before the U.S. Army


                                       52
<PAGE>

       Corps of Engineers for CHGE's pipeline facilities to Crow's Nest and
       request expedited issuance.

       C.   Refunds of Taxes.

       Central Hudson will cooperate with USMA concerning USMA's efforts to
       receive refunds of taxes that have been charged to USMA in CHGE's gas
       rates for which USMA believes it is not liable; subject to the
       understandings that the responsibility for identifying the taxes that
       USMA is interested in and all relevant information (aside from
       information related to Central Hudson's rates) rests with USMA, that
       Central Hudson will not perform any legal research for USMA in connection
       with USMA's tax status, that Central Hudson will not be obliged to make
       any representations to any taxing authorities as to USMA or USMA's tax
       status, that Central Hudson makes and will make no representations to
       USMA concerning USMA's tax responsibility, and that any tax refunds which
       CHGE receives will be subject to Section 113(2) of the Public Service
       Law.

       D.   Cost of Service Study.

       When it next files a new general combined or gas rate case, the Company
       will include in its gas cost of service study identification of those
       costs attributable to serving USMA and include with its rate design rates
       for USMA, or its parent service classification, based on no greater than
       a 100% revenue allocation of those costs to USMA and based on no greater
       than a 1.0 factor for application of any system average increase
       requested; provided, however, that nothing in this provision shall
       preclude the Company from filing and advocating such cost of service,
       class rates of return, revenue allocation or rate design as it may deem
       appropriate.

       E.   Reporting.

       Subsequent to the time it receives the easement referred to above,
       Central Hudson will provide to the West Point Contracting Officer an
       annual report of maintenance, testing, maintenance and repair of all
       Central Hudson-owned facilities located on-post. The report will be due
       by February 1 for all such activities conducted during the prior calendar
       year.


                                       53
<PAGE>

XIX.      TERMS AND CONDITIONS

       A.   Complete Resolution.

       This Joint Proposal is intended to be a complete resolution of all issues
       in Cases 05-E-0934 and 05-G-0935. 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. 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.

       B.   Reservation.

       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.

       C.   Integrated Document.

       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, 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 Joint Proposal, as executed or as modified.

       D.   Dispute Resolution.

       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


                                       54
<PAGE>

        such disagreement. If any such disagreement cannot be resolved by the
        Signatories, an affected Signatory may petition the Commission for
        relief on a disputed matter.

       E.   Non-Precedent.

       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.

       F.   Application for New Rates.

       Central Hudson may file an application(s) for new rates at any time,
       provided that any such rates will not become effective until after June
       30, 2009. Nothing in this provision shall affect the Commission's
       authority to suspend the effective date of a rate filing.

       G.   Safe and Adequate Service.

       Central Hudson may petition for new rates at any time on the grounds that
       without new rates safe, adequate and reliable service at just and
       reasonable rates would be jeopardized.

       H.   Continued Effect.

       Unless otherwise provided herein, the provisions of this Joint Proposal
       shall remain in effect until changed by the Commission.

       WHEREFORE, this Joint Proposal has been agreed to as of the 17th day of
April, 2006, by and among the following, each of whom, by its signature,
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 principal(s).


                                                    ____________________________


                                       55

<PAGE>


                             Appendix A, Schedule 1

                    Central Hudson Gas & Electric Corporation
                           Cases 05-E-0934 & 05-G-0935
                           Electric Income Statements
                                     ($000)

<TABLE>
<CAPTION>
                                                               Rate Years Ending
                                                         ------------------------------
                                                         6/30/07    6/30/08    6/30/09
Line No.                                                   (A)        (B)        (C)
--------                                                 --------   --------   --------
<S>                                                      <C>        <C>        <C>
           Operating Revenues

    1       Delivery Revenues - Before Increase          $170,486   $215,741   $225,615
    2       Rate Increase - Before Moderation              41,383      6,121      5,529
    3       Other Operating Revenues                        6,145      6,172      6,196
                                                         --------   --------   --------
    4         Total Operating Revenues                    218,014    228,034    237,340
                                                         --------   --------   --------

           Operating Expenses

    5       Production Maintenance                            143        146        149
    6       Transmission Right of Way Maintenance           2,187      2,240      2,296
    7       Distribution Right of Way Maintenance           7,804      8,116      8,442
    8       Labor                                          38,920     39,955     40,966
    9       Research and Development                        1,846      1,857      1,860
   10       Expenses Projected Based on Inflation           9,249      9,452      9,660
   11       Miscellaneous General Expenses                  2,408      2,453      2,498
   12       Transportation Depreciation                     1,334      1,363      1,393
   13       Fringe Benefits                                 6,011      6,158      6,329
   14       Other Post Employee Benefits                    8,382      8,382      8,382
   15       Pension Plan                                   10,568     10,568     10,568
   16       Contract Rents                                  2,120      2,167      3,414
   17       Uncollectible Accounts                          1,199      1,250      1,297
   18       Regulatory Commission Expenses                  1,349      1,379      1,409
   19       Data Processing Expense                         3,000      3,066      3,133
   20       Other Operating Insurance                       1,440      1,472      1,504
   21       Telephone                                       1,550      1,583      1,618
   22       Legal Services                                  2,316      2,367      2,419
   23       Special Services                                1,483      1,516      1,549
   24       Injuries and Damages                            1,959      2,002      2,046
   25       Storm Expense                                   5,197      5,311      5,428
   26       Environmental                                     309        316        323
   27       Powerful Opportunities Program                    976      1,125      1,275
   28       Expenses Allocated to Affiliates                 (491)      (502)      (513)
   29       Stray Voltage Testing                           2,200      2,250      2,300
   30       MGP Remediation Cost Recovery                      --      1,400      1,400
   31       Recovery of Net Regulatory Assets                  --         --         --
   32       Competition Education Program                     298        298        298
   33       Productivity                                     (149)      (149)      (149)
                                                         --------   --------   --------
   33         Total Operating Expenses                    113,608    117,541    121,296
                                                         --------   --------   --------

   34      Other Deductions

   35       Property Taxes                                 19,758     20,460     21,183
   36       Revenue Taxes                                   3,712      3,963      4,197
   37       Payroll Taxes                                   2,953      3,018      3,084
   38       Other Taxes                                     1,254      1,282      1,310
   39       Depreciation                                   21,682     22,554     23,746
   40       Moderator - Amortize Excess Reserves               --         --         --
                                                         --------   --------   --------
   41         Total Other Deductions                       49,359     51,277     53,520
                                                         --------   --------   --------

   42       State Income Taxes                              2,942      3,099      3,184
   43       Federal Income Taxes                           13,753     15,130     15,450
                                                         --------   --------   --------
   44         Total Income Taxes                           16,695     18,230     18,634
                                                         --------   --------   --------

   45      Total Operating Revenue Deductions             179,662    187,048    193,450
                                                         --------   --------   --------

   46      Operating Income                              $ 38,353   $ 40,986   $ 43,890
                                                         ========   ========   ========

   47      Rate Base                                     $544,007   $578,065   $615,375
                                                         ========   ========   ========

   48      Rate of Return                                    7.05%      7.09%      7.13%
                                                         ========   ========   ========
</TABLE>

<PAGE>

                             Appendix A, Schedule 2

                    Central Hudson Gas & Electric Corporation
                           Cases 05-E-0934 & 05-G-0935
                         Electric Rate Increase Phase-In
                                     ($000)

<TABLE>
<CAPTION>
                                                               Rate Years Ending
                                                        --------------------------------
                                                         6/30/07     6/30/08    6/30/09
                                                        ---------   ---------   --------
Line No.                                                   (A)         (B)        (C)
--------                                                ---------   ---------   --------
<S>                                                     <C>         <C>         <C>
           Electric Rate Increase Phase-In:

    1      Required Electric Rate Increases              $ 41,383    $  6,121   $  5,529

           Moderation of Rate Increases:

    2       RY1 Moderation                                (23,495)     23,918
    3       RY2 Moderation                                            (12,150)    12,357
    4       RY3 Moderation                                                             0
                                                        ---------   ---------   --------

    5      Phase-In Electric Rate Increases              $ 17,888    $ 17,889   $ 17,888
                                                        =========   =========   ========

           Use of Moderators:

    6       Amount of Moderators                        ($ 22,887)  ($ 11,840)  $      0
    7       / Gross up Factor                             0.97410     0.97410    0.97410
                                                        ---------   ---------   --------
    8       Revenue Requirement                         ($ 23,495)  ($ 12,150)  $      0
                                                        =========   =========   ========

           Loss of Revenue Growth Due to Phase-In:

    9       RY1 Moderation                              ($ 23,495)
   10       x Revenue Growth Rate                           1.018 =  $ 23,918
                                                        ---------   =========

   11       RY2 Moderation                                            (12,150)
   12       x Revenue Growth Rate                                       1.017 = $ 12,357
                                                                     --------   ========
</TABLE>

<PAGE>

                             Appendix A, Schedule 3

                    Central Hudson Gas & Electric Corporation
                           Cases 05-E-0934 & 05-G-0935
                               Electric Rate Base
                                     ($000)

<TABLE>
<CAPTION>
                                                            Electric
                                              -----------------------------------
                                                       Rate Years Ending
                                              -----------------------------------
                                               6/30/07      6/30/08      6/30/09
                                              ---------    ---------    ---------
<S>                                           <C>          <C>          <C>
Book Cost of Utility Plant                    $ 862,277    $ 907,246    $ 960,008
Less: Accumulated Provision for
   Depreciation and Amortization               (302,582)    (314,239)    (327,595)
                                              ---------    ---------    ---------

Net Plant                                       559,695      593,007      632,413

Noninterest-Bearing Construction
   Work in Progress                              39,705       44,887       48,105

Preliminary Survey & Investigation                    0            0            0

Customer Advances for Undergrounding               (179)        (179)        (179)

Deferred Charges                                 14,978       14,773       13,347

Accumulated Deferred Federal Taxes              (90,257)     (94,567)     (98,715)

Accumulated Deferred State Taxes                 (2,739)      (3,468)      (4,206)

Working Capital                                  30,425       31,232       32,232
                                              ---------    ---------    ---------

Unadjusted Rate Base                            551,628      585,686      622,996

Capitalization Adjustment to Rate Base           (7,621)      (7,621)      (7,621)
                                              ---------    ---------    ---------

Total                                         $ 544,007    $ 578,065    $ 615,375
                                              =========    =========    =========
</TABLE>

<PAGE>

                                   Appendix B

                    Central Hudson Gas & Electric Corporation
                           Cases 05-E-0934 & 05-G-0935
                           Electric Revenue Allocation
           Min .75x, Max 1.25x, S.C. No. 13 Set to S.C. No. 1 Average

                                   Rate Year 1

<TABLE>
<CAPTION>
                              (1)          (2)       (3)         (4)          (5)
                                           Rate                  Adj        Adj to
                          Initial Net       of      2.59%        Net      Initial Net
                            Income        Return   +/- 15%     Income       Income
                          -----------    -------   -------    --------    -----------
<S>                       <C>            <C>       <C>        <C>         <C>
       Total              $    14,142      2.59%              $ 12,973    $    14,142

SC 1 Residential          $     6,564      1.94%    2.20%     $  7,449    $     8,120
SC 2 Non Demand           $    (2,377)    -6.36%    2.20%     $    823    $       897
SC 2 Secondary            $     7,650      7.77%    2.98%     $  2,934    $     3,198
SC 2 Primary              $       460      4.65%    2.98%     $    295    $       321
SC 3 Primary              $     1,064      7.18%    2.98%     $    442    $       481
SC 5 Area Lighting        $       148      2.45%              $    148    $       161
SC 6 Residential TOU      $       497      8.65%    2.98%     $    171    $       187
SC 8 Street Lighting      $       (52)    -0.63%    2.20%     $    182    $       198
SC 13 Substation          $        56      1.36%    2.20%     $     91    $        99
SC 13 Transmission        $       132      0.66%    2.20%     $    440    $       480



SC 9 Traffic Signals      $       (49)   -16.22%    2.20%     $      7    $         7

<CAPTION>
                                                            Excludes Revenue Taxes
                                                      ---------------------------------
                              (6)          (7)           (8)          (9)        (10)         (11)
                            (5)-(1)     (6)/.60125                              (7)+(9)     (10)/(8)
                                           Adj           Base      Base Rev      Total     % Increase
                          Difference     FIT/SIT        Rates      Increase    Increase    Unadjusted
                          ----------    ----------    ---------    --------    --------    ----------
<S>                       <C>           <C>           <C>          <C>         <C>         <C>
       Total                                          $ 167,722    $ 17,433    $ 17,433      10.39%

SC 1 Residential          $    1,556    $    2,588    $ 101,450    $ 10,545    $ 13,132      12.94%
SC 2 Non Demand           $    3,274    $    5,445    $   7,416    $    771    $  6,216      83.82%
SC 2 Secondary            $   (4,452)   $   (7,404)   $  38,878    $  4,041    $ (3,363)     -8.65%
SC 2 Primary              $     (139)   $     (231)   $   3,353    $    349    $    118       3.52%
SC 3 Primary              $     (583)   $     (969)   $   5,630    $    585    $   (384)     -6.82%
SC 5 Area Lighting        $       13    $       22    $     917    $     95    $    117      12.81%
SC 6 Residential TOU      $     (310)   $     (516)   $   2,311    $    240    $   (276)    -11.94%
SC 8 Street Lighting      $      250    $      416    $   2,578    $    268    $    684      26.52%
SC 13 Substation          $       43    $       71    $   1,184    $    123    $    194      16.40%
SC 13 Transmission        $      348    $      578    $   4,005    $    416    $    994      24.83%

                                                      Tot. Rev.
                                                      ---------
SC 9 Traffic Signals      $       56    $       94    $     176                              53.15%
</TABLE>

<TABLE>
<CAPTION>
                              (12)         (13)          (14)         (15)        (16)        (17)
                                                       (8)*(12)     (8)*(13)    (14)+(15)   (10)-(16)
                           % Increase   % Increase    $ Increase   $ Increase                Revenue
                          Constrained   Unadjusted   Constrained   Unadjusted     Total     Shortfall
                          -----------   ----------   -----------   ----------   ---------   ---------
<S>                       <C>           <C>          <C>           <C>          <C>         <C>
                                                     $     5,219   $   13,921   $  19,140   $  (1,707)

SC 1 Residential                 0.00%       12.94%  $        --   $   13,132   $  13,132   $  (1,257)
SC 2 Non Demand                 12.99%        0.00%  $       964   $       --   $     964   $      --
SC 2 Secondary                   7.80%        0.00%  $     3,031   $       --   $   3,031   $    (290)
SC 2 Primary                     7.80%        0.00%  $       261   $       --   $     261   $     (25)
SC 3 Primary                     7.80%        0.00%  $       439   $       --   $     439   $     (42)
SC 5 Area Lighting               0.00%       12.81%  $        --   $      117   $     117   $     (11)
SC 6 Residential TOU             7.80%        0.00%  $       180   $       --   $     180   $     (17)
SC 8 Street Lighting            12.99%        0.00%  $       335   $       --   $     335   $      --
SC 13 Substation                 0.00%       12.94%  $        --   $      153   $     153   $     (15)
SC 13 Transmission               0.00%       12.94%  $        --   $      518   $     518   $     (50)

SC 9 Traffic Signals             5.20%               $         9                $       9   $      (1)

<CAPTION>
                             (18)         (19)         (20)         (21)         (22)            (23)
                          (16)+(17)     (18)/(8)                  (18)+(20)    (21)/(8)    (18)/(18) System
                           Revenue       Revenue     Revenue         Adj         Final      Increase as a
                          $ Increase   % Increase   Adjustment   $ Increase   % Increase     % of System
                          ----------   ----------   ----------   ----------   ----------   ----------------
<S>                       <C>          <C>          <C>          <C>          <C>          <C>
                          $   17,433        10.39%               $   17,434        10.39%            100.00%

SC 1 Residential          $   11,876        11.71%  $      (34)  $   11,842        11.67%             68.11%
SC 2 Non Demand           $      964        12.99%  $       (3)  $      961        12.95%              5.53%
SC 2 Secondary            $    2,741         7.05%  $       (8)  $    2,733         7.03%             15.72%
SC 2 Primary              $      236         7.05%  $       (1)  $      235         7.02%              1.36%
SC 3 Primary              $      397         7.05%  $       (1)  $      396         7.03%              2.28%
SC 5 Area Lighting        $      106        11.59%  $       --   $      106        11.59%              0.61%
SC 6 Residential TOU      $      163         7.05%  $       --   $      163         7.05%              0.93%
SC 8 Street Lighting      $      335        12.99%  $       (1)  $      334        12.95%              1.92%
SC 13 Substation          $      139        11.71%  $       --   $      139        11.71%              0.80%
SC 13 Transmission        $      469        11.71%  $       (1)  $      468        11.68%              2.69%

SC 9 Traffic Signals      $        8         4.70%  $       50   $       58        33.11%              0.05%
</TABLE>

                        Increase
                        --------
        Avg.                 10.39%
        Min         0.75x     7.80%
        Max         1.25x    12.99%

                                Rate Years 2 & 3

<TABLE>
<CAPTION>
                                                              Rate Year 2
                                          -----------------------------------------------------
                          Increase as a   Base Rev       %       Adj. for Rev Unbundled to MFCs
                           % of System    Increase   Increase      MWh       MFC/kWh     Total
                          -------------   --------   --------   ---------   ---------   -------
<S>                       <C>             <C>        <C>        <C>         <C>         <C>
       Total                     100.00%  $ 17,434       9.42%                          $ 8,766

SC 1 Residential                  68.11%  $ 11,874      10.48%  2,123,820   $ 0.00321   $ 6,817
SC 2 Non Demand                    5.53%  $    964      11.51%    187,020   $ 0.00072   $   135
SC 2 Secondary                    15.72%  $  2,741       6.59%  1,501,650   $ 0.00072   $ 1,081
SC 2 Primary                       1.36%  $    237       6.61%    240,630   $ 0.00072   $   173
SC 3 Primary                       2.28%  $    397       6.60%    385,910   $ 0.00021   $    81
SC 5 Area Lighting                 0.61%  $    106      10.39%     14,210   $ 0.00082   $    12
SC 6 Residential TOU               0.93%  $    162       6.55%     54,000   $ 0.00321   $   173
SC 8 Street Lighting               1.92%  $    335      11.50%     22,460   $ 0 00082   $    18
SC 13 Substation                   0.80%  $    139      10.55%    165,620   $ 0.00021   $    35
SC 13 Transmission                 2.69%  $    469      10.48%  1,134,220   $ 0.00021   $   238

SC 9 Traffic Signals               0.05%  $      9      14.96%      3,430   $ 0.00082   $     3

<CAPTION>
                                               Rate Year 3
                          -----------------------------------------------------
                          Base Rev       %       Adj. for Rev Unbundled to MFCs
                          Increase   Increase      MWh       MFC/kWh     Total
                          --------   --------   ---------   ---------   -------
<S>                       <C>        <C>        <C>         <C>         <C>
       Total              $ 17,433       8.61%                          $ 8,942

SC 1 Residential          $ 11,874       9.49%  2,168,620   $ 0.00321   $ 6,961
SC 2 Non Demand           $    964      10.32%    188,290   $ 0.00072   $   136
SC 2 Secondary            $  2,740       6.18%  1,537,710   $ 0.00072   $ 1,107
SC 2 Primary              $    237       6.20%    244,970   $ 0.00072   $   176
SC 3 Primary              $    397       6.19%    392,270   $ 0.00021   $    82
SC 5 Area Lighting        $    106       9.41%     14,540   $ 0.00082   $    12
SC 6 Residential TOU      $    162       6.15%     54,000   $ 0.00321   $   173
SC 8 Street Lighting      $    335      10.31%     22,390   $ 0.00082   $    18
SC 13 Substation          $    139       9.54%    165,620   $ 0.00021   $    35
SC 13 Transmission        $    469       9.49%  1,136,850   $ 0.00021   $   239

SC 9 Traffic Signals      $      9      13.01%      3,410   $ 0.00082   $     3
</TABLE>

<PAGE>

                             Appendix C Sheet 1 of 8

                    Central Hudson Gas & Electric Corporation
                           Cases 05-E-0934 & 05-G-0935
               Summary of Proposed Monthly Electric Delivery Rates
                           (Excludes S.C. Nos. 5 & 8)

<TABLE>
<CAPTION>
                                                          Current Rates    Rate Year 1    Rate Year 2    Rate Year 3
                                                          -------------    -----------    -----------    -----------
<S>                             <C>                       <C>              <C>            <C>            <C>
S.C. No. 1
                                Customer Charge           $       12.00    $     13.50    $     15.00    $     16.00
                                kWh                       $     0.03167    $   0.03523    $   0.03544    $   0.03955
S.C. No. 2 - Non-Demand
                                Customer Charge           $       14.00    $     16.00    $     18.00    $     20.00
                                kWh                       $     0.01432    $   0.01583    $   0.01662    $   0.01810
S.C. No. 2 - Secondary
                                Customer Charge           $       20.00    $     23.50    $     27.00    $     30.00
                                kWh                       $     0.00486    $   0.00501    $   0.00431    $   0.00431
                                kW                        $        6.18    $      6.61    $      7.07    $      7.53
S.C. No. 2 - Primary
                                Customer Charge           $       80.00    $     90.00    $    100.00    $    110.00
                                kWh                       $     0.00107    $   0.00116    $   0.00126    $   0.00135
                                kW                        $        4.61    $      4.91    $      4.94    $      5.23
S.C. No. 3
                                Customer Charge           $      250.00    $    400.00    $    400.00    $    400.00
                                kWh                       $     0.00250    $        --    $        --    $        --
                                kW                        $        5.22    $      6.69    $      7.05    $      7.49
                                Rkva                      $        0.44    $      0.44    $      0.44    $      0.44
S.C. No. 6
                                Customer Charge           $       12.00    $     14.50    $     17.00    $     19.00
                                On-Peak kWh               $     0.06423    $   0.06708    $   0.06418    $   0.06751
                                Off-Peak kWh              $     0.02141    $   0.02236    $   0.02139    $   0.02250
S.C. No. 9 - Traffic Signals
                                Charge per Signal Face    $          --    $      1.90    $      2.10    $      2.40
S.C. No. 13 - Substation
                                Customer Charge           $      500.00    $    500.00    $    500.00    $    500.00
                                kWh                       $     0.00150    $        --    $        --    $        --
                                kW                        $        2.90    $      4.18    $      4.52    $      4.98
                                Rkva                      $        0.44    $      0.44    $      0.44    $      0.44
S.C. No. 13 - Transmission
                                Customer Charge           $      500.00    $    500.00    $    500.00    $    500.00
                                kWh                       $     0.00100    $        --    $        --    $        --
                                kW                        $        1.52    $      2.39    $      2.51    $      2.75
                                Rkva                      $        0.44    $      0.44    $      0.44    $      0.44
</TABLE>

<PAGE>

                             Appendix C Sheet 2 of 8

                    Central Hudson Gas & Electric Corporation
                           Cases 05-E-0934 & 05-G-0935
                          Electric Billing Determinants
            (Excludes S.C. Nos. 5 & 8, Unbilled & Interdepartmental)

<TABLE>
<CAPTION>
                                                           Rate Year 1       Rate Year 2       Rate Year 3
                                                          -------------     -------------     -------------
<S>                             <C>                       <C>               <C>               <C>
S.C. No. 1                      Customer Months               2,978,064         3,000,048         3,020,808
                                kWh                       2,074,960,000     2,123,820,000     2,168,620,000

S.C. No. 2 - Non-Demand         Customer Months                 339,696           341,112           342,648
                                kWh                         185,770,000       187,020,000       188,290,000

S.C. No. 2 - Secondary          Customer Months                 140,364           143,964           147,936
                                kWh                       1,463,470,000     1,501,650,000     1,537,710,000
                                kW                            4,685,870         4,808,210         4,923,750

S.C. No. 2 - Primary            Customer Months                   2,100             2,148             2,184
                                kWh                         235,970,000       240,630,000       244,970,000
                                kW                              636,180           648,750           660,450

S.C. No. 3                      Customer Months                     540               552               564
                                kWh                         379,190,000       385,910,000       392,270,000
                                kW                              861,380           876,650           891,130
                                Rkva                            115,280           117,320           119,230

S.C. No. 6                      Customer Months                  30,720            30,720            30,720
                                On-Peak kWh                  18,360,000        18,360,000        18,360,000
                                Off-Peak kWh                 35,640,000        35,640,000        35,640,000

S.C. No. 9 - Traffic Signals    Signal Face Months            30,734.16         30,734.16         30,554.95

S.C. No. 13 - Substation        Customer Months                      84                84                84
                                kWh                         165,620,000       165,620,000       165,620,000
                                kW                              302,507           304,716           304,716
                                Rkva                             37,250            37,250            37,250

S.C. No. 13 - Transmission      Customer Months                      96                96                96
                                kWh                       1,135,560,000     1,134,220,000     1,136,850,000
                                kW                            1,839,929         1,907,337         1,911,580
                                Rkva                             56,140            56,140            56,140
</TABLE>

<PAGE>

                             Appendix C Sheet 3 of 8

                    Central Hudson Gas & Electric Corporation
                           Cases 05-E-0934 & 05-G-0935
              Electric Commodity Related Merchant Function Charges

                                       MFC (A)     MFC (B)     MFC (T)
                     Applicable to
                       S. C. No.        $/kWh       $/kWh       $/kWh
                                       -------     -------     -------
          MFC-1          1 & 6         0.00145     0.00176     0.00321
          MFC-2            2           0.00037     0.00035     0.00072
          MFC-3          3 & 13        0.00013     0.00008     0.00021
          MFC-4         5, 8 & 9       0.00013     0.00069     0.00082

Notes:

   1.    Customers taking commodity service from Central Hudson will be billed
         by Central Hudson for MFC(T), which is equal to the sum of MFC(A) and
         MFC(B).

   2.    MFC(A) will include the allocated portion of collection function costs
         and 50% of procurement-related call center function costs, plus
         administrative & general and rate base items associated with each of
         these items. Customers that choose to purchase their commodity service
         from an energy services company (ESCO) that is participating in
         Central Hudson's Purchase of Receivables (POR) Program will be billed
         by Central Hudson for MFC(A) only.

   3.    MFC(B) will include commodity purchasing function costs, allocated
         portions of advertising & promotions function costs and 50% of
         procurement-related call center function costs, plus administrative &
         general and rate base items associated with each of these items.

<PAGE>

                             Appendix C Sheet 4 of 8

                    Central Hudson Gas & Electric Corporation
                           Cases 05-E-0934 & 05-G-0935
                 Electric & Gas Embedded Cost of Service Studies

Summary of Revisions to Exhibits (LGA-1) & (LGA-2):

      o     The delivery/commodity relationship used for the functionalization
            of certain unbundled costs within the electric and gas embedded cost
            of service studies was revised to reflect the delivery/commodity
            relationship of revenues for the twelve months ended December
            31, 2005.

      o     Procurement Function - The Company developed a new allocation factor
            to replace the "ENERGY" COS class allocation factor for the
            "Procurement Function" shown on Exhibits ____(LGA-2), Schedule C,
            Page 1 (electric) and ____(LGA-1), Schedule C, Page 1 (gas). The new
            allocator is a blended factor that attributes the components of the
            procurement function to the COS classes as follows:

                  o     CHG&E Commodity-buyers costs - allocated to classes on
                        ENERGY as per the company's negotiated revisions to the
                        rate year #1 sales forecast by class;

                  o     Credit and Collections on Commodity - allocated to the
                        COS classes on number of customers via the CODBT
                        allocation factor;

                  o     Call Center costs related to Commodity - allocated to
                        COS classes on number of customers via CODBT allocation
                        factor.

      o     Delivery Service Uncollectibles, Credit and Collections:

                  o     All of Line 28 was redistributed vertically within each
                        COS class to all other functions except "Procurement"
                        re: Exhibit _____(LGA-1), Schedule C, Page 1 (gas);

                  o     All of Line 31 was re-distributed vertically within each
                        COS class to all functions other than "Procurement". re:
                        Exhibit_(LGA-2), Schedule C, Page 1.

      o     The amount originally (mistakenly) attributed to electric O&M
            account 565 was re-distributed among the other O&M Transmission
            accounts;

      o     Gas(i) and Electric demand, sales, revenue and customer allocators
            were revised to reflect Staff and Company revisions to the gas and
            electric sales forecasts. The demand allocators for SD, PD, LGP, LGS
            and LGT were developed from Ms. Bunt's forecasts;

      o     The classification of electric distribution lines was revised per
            agreement with Staff witness Allen;

      o     The inputs to the gas and electric rate year #1 COS studies were
            revised to reflect Staff rate year #1 Income Statement changes to
            rate base, revenues, O&M and taxes as provided to the Company for
            electric and gas.

----------
(i) Some specific changes included elimination of < 6" lines from West Point
gross plant; reduction of West Point MDQ from 7104 to 5833 Mcf; reduction in
SC11 transmission customers and sales due to closure of IBM West complex.

<PAGE>

                             Appendix C Sheet 5 of 8

                    Central Hudson Gas & Electric Corporation
                           Cases 05-E-0934 & 05-G-0935
               Comparison of Present and Proposed Electric Rates

                        Single Phase Residential Service
                 Service Classification No. 1 - General Service

Energy kWh     Present Rates     Proposed Rates     Change ($)     Change (%)
----------     -------------     --------------     ----------     ----------

        --     $       12.29     $        13.82     $     1.54          12.50%
        12     $       13.48     $        15.06     $     1.58          11.72%
        25     $       14.77     $        16.40     $     1.63          11.02%
        50     $       17.25     $        18.97     $     1.72           9.96%
        75     $       19.73     $        21.54     $     1.81           9.17%
       100     $       22.21     $        24.11     $     1.90           8.56%
       132     $       25.39     $        27.41     $     2.02           7.94%
       150     $       27.18     $        29.26     $     2.08           7.66%
       175     $       29.66     $        31.83     $     2.17           7.33%
       200     $       32.14     $        34.40     $     2.26           7.05%
       250     $       37.10     $        39.55     $     2.45           6.60%
       300     $       42.07     $        44.69     $     2.63           6.25%
       350     $       47.03     $        49.84     $     2.81           5.98%
       400     $       51.99     $        54.98     $     2.99           5.76%
       450     $       56.95     $        60.13     $     3.18           5.58%
       500     $       61.92     $        65.28     $     3.36           5.42%
       600     $       71.84     $        75.57     $     3.72           5.18%
       700     $       81.77     $        85.86     $     4.09           5.00%
       800     $       91.69     $        96.15     $     4.45           4.86%
       900     $      101.62     $       106.44     $     4.82           4.74%
     1,000     $      111.55     $       116.73     $     5.18           4.64%
     1,200     $      131.40     $       137.31     $     5.91           4.50%
     1,500     $      161.18     $       168.18     $     7.00           4.35%
     2,000     $      210.81     $       219.63     $     8.83           4.19%
     2,500     $      260.43     $       271.08     $    10.65           4.09%
     3,000     $      310.06     $       322.54     $    12.47           4.02%
     3,500     $      359.69     $       373.99     $    14.29           3.97%
     4,000     $      409.32     $       425.44     $    16.12           3.94%
     4,500     $      458.95     $       476.89     $    17.94           3.91%
     5,000     $      508.58     $       528.34     $    19.76           3.89%
    10,000     $    1,004.88     $     1,042.86     $    37.99           3.78%
    20,000     $    1,997.46     $     2,071.90     $    74.44           3.73%

The following rates were used in the development of these bills:

Market Price Charge              $      0.06701     per kWh
Market Price Adjustment          $           --     per kWh
Purchased Power Adjustment       $     (0.00225)    per kWh
Miscellaneous Charges            $      0.00066     per kWh
SBC/RPS                          $      0.00116     per kWh
Revenue Tax Rate - Commodity              0.339%
Revenue Tax Rate - Delivery               2.339%

<PAGE>

                             Appendix C Sheet 6 of 8

                    Central Hudson Gas & Electric Corporation
                           Cases 05-E-0934 & 05-G-0935
               Comparison of Present and Proposed Electric Rates

                               Non-Demand Metered
                 Service Classification No. 2 - General Service

Energy kWh   Present Rates   Proposed Rates   Change ($)   Change (%)
----------   -------------   --------------   ----------   ----------

        --   $       14.05   $        16.05   $     2.01        14.29%
        12   $       15.02   $        17.05   $     2.02        13.48%
        25   $       16.08   $        18.12   $     2.04        12.72%
        50   $       18.11   $        20.19   $     2.08        11.50%
        75   $       20.14   $        22.26   $     2.12        10.53%
       100   $       22.17   $        24.32   $     2.16         9.74%
       132   $       24.76   $        26.97   $     2.21         8.91%
       150   $       26.22   $        28.46   $     2.23         8.52%
       175   $       28.25   $        30.53   $     2.27         8.04%
       200   $       30.28   $        32.59   $     2.31         7.63%
       500   $       54.64   $        57.40   $     2.76         5.06%
       750   $       74.93   $        78.07   $     3.14         4.19%
     1,000   $       95.22   $        98.74   $     3.52         3.70%
     2,500   $      216.99   $       222.78   $     5.79         2.67%
     5,000   $      419.92   $       429.51   $     9.58         2.28%
    10,000   $      825.80   $       842.96   $    17.16         2.08%
    20,000   $    1,637.55   $     1,669.86   $    32.31         1.97%

The following rates were used in the development of these bills:

Market Price Charge          $      0.06701   per kWh
Market Price Adjustment      $           --   per kWh
Purchased Power Adjustment   $     (0.00225)  per kWh
Miscellaneous Charges        $      0.00066   per kWh
SBC/RPS                      $      0.00116   per kWh
Revenue Tax Rate - Commodity          0.339%
Revenue Tax Rate - Delivery           0.339%

<PAGE>

                             Appendix C Sheet 7 of 8

                    Central Hudson Gas & Electric Corporation
                           Cases 05-E-0934 & 05-G-0935
               Comparison of Present and Proposed Electric Rates

                      Small General Demand Metered Service
                    Service Classification No. 2 - Secondary Customers

<TABLE>
<CAPTION>
Demand kW     Energy kWh     Present Rates    Proposed Rates    Change ($)    Change (%)
----------    ----------     -------------    --------------    ----------    ----------
<S>           <C>            <C>              <C>               <C>           <C>
         7         2,500     $      242.68    $       249.59    $     6.91          2.85%
        10         2,500     $      261.29    $       269.49    $     8.20          3.14%
        17         2,500     $      304.69    $       315.92    $    11.22          3.68%
        14         5,000     $      465.30    $       475.60    $    10.30          2.21%
        20         5,000     $      502.50    $       515.40    $    12.89          2.57%
        33         5,000     $      583.12    $       601.62    $    18.50          3.17%
        29        10,000     $      916.73    $       934.26    $    17.53          1.91%
        40        10,000     $      984.94    $     1,007.21    $    22.28          2.26%
        67        10,000     $    1,152.37    $     1,186.29    $    33.93          2.94%
        57        20,000     $    1,807.19    $     1,838.30    $    31.12          1.72%
        80        20,000     $    1,949.81    $     1,990.85    $    41.04          2.10%
       133        20,000     $    2,278.46    $     2,342.37    $    63.91          2.80%
        90        50,000     $    4,162.31    $     4,212.18    $    49.87          1.20%
       115        50,000     $    4,317.34    $     4,377.99    $    60.66          1.40%
       230        50,000     $    5,030.45    $     5,140.73    $   110.27          2.19%
       175       100,000     $    8,273.55    $     8,367.62    $    94.07          1.14%
       230       100,000     $    8,614.60    $     8,732.40    $   117.80          1.37%
       460       100,000     $   10,040.84    $    10,257.87    $   217.04          2.16%
       350       200,000     $   16,527.03    $    16,711.65    $   184.63          1.12%
       460       200,000     $   17,209.14    $    17,441.23    $   232.09          1.35%
       920       200,000     $   20,061.61    $    20,492.17    $   430.56          2.15%
       520       300,000     $   24,749.50    $    25,022.53    $   273.03          1.10%
       700       300,000     $   25,865.68    $    26,216.37    $   350.69          1.36%
       700       400,000     $   33,033.99    $    33,399.73    $   365.74          1.11%
       920       400,000     $   34,398.21    $    34,858.87    $   460.66          1.34%
       868       500,000     $   41,244.06    $    41,697.33    $   453.28          1.10%
</TABLE>

The following rates were used in the development of these bills:

Market Price Charge          $     0.06701    per kWh
Market Price Adjustment      $          --    per kWh
Purchased Power Adjustment   $    (0.00225)   per kWh
Miscellaneous Charges        $     0.00066    per kWh
SBC/RPS                      $     0.00116    per kWh
Revenue Tax Rate - Commodity         0.339%
Revenue Tax Rate - Delivery          0.339%

<PAGE>

                             Appendix C Sheet 8 of 8

                    Central Hudson Gas & Electric Corporation
                           Cases 05-E-0934 & 05-G-0935
               Comparison of Present and Proposed Electric Rates

                      Small General Demand Metered Service
                Service Classification No. 2 - Primary Customers

<TABLE>
<CAPTION>
Demand kW    Energy kWh      Present Rates    Proposed Rates    Change ($)   Change (%)
---------    ----------      -------------    --------------    ----------   ----------
<S>          <C>             <C>              <C>               <C>          <C>
        7         2,500      $      282.35    $       294.72    $    12.37         4.38%
       10         2,500      $      296.23    $       309.50    $    13.27         4.48%
       17         2,500      $      328.61    $       343.99    $    15.38         4.68%
       14         5,000      $      484.43    $       499.13    $    14.70         3.03%
       20         5,000      $      512.19    $       528.69    $    16.51         3.22%
       33         5,000      $      572.32    $       592.74    $    20.42         3.57%
       29        10,000      $      893.22    $       912.88    $    19.67         2.20%
       40        10,000      $      944.10    $       967.08    $    22.98         2.43%
       67        10,000      $    1,068.99    $     1,100.10    $    31.11         2.91%
       57        20,000      $    1,701.54    $     1,730.54    $    29.00         1.70%
       80        20,000      $    1,807.93    $     1,843.85    $    35.92         1.99%
      133        20,000      $    2,053.09    $     2,104.97    $    51.88         2.53%
       90        50,000      $    3,890.59    $     3,932.23    $    41.64         1.07%
      115        50,000      $    4,006.23    $     4,055.40    $    49.17         1.23%
      230        50,000      $    4,538.18    $     4,621.97    $    83.78         1.85%
      175       100,000      $    7,677.78    $     7,749.52    $    71.74         0.93%
      230       100,000      $    7,932.19    $     8,020.49    $    88.30         1.11%
      460       100,000      $    8,996.10    $     9,153.63    $   157.53         1.75%
      350       200,000      $   15,275.28    $    15,408.74    $   133.45         0.87%
      460       200,000      $   15,784.11    $    15,950.67    $   166.56         1.06%
      920       200,000      $   17,911.92    $    18,216.96    $   305.03         1.70%
      520       300,000      $   22,849.66    $    23,043.32    $   193.66         0.85%
      700       300,000      $   23,682.28    $    23,930.12    $   247.84         1.05%
      700       400,000      $   30,470.29    $    30,727.17    $   256.87         0.84%
      920       400,000      $   31,487.94    $    31,811.04    $   323.10         1.03%
      868       500,000      $   38,035.42    $    38,351.89    $   316.47         0.83%
</TABLE>

The following rates were used in the development of these bills:

Market Price Charge          $     0.06701    per kWh
Market Price Adjustment      $          --    per kWh
Purchased Power Adjustment   $    (0.00225)   per kWh
Miscellaneous Charges        $     0.00066    per kWh
SBC/RPS                      $     0.00116    per kWh
Revenue Tax Rate - Commodity         0.339%
Revenue Tax Rate - Delivery          0.339%

<PAGE>

                             Appendix D, Schedule 1

                    Central Hudson Gas & Electric Corporation
                           Cases 05-E-0934 & 05-G-0935
                              Gas Income Statements
                                     ($000)

<TABLE>
<CAPTION>
                                                                       Rate Years Ending
                                                               --------------------------------
                                                                6/30/07    6/30/08     6/30/09
Line No.                                                          (A)        (B)         (C)
--------                                                       --------   ---------   ---------
<S>                                                            <C>        <C>         <C>
          Operating Revenues

    1        Gas Delivery Revenues - Before Increase           $ 42,041   $  51,457   $  59,008
    2        Rate Increase                                        8,003       6,057          --
    3        Interruptible & Sales to Generators                  1,000       1,000       1,000
    4        Other Operating Revenues                             1,982         914         943
                                                               --------   ---------   ---------
    5           Total Operating Revenues                         53,027      59,428      60,950

    6     Operating Expenses

    7        Labor                                                9,523       9,820      10,101
    8        Research and Development                               299         304         306
    9        Expenses Projected Based on Inflation                3,064       3,131       3,200
   10        Miscellaneous General Expenses                         462         470         479
   11        Transportation - Depreciation                          341         349         356
   12        Fringe Benefits                                      1,369       1,403       1,442
   13        Other Post Employee Benefits (OPEB)                  1,943       1,943       1,943
   14        Pension Plan                                         2,413       2,413       2,413
   15        Environmental                                           64          65          67
   16        Contract Rents                                         187         191         195
   17        Uncollectible Accounts                                 462         531         545
   18        Regulatory Commission Expenses                         380         388         397
   19        Data Processing Expense                                527         539         550
   20        Other Operating Insurance                              214         219         224
   21        Telephone                                              225         230         236
   22        Legal Services                                         576         589         602
   23        Special Services                                       324         331         338
   24        Injuries and Damages                                   448         458         468
   25        Powerful Opportunities Program                         172         199         225
   26        Expenses Allocated to Affiliates                       (87)        (89)        (91)
   27        MGP Remediation Cost Recovery                           --         250         250
   28        Recovery of Net Requlatory Assets                       --       4,274       4,346
   29        Competition Education Program                           53          53          53
   30        Productivity                                           (34)        (34)        (34)
                                                               --------   ---------   ---------
   31        Total Operating Expenses                            22,925      28,026      28,611
                                                               --------   ---------   ---------

          Other Deductions

   32        Property Taxes                                       5,342       5,531       5,727
   33        Revenue Taxes                                        1,022       1,244       1,288
   34        Payroll Taxes                                          680         695         710
   35        Other Taxes                                            173         177         181
   36        Depreciation                                         6,478       6,335       6,192
                                                               --------   ---------   ---------
   37           Total Other Deductions                           13,695      13,981      14,098
                                                               --------   ---------   ---------

   38        State Income Taxes                                     984       1,054       1,110
   39        Federal Income Taxes                                 4,885       5,243       5,475
                                                               --------   ---------   ---------
   40           Total Income Taxes                                5,869       6,296       6,585
                                                               --------   ---------   ---------

   41     Total Operating Revenue Deductions                     42,489      48,304      49,294
                                                               --------   ---------   ---------

   42     Operating Income                                       10,538      11,124      11,657
                                                               ========   =========   =========

   43     Rate Base                                            $149,521   $ 156,889   $ 163,440
                                                               ========   =========   =========

   44     Rate of Return                                           7.05%       7.09%       7.13%
                                                               ========   =========   =========
</TABLE>

<PAGE>

                             Appendix D, Schedule 2

                    Central Hudson Gas & Electric Corporation
                           Cases 05-E-0934 & 05-G-0935
                                  Gas Rate Base

<TABLE>
<CAPTION>
                                                                              Gas
                                                               --------------------------------
                                                                       Rate Years Ending
                                                               --------------------------------
                                                                6/30/07    6/30/08     6/30/09
                                                               ---------  ---------   ---------
<S>                                                            <C>        <C>         <C>
Book Cost of Utility Plant                                     $ 250,779  $ 265,176   $ 279,055
Less: Accumulated Provision for Depreciation and
   Amortization                                                  (94,887)  (100,183)   (105,299)
                                                               ---------  ---------   ---------

Net Plant                                                        155,892    164,993     173,756

Noninterest-Bearing Construction Work in Progress                  9,930     10,207      10,319

Preliminary Survey & Investigation                                     0          0           0

Customer Advances for Undergrounding                                  (2)        (2)         (2)

Deferred Charges                                                   4,382      4,247       3,877

Accumulated Deferred Federal Taxes                               (24,504)   (26,326)    (28,221)

Accumulated Deferred State Taxes                                    (206)      (419)       (638)

Working Capital                                                    6,569      6,729       6,889
                                                               ---------  ---------   ---------

Unadjusted Rate Base                                             152,061    159,429     165,980

Capitalization Adjustment to Rate Base                            (2,540)    (2,540)     (2,540)
                                                               ---------  ---------   ---------

Total                                                          $ 149,521  $ 156,889   $ 163,440
                                                               =========  =========   =========
</TABLE>

<PAGE>

                                   Appendix E

                    Central Hudson Gas & Electric Corporation
                           Cases 05-E-0934 & 05-G-0935
                           Gas Cost of Service Summary

<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
    Rev. Req. for Bundled Functions @ ROR on
    RB = 7.06%                                                                   Residential           Commercial/Industrial
                                                            Total System     Heating      Non-heat      Heating     Non-heat
------------------------------------------------------------------------------------------------------------------------------------
<S>                                           <C>           <C>            <C>           <C>          <C>          <C>
40  Demand-related functions                      L35       $ 19,893,626   $ 8,690,069   $  248,484   $ 8,449,553  $1,316,567
41  Commodity-related functions                 L36-L45     $          0   $         0   $        0   $         0  $        0
42  Customer-related functions                L37 - 46:48   $ 27,433,547   $17,345,324   $3,503,338   $ 4,910,491  $  717,711
------------------------------------------------------------------------------------------------------------------------------------
43  sub-total                                               $ 47,327,173   $26,035,393   $3,751,822   $13,360,044  $2,034,278

44  Rev. Req. for Unbundled Functions
45  Procurement function                           L4       $  1,061,424   $   694,432   $  113,470   $   213,236  $   39,685
46  DS Uncollectibles, Credit & Collections
       function                                    L28      spread vertically within each column to all functions except Procurement
47  Bill Printing, Mailing & Receipt
       function                                    L29      $    500,856   $   313,473   $   58,947   $   110,423  $   17,942
48  Competitive Energy Services function           L30      $    428,882   $   306,292   $   57,597   $    55,878  $    9,079
------------------------------------------------------------------------------------------------------------------------------------
49  sub-total                                               $  1,991,163   $ 1,314,197   $  230,013   $   379,536  $   66,705

50  Total Delivery Service Rev. Req.           L43 + L49    $ 49,318,335   $27,349,590   $3,981,836   $13,739,581  $2,100,983

------------------------------------------------------------------------------------------------------------------------------------
    RY#1 Billing Units
51  GAS Deliveries @ meter, Mcf                               16,535,558     5,460,256      200,465     5,369,003   1,117,222
52  Number of Customers                                           72,813        52,220        9,810         9,218       1,498
------------------------------------------------------------------------------------------------------------------------------------

<CAPTION>
-------------------------------------------------------------------------------------------------------------
    Rev. Req. for Bundled Functions @ ROR on
    RB = 7.06%                                   SC8/9                                     Firm        Firm
                                              Interruptible   SC11-DLM   Intrdprtmntl     SC11 t      SC11 d
-------------------------------------------------------------------------------------------------------------
<S>                                           <C>             <C>        <C>            <C>          <C>
40  Demand-related functions                  $           0   $457,718   $     56,070   $  609,699   $ 65,465
41  Commodity-related functions               $           0   $      0   $          0   $        0   $      0
42  Customer-related functions                $           0   $ 21,025   $    765,042   $  152,885   $ 17,731
-------------------------------------------------------------------------------------------------------------
43  sub-total                                 $           0   $478,743   $    821,112   $  762,585   $ 83,196

44  Rev. Req. for Unbundled Functions
45  Procurement function                      $           0   $     11   $        535   $       33   $     22
46  DS Uncollectibles, Credit & Collections
       function
47  Bill Printing, Mailing & Receipt
       function                               $           0   $     12   $          0   $       36   $     24
48  Competitive Energy Services function      $           0   $      6   $          0   $       18   $     12
-------------------------------------------------------------------------------------------------------------
49  sub-total                                 $           0   $     29   $        535   $       88   $     58

50  Total Delivery Service Rev. Req.          $           0   $478,772   $    821,647   $  762,672   $ 83,254

-------------------------------------------------------------------------------------------------------------
    RY#1 Billing Units

51  GAS Deliveries @ meter, Mcf                   1,802,120    847,692         26,000    1,540,000    172,800
52  Number of Customers                                  61          1              1            3          2
-------------------------------------------------------------------------------------------------------------
</TABLE>

<PAGE>

                             Appendix F Sheet 1 of 6

                    Central Hudson Gas & Electric Corporation
                           Cases 05-E-0934 & 05-G-0935
                             Gas Revenue Allocation
                                Min .5x, Max 1.5x

<TABLE>
<CAPTION>
                                      (1)         (2)      (3)       (4)        (5)          (6)
                                                 Rate                Adj       Adj to      (5)-(1)
                                  Initial Net     of      3.95%      Net    Initial Net
                                    Income      Return   +/- 15%   Income      Income     Difference
                                  -----------   ------   -------   ------   -----------   -----------
<S>                               <C>           <C>      <C>       <C>      <C>           <C>
          Total                   $     5,894    3.95%             $5,623   $     5,894

SC 1 & 12 Residential Heat        $     4,035    4.51%    4.51%
SC 1 & 12 Residential Nonheat     $      (535)  -4.14%    3.36%
-----------------------------------------------------------------------------------------------------
Total SC 1 & 12 Residential       $     3,500    3.42%    3.42%    $3,500   $     3,669   $      169
-----------------------------------------------------------------------------------------------------
SC 2, 6, & 13 Com & Ind Heat      $     1,870    4.62%    4.54%
SC 2, 6, & 13 Com & Ind Nonheat   $       524    8.37%    4.54%
-----------------------------------------------------------------------------------------------------
Total SC 2, 6, & 13               $     2,394    5.12%    4.54%    $2,123   $     2,225   $     (169)
-----------------------------------------------------------------------------------------------------

SC 11 Transmission                $       264   19.51%
SC 11 Distribution                $        37   15.89%
SC 11 DLM                         $       170   15.04%

<CAPTION>
                                                   Excludes Revenue Taxes
                                               ------------------------------
                                      (7)        (8)        (9)        (10)       (11)
                                  (6)/.60125                         (7)+(9)     (10)/(8)
                                      Adj        Base     Base Rev     Total    % Increase
                                    FIT/SIT     Rates     Increase   Increase   Unadjusted
                                  ----------   --------   --------   --------   ----------
<S>                               <C>          <C>        <C>        <C>        <C>
          Total                                $ 39,312   $  8,765   $  8,765     22.30%

SC 1 & 12 Residential Heat
SC 1 & 12 Residential Nonheat
------------------------------------------------------------------------------------------
Total SC 1 & 12 Residential         $  281     $ 24,850   $  5,541   $  5,821     23.43%
------------------------------------------------------------------------------------------
SC 2, 6, & 13 Com & Ind Heat
SC 2, 6, & 13 Com & Ind Nonheat
------------------------------------------------------------------------------------------
Total SC 2, 6, & 13                 $ (281)    $ 14,462   $  3,224   $  2,944     20.36%
------------------------------------------------------------------------------------------

SC 11 Transmission                             $  1,053
SC 11 Distribution                             $    118
SC 11 DLM                                      $    636
</TABLE>

<TABLE>
<CAPTION>
                                     (12)          (13)         (14)          (15)       (16)         (17)
                                                              (8)*(12)      (8)*(13)   (14)+(15)    (10)-(16)
                                  % Increase    % Increase   $ Increase    $ Increase                Revenue
                                  Constrained   Unadjusted   Constrained   Unadjusted    Total      Shortfall
                                  -----------   ----------   -----------   ----------  ---------    ---------
<S>                               <C>           <C>          <C>           <C>         <C>          <C>
                                                             $        --   $    8,765   $   8,765   $      --

SC 1 & 12 Residential Heat
SC 1 & 12 Residential Nonheat
-------------------------------------------------------------------------------------------------------------
Total SC 1 & 12 Residential          0.00%        23.43%     $        --   $    5,821   $   5,821   $      --
-------------------------------------------------------------------------------------------------------------
SC 2, 6, & 13 Com & Ind Heat
SC 2, 6, & 13 Com & Ind Nonheat
-------------------------------------------------------------------------------------------------------------
Total SC 2, 6, & 13                  0.00%        20.36%     $        --   $    2,944   $   2,944   $      --
-------------------------------------------------------------------------------------------------------------

SC 11 Transmission
SC 11 Distribution
SC 11 DLM

<CAPTION>
                                     (18)         (19)        (20)         (21)          (22)            (23)
                                   (16)+(17)    (18)/(8)                 (18)+(20)     (21)/(8)    (19)/(19) System
                                    Revenue      Revenue     Revenue        Adj          Final       Increase as a
                                  $ Increase   % Increase   Adjustment   $ Increase   % Increase      % of System
                                  ----------   ----------   ----------   ----------   ----------    ---------------
<S>                               <C>          <C>          <C>          <C>          <C>           <C>
                                  $    8,765     22.30%                  $    8,765      22.30%         100.00%

SC 1 & 12 Residential Heat
SC 1 & 12 Residential Nonheat
-------------------------------------------------------------------------------------------------------------------
Total SC 1 & 12 Residential       $    5,821     23.43%     $      104   $    5,925      23.84%          66.41%
-------------------------------------------------------------------------------------------------------------------
SC 2, 6, & 13 Com & Ind Heat
SC 2, 6, & 13 Com & Ind Nonheat
-------------------------------------------------------------------------------------------------------------------
Total SC 2, 6, & 13               $    2,944     20.36%     $       53   $    2,997      20.72%          33.59%
-------------------------------------------------------------------------------------------------------------------

SC 11 Transmission
SC 11 Distribution
SC 11 DLM                                                   $     (157)  $     (157)    -24.69%           0.00%
</TABLE>

                      Increase
                      --------
        Avg.                 22.30%
        Min       0.50x      11.15%
        Max       1.50x      33.44%

                                Rate Years 2 & 3

<TABLE>
<CAPTION>
                                                              Rate Year 2                                 Rate Year 3
                                                ----------------------------------------  ------------------------------------------
                                 Increase as a  Base Rev  Adj. for Rev Unbundled to MFCs   Base Rev   Adj. for Rev Unbundled to MFCs
                                  % of System   Increase     Mcf       MFC/Ccf     Total   Increase      MWh       MFC/kWh     Total
                                 -------------  --------  ---------   ---------   ------   --------   ---------   ---------   ------
<S>                              <C>            <C>       <C>         <C>         <C>      <C>        <C>         <C>         <C>
         Total                      100.00%     $  6,877                          $1,532                                      $1,572

SC 1 & 12 Residential Heat                                5,605,780   $ 0.02070   $1,160              5,755,130   $ 0.02070   $1,191
SC 1 & 12 Residential Nonheat                               196,270   $ 0.02070   $   41                192,160   $ 0.02070   $   40
Total SC 1 & 12 Residential          66.41%     $  4,567  5,802,050   $ 0.02070   $1,201              5,947,290   $ 0.02070   $1,231
SC 2, 6, & 13 Com & Ind Heat                              5,553,480   $ 0.00490   $  272              5,744,040   $ 0.00490   $  281
SC 2, 6, & 13 Com & Ind Nonheat                           1,197,446   $ 0.00490   $   59              1,222,856   $ 0.00490   $   60
Total SC 2, 6, & 13                  33.59%     $  2,310  6,750,926   $ 0.00490   $  331              6,966,896   $ 0.00490   $  341
</TABLE>

<PAGE>

                             Appendix F Sheet 2 of 6

                    Central Hudson Gas & Electric Corporation
                           Cases 05-E-0934 & 05-G-0935
                 Summary of Proposed Monthly Gas Delivery Rates

<TABLE>
<CAPTION>
                                                      Current Rates   Rate Year 1   Rate Year 2   Rate Year 3
                                                      -------------   -----------   -----------   -----------
<S>         <C>                       <C>             <C>             <C>           <C>           <C>
S.C. No. 1 & 12
            Billing Block 1           First 2 Ccf     $        7.20   $     14.00   $     14.00   $     14.00
            Billing Block 2 per Ccf   Next 48 Ccf     $      0.4250   $    0.4620   $    0.5284   $    0.5284
            Billing Block 3 per Ccf   Additional      $      0.3028   $    0.2892   $    0.3300   $    0.3300

S.C. No. 2, 6 & 13
            Billing Block 1           First 2 Ccf     $        7.20   $     20.00   $     20.00   $     20.00
            Billing Block 2 per Ccf   Next 98 Ccf     $      0.3307   $    0.3505   $    0.3843   $    0.3843
            Billing Block 3 per Ccf   Next 4900 Ccf   $      0.2041   $    0.2163   $    0.2372   $    0.2372
            Billing Block 4 per Ccf   Additional      $      0.1760   $    0.1869   $    0.2048   $    0.2048

S.C. No. 11 Transmission
            Customer Charge                           $      317.00   $    317.00   $    317.00   $    317.00
            MDQ                                       $        6.46   $      6.46   $      6.46   $      6.46

S.C. No. 11 Distribution
            Customer Charge                           $      317.00   $    317.00   $    317.00   $    317.00
            MDQ                                       $       11.76   $     11.76   $     11.76   $     11.76

S.C. No. 11 DLM
            Customer Charge                           $          --   $    317.00   $    317.00   $    317.00
            MDQ                                       $          --   $      6.79   $      6.79   $      6.79
</TABLE>

<PAGE>

                             Appendix F Sheet 3 of 6

                    Central Hudson Gas & Electric Corporation
                           Cases 05-E-0934 & 05-G-0935
                            Gas Billing Determinants
                               (Excludes Unbilled)

<TABLE>
<CAPTION>
                                                             Rate Year 1   Rate Year 2   Rate Year 3
                                                             -----------   -----------   -----------
<S>                             <C>                          <C>           <C>           <C>
S.C. No. 1 & 12 Res. Heat       Block 1 - Customer Months        626,640       643,344       660,480
                                Block 1 - Mcf - Not Billed       119,680       122,860       126,150
                                Block 2 - Mcf                  2,140,570     2,197,630     2,256,170
                                Block 3 - Mcf                  3,199,990     3,285,290     3,372,810

S.C. No. 1 & 12 Res. Non-Heat   Block 1 - Customer Months        117,720       115,260       112,848
                                Block 1 - Mcf - Not Billed        19,960        19,510        19,130
                                Block 2 - Mcf                    128,490       125,830       123,180
                                Block 3 - Mcf                     52,010        50,930        49,850

S.C. No. 2, 6 & 13 Heat         Block 1 - Customer Months        110,616       114,600       118,716
                                Block 1 - Mcf - Not Billed        17,290        17,880        18,500
                                Block 2 - Mcf                    611,690       632,790       654,600
                                Block 3 - Mcf                  3,728,300     3,856,360     3,988,670
                                Block 4 - Mcf                  1,011,750     1,046,450     1,082,270

S.C. No. 2, 6 & 13 Non-Heat     Block 1 - Customer Months         17,964        18,504        19,068
                                Block 1 - Mcf - Not Billed         2,380         2,490         2,560
                                Block 2 - Mcf                     67,760        70,290        72,940
                                Block 3 - Mcf                    289,700       300,540       311,790
                                Block 4 - Mcf                    757,374       824,126       835,566

S.C. No. 11 Transmission        Customer Months                       36            36            36
                                MDQ                              161,412       161,412       161,412

S.C. No. 11 Distribution        Customer Months                       24            24            24
                                MDQ                                9,444         9,444         9,444

S.C. No. 11 - DLM               Customer Months                       12            12            12
                                MDQ                               69,996        69,996        69,996

Interdepartmental (S.C. No. 2)  Block 4 - Mcf                     26,000        26,000        26,000
</TABLE>

<PAGE>

                             Appendix F Sheet 4 of 6

                    Central Hudson Gas & Electric Corporation
                           Cases 05-E-0934 & 05-G-0935
                 Gas Commodity Related Merchant Function Charges

                                      MFC (A)   MFC (B)   MFC (T)
                        Applicable to
                          S. C. No.    $/ccf     $/ccf     $/ccf
                                      -------   -------   -------
                  MFC-1       1       0.00680   0.01390   0.02070
                  MFC-2       2       0.00213   0.00277   0.00490

Notes:

      1.    Customers taking commodity service from Central Hudson will be
            billed by Central Hudson for MFC(T), which is equal to the sum of
            MFC(A) and MFC(B).

      2.    MFC(A) will include the allocated portion of collection function
            costs and 50% of procurement-related call center function costs,
            plus administrative & general and rate base items associated with
            each of these items. Customers that choose to purchase their
            commodity service from an energy services company (ESCO) that is
            participating in Central Hudson's Purchase of Receivables (POR)
            Program will be billed by Central Hudson for MFC(A) only.

      3.    MFC(B) will include commodity purchasing function costs, allocated
            portions of advertising & promotions function costs and 50% of
            procurement-related call center function costs, plus administrative
            & general and rate base items associated with each of these items.

<PAGE>

                             Appendix F Sheet 5 of 6

                    Central Hudson Gas & Electric Corporation
                           Cases 05-E-0934 & 05-G-0935
              Comparison of Bills Under Present and Proposed Rates

                               P.S.C. No. 12 - Gas
                       Service Classification Nos. 1 & 12

          Monthly         Monthly Bill         Change in Monthly Bill
           Usage          ------------        ------------------------
            Ccf       Present     Proposed      Amount     Increase
          ------------------------------------------------------------
                2   $     9.16   $    16.15   $     6.98        76.20%
                4        11.81        18.87         7.06        59.78%
                6        14.45        21.58         7.13        49.37%
                8        17.09        24.30         7.21        42.18%
               10        19.74        27.02         7.29        36.92%
               15        26.34        33.82         7.48        28.38%
               20        32.95        40.62         7.67        23.26%
               25        39.56        47.42         7.86        19.86%
               30        46.17        54.21         8.05        17.43%
               35        52.78        61.01         8.24        15.61%
               40        59.38        67.81         8.43        14.19%
               50        72.60        81.41         8.81        12.13%
               60        84.56        93.23         8.67        10.25%
               80       108.49       116.87         8.39         7.73%
              100       132.41       140.52         8.11         6.12%
              130       168.29       175.98         7.69         4.57%
              170       216.14       223.27         7.13         3.30%
              200       252.02       258.73         6.71         2.66%
              300       371.64       376.95         5.31         1.43%
             1000     1,208.93     1,204.47        (4.46)       -0.37%

               Typical Annual Heating Customer @ 1100 Ccf Per Year
               ---------------------------------------------------
                    $ 1,454.23   $ 1,546.68   $    92.45         6.36%

          Revenue Tax Factor:     Delivery       0.02612
                                  Commodity      0.00612

          Gas Supply Charge:                  $   0.8798

<PAGE>

                             Appendix F Sheet 6 of 6

                    Central Hudson Gas & Electric Corporation
                           Cases 05-E-0934 & 05-G-0935
              Comparison of Bills Under Present and Proposed Rates

                               P.S.C. No. 12 - Gas
                       Service Classification Nos. 2 & 13

          Monthly          Monthly Bill         Change in Monthly Bill
           Usage           ------------         -----------------------
            Ccf       Present      Proposed      Amount      Increase
          -------------------------------------------------------------
                2   $      9.01   $     21.89   $  12.88        142.86%
               10         18.76         31.80      13.04         69.51%
               30         43.12         56.55      13.44         31.16%
               50         67.48         81.31      13.84         20.50%
              100        128.37        143.21      14.83         11.55%
              150        182.90        198.35      15.44          8.44%
              200        237.43        253.49      16.06          6.76%
              250        291.96        308.63      16.67          5.71%
              300        346.49        363.78      17.29          4.99%
              400        455.55        474.06      18.51          4.06%
              500        564.60        584.35      19.74          3.50%
              600        673.66        694.63      20.97          3.11%
              800        891.78        915.20      23.42          2.63%
             1000      1,109.89      1,135.77      25.88          2.33%
             1500      1,655.18      1,687.19      32.02          1.93%
             2000      2,200.47      2,238.62      38.15          1.73%
             3000      3,291.04      3,341.47      50.43          1.53%
             5000      5,472.19      5,547.17      74.98          1.37%
             7500      8,127.94      8,230.34     102.40          1.26%
            10000     10,783.69     10,913.51     129.81          1.20%
            12000     12,908.30     13,060.05     151.75          1.18%
            14000     15,032.90     15,206.58     173.68          1.16%
            16000     17,157.50     17,353.12     195.62          1.14%
            20000     21,406.71     21,646.19     239.49          1.12%

                   Annual Heating Customer @ 5300 Ccf Per Year
                   -------------------------------------------
                    $  5,937.16   $  6,161.32   $ 224.16          3.78%

          Revenue Tax Factor:     Delivery       0.00612
                                  Commodity      0.00612

          Gas Supply Charge:                    $ 0.8798

<PAGE>

                             Appendix G, Schedule 1
                    Central Hudson Gas & Electric Corporation
                           Cases 05-E-0934 & 05-G-0935
       Electric Deferred Items For Offset - Projected as of June 30, 2006
                                     ($000)

<TABLE>
<CAPTION>
                                                                          Electric Department
                                                                   --------------------------------
                                                                    Deferred   Deferred
                                                                     Charge      Tax        Net
                                                                   --------------------------------
<S>                                                                <C>         <C>       <C>
                              Deferred Debits

Pension Costs - Under/(Over) Collection                             $ 29,616   ($11,809)  $ 17,807
OPEB Costs - Excluding Medicare Subsidy - Under/(Over) Collection     11,113     (4,433)     6,680
Pension Reserve Carrying Charges                                       7,172     (2,860)     4,312
Stray Voltage Testing Costs                                            2,050       (818)     1,232
Carrying Charges on Stray Voltage Testing Costs                           65        (24)        41
NYS Income Taxes (00-M-1556)                                             260      3,678      3,938
Research & Development Costs                                             369       (149)       220
                                                                   --------------------------------
                      Total Deferred Debits                         $ 50,645   ($16,415)  $ 34,230
                                                                   --------------------------------

                             Deferred Credits

Proceeds from Sale of Clean Air Act Allowances                     ($ 13,576)   $ 5,414  ($  8,162)
Benefit Fund Principle & Carrying Charges (1)                        (12,450)     4,450     (8,000)
Variable Rate Notes                                                   (3,666)     1,461     (2,205)
NMP-2 Settlement Agreement Costs                                      (1,930)       775     (1,155)
Reliability Service Quality Penalty                                   (1,138)       454       (684)
OPEB Reserve Carrying Charges                                         (1,220)       487       (733)
Carrying Charges - Deferred NYS Taxes                                 (1,014)       404       (610)
Carrying Charges - CAA Allowance Proceeds                               (724)       288       (436)
Carrying Charge on NMP-2 Settlement Agreement Costs                     (490)       201       (289)
NYS Deferred Tax - Restate 8.50% & 8.00% Balances to 7.50%                 0       (172)      (172)
Powerful Opportunity Costs                                                 0          0          0
                                                                   --------------------------------
Total Deferred Credits                                             ($ 36,208)   $13,762  ($ 22,446)
                                                                   --------------------------------

Net Deferred Debit                                                    14,437     (2,653)    11,784

Amount Recovered from Excess Depreciation Reserve                    (14,437)     2,653    (11,784)
                                                                   --------------------------------

Net Remaining Deferred Balance                                      $      0    $     0   $      0
                                                                   ================================
</TABLE>

(1)   Includes Shared Earnings deferred for Customer benefit of $ 22.3 million

<PAGE>

                             Appendix G, Schedule 2
                    Central Hudson Gas & Electric Corporation
                           Cases 05-E-0934 & 05-G-0935
          Gas Deferred Items For Offset - Projected as of June 30, 2006
                                     ($000)

<TABLE>
<CAPTION>
                                                                                           Gas Department
                                                                                ----------------------------------
                                                                                 Deferred    Deferred
                                                                                  Charge        Tax         Net
                                                                                ----------------------------------
<S>                                                                             <C>          <C>         <C>
                             Deferred Debits

Pension Costs - Under/(Over) Collection                                       a  $ 19,206    ($ 7,658)    $11,548
Pension Reserve Carrying Charges                                              b     6,790      (2,708)      4,082
OPEB Costs - Excluding Medicare Subsidy - Under/(Over) Collection             a     6,179      (2,463)      3,716
Gas Earnings Restoration                                                      b     1,272        (508)        764
NYS Income Taxes (00-M-1556)                                                  b        87         426         513
                                                                                ----------------------------------
                          Total Deferred Debits                                  $ 33,534    ($12,911)    $20,623
                                                                                ----------------------------------

                             Deferred Credits

Gas Shared Earnings (Rate Years 1 through 3)                                  b    (1,486)        592        (894)
Variable Rate Notes                                                           b    (1,149)        460        (689)
OPEB Reserve Carrying Charges                                                 b      (502)        204        (298)
Research & Development Costs                                                  b       (11)          6          (5)
Carrying Charges - Deferred NYS Taxes                                         b       (96)         39         (57)
NYS Deferred Tax - Restate 8.50% & 8.00% Balances to 7.50%                              0        (150)       (150)
Powerful Opportunity Costs                                                    b         0           0           0
                                                                                ----------------------------------
Total Deferred Credits                                                          ($  3,244)    $ 1,151    ($ 2,093)
                                                                                ----------------------------------

Net Deferred Debit                                                               $ 30,290    ($11,760)    $18,530
                                                                                ==================================

Recovery of Gas Net Regulatory Asset

Net Deferred Items Not Subject to Interest                                    a  $ 25,387    ($10,123)    $15,264
Net Deferred Items Subject to Interest                                        b     4,903      (1,637)      3,266
                                                                                ---------    --------    --------
                                                                                 $ 30,290    ($11,760)    $18,530
                                                                                ---------    --------    --------

The non-interest bearing components ("a" references) of the gas net
regulatory asset balance are amortized on a straight-line basis over 7
years beginning July 1, 2007, the start of RY2.                                  $ 25,387   / 7 years =   $ 3,627

The interest bearing components ("b" references) of the gas net regulatory
asset balance accrue interest during RY1 at the carrying charge rate. The
balance at July 1, 2007, which includes interest accrued in RY1, is
amortized over 7 years, on a levelized basis recognizing accrued interest                     over 7
on the unamortized balance at the carrying charge rate, beginning July 1,                   years plus
2007, the start of RY2 (1).                                                      $  4,903    interest =       719
                                                                                                          -------

                                                                                                          $ 4,346
Total Annual Amortization of Net Gas Regulatory Asset                                                     =======

</TABLE>

(1)   The amount for RY2 shown on Appendix D, Schedule 1, Line 28 has been
      moderated to eliminate the need for a RY3 gas rate change.

<PAGE>

                             Appendix G, Schedule 3
                    Central Hudson Gas & Electric Corporation
                           Cases 05-E-0934 & 05-G-0935
                       Deprecation Reserve Rate Moderator
                                     ($000)

<TABLE>
<S>                                                                  <C>          <C>
Settlement Excess Electric Depreciation Reserve                                   $ 52,500

Recovery of Net Electric Regulatory Assets
   Net Regulatory Assets Remaining After Offset                      $   14,437
   Deferred Taxes on Above                                               (2,653)    11,784
                                                                     ----------   --------

Remaining Balance After Offset                                                      40,716

Amounts Applied to Phase-in Electric Rate Increase

   Rate Year 1                                                          (22,887)
   Rate Year 2                                                          (11,840)
                                                                     ----------
                                                                        (34,727)
                                                                        0.60125    (20,880)
                                                                     ----------

Remaining Balance After Offset & Phase-In                                         $ 19,837
                                                                                  ========

Pre-tax Equivalent                                                                $ 32,992
                                                                                  ========
</TABLE>

<PAGE>

                             Appendix H, Schedule 1

                    Central Hudson Gas & Electric Corporation
                           Cases 05-E-0934 & 05-G-0935
                  Capital Structure and Allowed Rate of Return
                                     ($000)

<TABLE>
<CAPTION>
                                                                            Pre-Tax
                                                                Weighted   Weighted
Rate Year 1:                        Amount      Ratio    Cost     Cost       Cost
------------                      ----------   ------   -----   --------   --------
<S>                               <C>          <C>      <C>     <C>        <C>
Long-Term Debt                    $  367,579     51.2%   4.99%      2.55%      2.55%
Customer Deposits                      6,359      0.9%   3.00%      0.03%      0.03%
Preferred Stock                       21,030      2.9%   5.04%      0.15%      0.25%
Common Equity                        323,094     45.0%   9.60%      4.32%      7.18%
                                  ----------   ------   -----   --------   --------
                                  $  718,062    100.0%              7.05%     10.01%
                                  ==========   ======           ========   ========
</TABLE>

<TABLE>
<CAPTION>
                                                                            Pre-Tax
                                                                Weighted   Weighted
Rate Year 2:                        Amount      Ratio    Cost     Cost       Cost
------------                      ----------   ------   -----   --------   --------
<S>                               <C>          <C>      <C>     <C>        <C>
Long-Term Debt                    $  382,837     51.3%   5.07%      2.60%      2.60%
Customer Deposits                      6,359      0.9%   3.00%      0.03%      0.03%
Preferred Stock                       21,030      2.8%   5.04%      0.14%      0.24%
Common Equity                        335,686     45.0%   9.60%      4.32%      7.19%
                                  ----------   ------   -----   --------   --------
                                  $  745,912    100.0%              7.09%     10.05%
                                  ==========   ======           ========   ========
</TABLE>

<TABLE>
<CAPTION>
                                                                            Pre-Tax
                                                                Weighted   Weighted
Rate Year 3:                        Amount      Ratio    Cost     Cost       Cost
------------                      ----------   ------   -----   --------   --------
<S>                               <C>          <C>      <C>     <C>        <C>
Long-Term Debt                    $  411,042     51.6%   5.15%      2.66%      2.66%
Customer Deposits                      6,359      0.8%   3.00%      0.02%      0.02%
Preferred Stock                       21,030      2.6%   5.04%      0.13%      0.22%
Common Equity                        358,658     45.0%   9.60%      4.32%      7.18%
                                  ----------   ------   -----   --------   --------
                                  $  797,089    100.0%              7.13%     10.09%
                                  ==========   ======           ========   ========
</TABLE>

<PAGE>

                             Appendix H, Schedule 2

                    Central Hudson Gas & Electric Corporation
                           Cases 05-E-0934 & 05-G-0935
                      Electric and Gas Basis Point Values

                                                       Electric
                                          ---------------------------------
Basis Point Values:                          RY1         RY2         RY2
-------------------                       ---------   ---------   ---------

Rate Base ($000)                          $ 544,007   $ 578,065   $ 615,375

x Equity Ratio                                   45%         45%         45%
                                          ---------   ---------   ---------

Equity component of Rate Base ($000)      $ 244,803   $ 260,129   $ 276,919

x 1 BP                                         0.01%       0.01%       0.01%
                                          ---------   ---------   ---------

After-tax value of 1 BP - whole dollars   $  24,500   $  26,000   $  27,700
                                          =========   =========   =========

Pre-tax value of 1 BP - whole dollars     $  40,700   $  43,200   $  46,100
                                          =========   =========   =========

                                                         Gas
                                          ---------------------------------
Basis Point Values:                          RY1         RY2         RY2
-------------------                       ---------   ---------   ---------

Rate Base ($000)                          $ 149,521   $ 156,889   $ 163,440

x Equity Ratio                                   45%         45%         45%
                                          ---------   ---------   ---------

Equity component of Rate Base ($000)      $  67,284   $  70,600   $  73,548

x 1 BP                                         0.01%       0.01%       0.01%
                                          ---------   ---------   ---------

After-tax value of 1 BP - whole dollars   $   6,700   $   7,100   $   7,400
                                          =========   =========   =========

Pre-tax value of 1 BP - whole dollars     $  11,100   $  11,800   $  12,300
                                          =========   =========   =========

<PAGE>

                      Appendix H, Schedule 3, Sheet 1 of 3

                   CENTRAL HUDSON GAS & ELECTRIC CORPORATION
                          Cases 05-E-0934 & 05-G-0935
                LONG TERM DEBT - AVERAGE CAPITALIZATION AND COST
                   FOR THE TWELVE MONTHS ENDING JUNE 30, 2007
                                     ($000)

<TABLE>
<CAPTION>
                                                                                                          Average
                                                                 Principal                                Amount       Interest
                                                                  Amount       Charges                  Outstanding    Expense
                                     Maturity        Interest   Outstanding     During       Months       During        During
                                       Date           Rate %     6/30/2006    Rate Year   Outstanding    Rate Year    Rate Year
                                ------------------   --------   -----------   ---------   -----------   -----------   ---------
                                        (1)            (2)          (3)          (4)          (5)           (6)          (7)
<S>                             <C>                  <C>        <C>           <C>         <C>           <C>           <C>
Long Term Debt
   Outstanding Issues
      NYSERDA Series A              August 1, 2027     5.45       33,400            --         12            33,400       1,820
      NYSERDA Var Rate              August 1, 2028     3.10       41,150            --         12            41,150       1,276
      NYSERDA Var Rate              August 1, 2028     3.02       41,000            --         12            41,000       1,238
      Polution Control Note       December 1, 2028     3.00       16,700            --         12            16,700         501
      NYSERDA Var Rate                July 1, 2034     3.38       33,700            --         12            33,700       1,139
                                    March 28, 2007     5.87       33,000       (33,000)         9            24,750       1,453
                                  January 15, 2009     6.00       20,000            --         12            20,000       1,200
                                September 23, 2010     4.33       24,000            --         12            24,000       1,039
                                    March 28, 2012     6.64       36,000            --         12            36,000       2,390
                                 February 27, 2014     4.73        7,000            --         12             7,000         331
                                  November 5, 2014     4.80        7,000            --         12             7,000         336
                                  December 1, 2035     5.84       24,000            --         12            24,000       1,402
                                   October 1, 2016     6.25           --        11,169          9             8,377         524
                                  February 1, 2017     6.25           --        39,000          5            16,250       1,016
                                  November 4, 2019     5.05       27,000            --         12            27,000       1,364

Average Long Term Debt Outstanding                                                                      $   360,327
                                                                                                        ===========

Interest Charges for the Rate Year                                                                                    $  17,028
                                                                                                                      ---------
Plus: Amortization of Debt Discount and Expense                                                                             973
Less: Amortization of Premium on Debt                                                                                         3

Total Cost of Debt
   Amount                                                                                                             $  17,998
                                                                                                                      =========

   % of Average Long Term Debt Outstanding                                                                                 4.99%
                                                                                                                      =========
</TABLE>

<PAGE>

                      Appendix H, Schedule 3, Sheet 2 of 3

                   CENTRAL HUDSON GAS & ELECTRIC CORPORATION
                          Cases 05-E-0934 & 05-G-0935
                LONG TERM DEBT - AVERAGE CAPITALIZATION AND COST
                   FOR THE TWELVE MONTHS ENDING JUNE 30, 2008
                                     ($000)

<TABLE>
<CAPTION>
                                                                                                          Average
                                                                 Principal                                Amount      Interest
                                                                  Amount       Charges                  Outstanding    Expense
                                     Maturity        Interest   Outstanding     During       Months        During      During
                                       Date           Rate %     6/30/2007    Rate Year   Outstanding    Rate Year    Rate Year
                                ------------------   --------   -----------   ---------   -----------   -----------   ---------
                                        (1)            (2)          (3)          (4)          (5)           (6)          (7)
<S>                             <C>                  <C>        <C>           <C>         <C>           <C>           <C>
Long Term Debt
   Outstanding Issues
      NYSERDA Series A              August 1, 2027     5.45        33,400          --         12             33,400       1,820
      NYSERDA Var Rate              August 1, 2028     3.10        41,150          --         12             41,150       1,276
      NYSERDA Var Rate              August 1, 2028     3.02        41,000          --         12             41,000       1,238
      Polution Control Note       December 1, 2028     3.00        16,700          --         12             16,700         501
      NYSERDA Var Rate                July 1, 2034     3.38        33,700          --         12             33,700       1,139
                                  January 15, 2009     6.00        20,000          --         12             20,000       1.200
                                September 23, 2010     4.33        24,000          --         12             24,000       1,039
                                    March 28, 2012     6.64        36,000          --         12             36,000       2,390
                                 February 27, 2014     4.73         7,000          --         12              7,000         331
                                  November 5, 2014     4.80         7,000          --         12              7,000         336
                                  December 1, 2035     5.84        24,000          --         12             24,000       1,402
                                   October 1, 2016     6.25        11,169          --         12             11,169         698
                                  February 1, 2017     6.25        39,000          --         12             39,000       2,438
                                   January 1, 2018     6.25            --      28,515          6             14,258         891
                                  November 4, 2019     5.05        27,000          --         12             27,000       1,364

Average Long Term Debt Outstanding                                                                      $   375,377
                                                                                                        ===========

Interest Charges for the Rate Year                                                                                    $  18,063
                                                                                                                      ---------

Plus: Amortization of Debt Discount and Expense                                                                             959
Less: Amortization of Premium on Debt                                                                                         3

Total Cost of Debt
   Amount                                                                                                             $  19,019
                                                                                                                      =========

   % of Average Long Term Debt Outstanding                                                                                 5.07%
                                                                                                                      =========
</TABLE>

<PAGE>

                      Appendix H, Schedule 3, Sheet 3 of 3

                   CENTRAL HUDSON GAS & ELECTRIC CORPORATION
                          Cases 05-E-0934 & 05-G-0935
                LONG TERM DEBT - AVERAGE CAPITALIZATION AND COST
                   FOR THE TWELVE MONTHS ENDING JUNE 30, 2009
                                     ($000)

<TABLE>
<CAPTION>
                                                                                                          Average
                                                                 Principal                                Amount      Interest
                                                                  Amount       Charges                  Outstanding    Expense
                                     Maturity        Interest   Outstanding    During        Months       During        During
                                       Date           Rate %     6/30/2008    Rate Year   Outstanding    Rate Year    Rate Year
                                ------------------   --------   -----------   ---------   -----------   -----------   ---------
                                       (1)              (2)         (3)          (4)          (5)           (6)          (7)
<S>                             <C>                  <C>        <C>           <C>         <C>           <C>           <C>
Long Term Debt
   Outstanding Issues
      NYSERDA Series A              August 1, 2027     5.45        33,400            --       12             33,400       1,820
      NYSERDA Var Rate              August 1, 2028     3.10        41,150            --       12             41,150       1,276
      NYSERDA Var Rate              August 1, 2028     3.02        41,000            --       12             41,000       1,238
      Polution Control Note       December 1, 2028     3.00        16,700            --       12             16,700         501
      NYSERDA Var Rate                July 1, 2034     3.38        33,700            --       12             33,700       1,139
                                  January 15, 2009     6.00        20,000       (20,000)       7             10,833         650
                                September 23, 2010     4.33        24,000            --       12             24,000       1,039
                                    March 28, 2012     6.64        36,000            --       12             36,000       2,390
                                 February 27, 2014     4.73         7,000            --       12              7,000         331
                                  November 5, 2014     4.80         7,000            --       12              7,000         336
                                  December 1, 2035     5.84        24,000            --       12             24,000       1,402
                                   October 1, 2016     6.25        11,169                     12             11,169         698
                                  February 1, 2017     6.25        39,000            --       12             39,000       2,438
                                   January 1, 2018     6.25        28,515            --       12             28,515       1,782
                                      July 1, 2018     6.25        14,000            --       12             14,000         875
                                     April 1, 2019     6.25            --        34,380        3              8,595         537
                                  November 4, 2019     5.05        27,000            --       12             27,000       1,364

Average Long Term Debt Outstanding                                                                      $   403,062
                                                                                                        ===========

Interest Charges for the Rate Year                                                                                    $  19,816
                                                                                                                      ---------

Plus: Amortization of Debt Discount and Expense                                                                             944
Less: Amortization of Premium on Debt                                                                                         3

Total Cost of Debt
   Amount                                                                                                             $  20,757
                                                                                                                      =========

   % of Average Long Term Debt Outstanding                                                                                 5.15%
                                                                                                                      =========
</TABLE>

<PAGE>

                             Appendix I, Schedule 1

                    Central Hudson Gas & Electric Corporation
                           Cases 05-E-0934 & 05-G-0935
                                 Deferral Items
                                     ($000)

<TABLE>
<CAPTION>
                                                ELECTRIC OPERATIONS            GAS OPERATIONS
                                            ---------------------------   -------------------------
Rate Allowance Items:              Method     RY1       RY2       RY3       RY1      RY2      RY3
---------------------              ------   -------   -------   -------   -------   -----   -------
<S>                                <C>      <C>       <C>       <C>       <C>       <C>     <C>
Asbestos Litigation                   B     $     0   $     0   $     0   $     0       0   $     0

Competition Education Program         C     $   298   $   298   $   298   $    53      53   $    53

Gas Balancing Software                B     $     0   $     0   $     0   $     0       0   $     0

MGP Remediation                       A     $     0   $ 1,400   $ 1,400   $     0     250   $   250

OPEB                                  A     $ 8,382   $ 8,382   $ 8,382   $ 1,943    1943   $ 1,943

Pension Plan                          A     $10,568   $10,568   $10,568   $ 2,413    2413   $ 2,413

Powerful Opportunities Program        B     $   976   $ 1,125   $ 1,275   $   172     199   $   225

Property Taxes                        D     $19,758   $20,460   $21,183   $ 5,342    5531   $ 5,727

Research & Development                B     $ 1,846   $ 1,857   $ 1,860   $   299     304   $   306

Stray Voltage Testing                 B     $ 2,200   $ 2,250   $ 2,300       n/a     n/a       n/a

Real-Time Gas Meters 04-G-0463        A         n/a       n/a       n/a   $     0   $   0   $     0
</TABLE>

Capital & Expense Expenditure Targets (cumulative totals through Rate Year 3):

Category                         Type                 Target    Method
--------                         ----                --------   ------
  Electric                       Cap                 $158,078      C
  Gas                            Cap                 $ 27,495      C
  Common                         Cap                 $ 21,693      C
  Steel/Cast Iron Replacement    Cap                 $ 15,750      C
  Transmission ROW Maintenance   Exp                 $  6,723      C
  East Fishkill Substation       Cap & Exp                         A

Cost of Capital:

  Variable Rate Debt Interest Rate (all rate years):   Target   Method
                                                       ------   ------
      $41.150 Million Issue                              3.10%     B
      $41.000 Million Issue                              3.02%     B
      $33.700 Million Issue                              3.38%     B

Method of Deferral:

  A - Deferral of costs over/under rate allowance, no limitation

  B - Deferral of costs over/under rate allowance subject to limitation

  C - Deferral of costs less than rate allowance

  D - Shared deferral of costs over/under rate allowance subject to limitation

<PAGE>

                             Appendix I, Schedule 2

                    Central Hudson Gas & Electric Corporation
                           Cases 05-E-0934 & 05-G-0935
                            Revenue Matching Factors

<TABLE>
<CAPTION>
                                              Rate Year #1   Rate Year #2   Rate Year #3
                                              ------------   ------------   ------------
<S>                                           <C>            <C>            <C>
ELECTRIC:

  Research & Development:

    Rate Allowance ($000)                     $      1,846   $      1,857   $      1,860
    SC 1, 2, 3, 5, 6, 8, 9 & 13 Sales (mWh)      5,756,150      5,870,650      5,966,350
    Revenue Matching Factor - $/kWh           $   0.000321   $   0.000316   $   0.000312
                                              ============   ============   ============

  Pension Plan:

    Rate Allowance ($000)                     $     10,568   $     10,568   $     10,568
    SC 1, 2, 3, 5, 6, 8, 9 & 13 Sales (mWh)      5,756,150      5,870,650      5,966,350
    Revenue Matching Factor - $/kWh           $   0.001836   $   0.001800   $   0.001771
                                              ============   ============   ============

  OPEB's:

    Rate Allowance ($000)                     $      8,382   $      8,382   $      8,382
    SC 1, 2, 3, 5, 6, 8, 9 & 13 Sales (mWh)      5,756,150      5,870,650      5,966,350
    Revenue Matching Factor - $/kWh           $   0.001456   $   0.001428   $   0.001405
                                              ============   ============   ============

GAS:

  Research & Development:

    Rate Allowance ($000)                     $        299   $        304   $        306
    SC 1, 2, 6, 12 & 13 Sales (Mcf)             12,146,946     12,553,010     12,914,218
    Revenue Matching Factor - $/Mcf           $   0.024615   $   0.024217   $   0.023695
                                              ============   ============   ============

  Pension Plan:

    Rate Allowance ($000)                     $      2,413   $      2,413   $      2,413
    SC 1, 2, 6, 12 & 13 Sales (Mcf)             12,146,946     12,553,010     12,914,218
    Revenue Matching Factor - $/Mcf           $   0.198651   $   0.192225   $   0.186848
                                              ============   ============   ============

  OPEB's:

    Rate Allowance ($000)                     $      1,943   $      1,943   $      1,943
    SC 1, 2, 6, 12 & 13 Sales (Mcf)             12,146,946     12,553,010     12,914,218
    Revenue Matching Factor - $/Mcf           $   0.159958   $   0.154784   $   0.150454
                                              ============   ============   ============
</TABLE>

<PAGE>

                             Appendix J Sheet 1 of 2

                    Central Hudson Gas & Electric Corporation
                           Cases 05-E-0934 & 05-G-0935
                               DEPRECIATION RATES

<TABLE>
<CAPTION>
   PSC                                                                 Average              Annual                     Allocation
  ACCT                                                                 Service      Net     Deprec      Survivor       of Excess
   NO                             PLANT ACCOUNT                          Life     Salvage    Rate         Curve         Reserve
---------   -------------------------------------------------------    -------    -------   ------    -------------   -----------
<S>         <C>                                                        <C>        <C>       <C>       <C>             <C>
                           ELECTRIC PLANT IN SERVICE

             HYDRO PLANT

  331.00        STRUCTURES AND IMPROVEMENT                               60        (50)      2.50          R3             (59,000)
  332.00        RESERVOIRS, DAMS AND WATERWAYS                           75        (60)      2.13          L5            (230,700)
  333.00        TURBINES AND GENERATORS                                  60        (60)      2.67          R4            (290,000)
  334.10        ACCESSORY ELECTRIC EQUIPMENT                             55        (60)      2.91         R1.5             40,400
  335.00        MISCELLANEOUS POWER PLANT EQUIPMENT                      40        (40)      3.50         S2.5            (50,900)

             OTHER PRODUCTION PLANT

  341.00        STRUCTURES AND IMPROVEMENTS                              27         (5)      3.89          R5             (62,300)
  342.00        FUEL HOLDERS, PRODUCERS & ACCESSORIES                    27         (5)      3.89          R5            (102,700)
  343.00        PRIME MOVERS                                             27         (5)      3.89          R5            (361,500)
  344.00        GENERATORS                                               27         (5)      3.89          R5            (198,200)
  345.00        ACCESSORY ELECTRIC EQUIPMENT                             27         (5)      3.89          R5              92,200
  346.00        MISCELLANEOUS POWER PLANT EQUIPMENT                      27         (5)      3.89          R5              (1,100)

             TRANSMISSION PLANT

  350.11        LAND AND LAND RIGHTS-LINES                               85         10       1.06          R4             (68,000)
  352.00        STRUCTURES AND IMPROVEMENTS                              65        (40)      2.15          R3             145,000
353.11-20       STATION EQUIPMENT-IN USE                                 55        (20)      2.18          R1          (7,919,600)
  353.12        SUPERVISORY EQUIPMENT-IN USE                             28        (10)      3.93          S1            (775,300)
  354.00        TOWERS AND FIXTURES                                      65        (30)      2.00          R3            (490,400)
  355.00        POLES AND FIXTURES                                       55        (50)      2.73          R3           1,049,200
  355.15        POLES AND FIXTURES-345KV LINE                            55        (50)      2.73          R3             353,500
  356.10        OVERHEAD CONDUCTORS AND DEVICES                          60        (25)      2.08          R2            (526,100)
  356.15        OVERHEAD CONDUCTORS AND DEVICES-345KV LINE               60        (35)      2.25          R2             (81,300)
  356.20        CLEARING                                                 60        (35)      2.25          R2             (33,100)
  356.25        CLEARING-345KV LINE                                      60        (35)      2.25          R2              (9,500)
  357.00        UNDERGROUND CONDUIT                                      40         (5)      2.63         L0.5             (7,400)
  358.00        UNDERGROUND CONDUCTORS AND DEVICES                       40        (20)      3.00          R3          (1,094,500)

             DISTRIBUTION PLANT

  360.11        LAND AND LAND RIGHTS-OVERHEAD LINES                      60         10       1.50          S4             (39,900)
  360.22        LAND AND LAND RIGHTS-UNDERGROUND                         60         10       1.50          S4                (200)
  361.00        STRUCTURES AND IMPROVEMENTS                              80        (25)      1.56          R3            (108,400)
362.11-20       STATION EQUIPMENT-IN USE                                 52        (20)      2.31         R1.5            397,000
  362.12        SUPERVISORY EQUIPMENT-IN USE                             30        (10)      3.67          R2            (437,400)
  364.00        POLES, TOWERS AND FIXTURES                               55        (25)      2.27          O1         (11,591,300)
  365.00        OVERHEAD CONDUCTORS AND DEVICES                          60        (30)      2.17          R1          (9,817,300)
  366.00        UNDERGROUND CONDUIT                                      65        (25)      1.92          R3             (10,600)
  367.00        UNDERGROUND CONDUCTOR AND DEVICES                        55        (10)      2.00         R2.5         (2,330,500)
  368.00        TRANSFORMERS                                             43        (10)      2.56          L1          (6,657,700)
  369.10        SERVICES OVERHEAD                                        52        (75)      3.37         R1.5         (5,497,100)
  369.20        SERVICES UNDERGROUND                                     52        (25)      2.40         R1.5           (517,600)
  370.00        METERS                                                   32          0       3.13         R1.5           (589,000)
  371.00        INSTALLATIONS ON CUSTOMER PREMISES                       20        (15)      5.75         R0.5           (878,500)
  372.00        LEASED PROPERTY ON CUSTOMER PREMISES                     11          0       9.09          L2            (456,000)
  373.00        STREET LIGHTING                                          30        (25)      4.17          L0          (3,136,000)
  390.00        STRUCTURES AND IMPROVEMENTS                              40        (30)      3.25         R1.5           (148,200)
                                                                                                                      -----------
                                                                                                                      (52,500,000)
                                                                                                                      ===========
</TABLE>

<PAGE>

                             Appendix J Sheet 2 of 2

                    Central Hudson Gas & Electric Corporation
                           Cases 05-E-0934 & 05-G-0935
                               DEPRECIATION RATES

<TABLE>
<CAPTION>
   PSC                                                                 Average              Annual                    Allocation
  ACCT                                                                 Service      Net     Deprec       Survivor     of Excess
   NO                             PLANT ACCOUNT                          Life     Salvage    Rate         Curve         Reserve
---------    ------------------------------------------------------    -------    -------   ------    -------------   ----------
<S>          <C>                                                       <C>        <C>       <C>       <C>             <C>
                              GAS PLANT IN SERVICE

             MANUFACTURING GAS PLANT - PROPANE

  305.00        STRUCTURES AND IMPROVEMENTS                              75        (10)      1.47     Undetermined
  311.00        LIQUIFIED PETROLEUM GAS EQUIPMENT                        60        (45)      2.42     Undetermined
  320.10        OTHER EQUIPMENT                                          25          0       4.00          S3

             TRANSMISSION PLANT

  365.11        LAND                                                      0          0         --
  365.20        LAND RIGHTS                                              70          0       1.43          S4
  365.50        LAND RIGHTS-IROQUOIS                                     70          0       1.43          S4
  366.20        STRUCTURES AND IMPROVEMENTS                              45        (40)      3.11          R3
  366.50        STRUCTURES AND IMPROVEMENTS-REG STATION IROQUOIS         45        (40)      3.11          R3
  367.00        MAINS                                                    68        (40)      2.06     Undetermined
  367.50        MAINS - IROQUOIS                                         68        (40)      2.06     Undetermined
  369.11        REGULATING STATION EQUIPMENT                             35        (30)      3.71     Undetermined
  369.12        REGULATING STATION EQUIPMENT-SUPERVISORY                 18        (20)      6.67         S0.5
  369.51        REGULATING STATION EQUIPMENT-IROQUOIS                    35        (30)      3.71     Undetermined
  369.52        REGULATING STATION EQUIPMENT-SUPERVISORY IROQUOIS        18        (20)      6.67         S0.5

             DISTRIBUTION PLANT

  374.11        LAND AND LAND RIGHTS-MAINS                               70          0       1.43          R3
  375.00        STRUCTURES AND IMPROVEMENTS                              60        (30)      2.17     Undetermined
  376.00        MAINS                                                    85        (60)      1.88          R3
  378.11        REGULATING STATION EQUIPMENT                             35        (35)      3.86     Undetermined
  378.12        REGULATING STATION EQUIPMENT-SUPERVISORY                 30        (15)      3.83     Undetermined
  380.00        SERVICES                                                 70        (60)      2.29          R2
  381.00        METERS                                                   32        (10)      3.44         R1.5
  382.00        METER INSTALLATIONS                                      40        (15)      2.88     Undetermined
  383.00        HOUSE REGULATORS                                         55          0       1.82     Undetermined
  384.00        HOUSE REGULATOR INSTALLATION                             45        (20)      2.67          L5
  385.00        INDUSTRIAL REGULATING STATION EQUIPMENT                  55        (30)      2.36     Undetermined
  385.10        INDUSTRIAL REGULATING STATION REMOTE METERING            55        (30)      2.36     Undetermined

                            COMMON PLANT IN SERVICE

  390.00        STRUCTURES AND IMPROVEMENTS                              50        (50)      3.00          L0
  390.10        STRUCTURES AND IMPROVEMENTS-LEASED PROPERTY              50        (50)      3.00          L0
  391.11        OFFICE EQUIPMENT-EDP-GENERAL                              8          0      12.50          L3
  391.12        OFFICE EQUIPMENT-EDP-SYSTEM OPERATION                    12          0       8.33          L2
  391.21        OFFICE EQUIPMENT-DATA HANDLING                           20          0       5.00          L0
  391.22        OFFICE FURNITURE AND EQUIPMENT-OTHER                     20          0       5.00          L0
  392.10        TRANSPORTATION EQUIPMENT                                  8         10      11.25          L3
  392.20        TRANSPORTATION EQUIPMENT-GAS                              8         10      11.25          L3
  392.40        TRANSPORTATION EQUIPMENT-COMMON                           8         10      11.25          L3
  393.00        STORES EQUIPMENT                                         35          0       2.86          L2
  393.20        STORES EQUIPMENT - FORKLIFTS                             35          0       2.86          L2
  394.10        GARAGE & REPAIR EQUIPMENT                                30          0       3.33         R1.5
  394.20        SHOP EQUIPMENT                                           30          0       3.33         R1.5
  394.30        TOOLS AND WORK EQUIPMENT                                 30          0       3.33         R1.5
  395.10        LABORATORY EQUIPMENT                                     35          0       2.86          L1
  395.20        LABORATORY EQUIPMENT-R&D                                 35          0       2.86          L1
  396.10        POWER OPERATED EQUIP-ELECTRIC                            12         15       7.08          L3
  396.20        POWER OPERATED EQUIPMENT-GAS                             12         15       7.08          L3
  396.40        POWER OPERATED EQUIPMENT-COMMON                          12         15       7.08          L3
  397.10        COMMUNICATION EQUIPMENT-RADIO                            20          0       5.00         R2.5
  397.20        COMMUNICATION EQUIPMENT-TELEPHONE                        10          0      10.00          L3
  398.00        MISCELLANEOUS EQUIPMENT                                  30          0       3.33         R0.5
</TABLE>

<PAGE>

                                   Appendix K

                    Central Hudson Gas & Electric Corporation
                           Cases 05-E-0934 & 05-G-0935
              Gas Balancing Methodology Applicable to S.C. 9 and 11

Monthly Balanced Service

<TABLE>
<CAPTION>
                                                                          Normalized   Balancing
                                                             Allocation   Throughput    Svc Chg
Peak Requirements                       Mcf      % Mcf        of Costs       (Mcf)      ($/Mcf)
                                      -------   --------    -----------   ----------   ---------
<S>                             <C>   <C>       <C>         <C>           <C>          <C>
S.C. No. 9                      (a)       420       1.22%   $    63,071      797,600    $ 0.0791
S.C. No. 11 - Trans. & Dist.    (a)       614       1.78%   $    92,235    1,992,800    $ 0.0463
S.C. No. 11 - DLM               (a)     1,436       4.17%   $   215,468      847,692    $ 0.2542

Other Classes                          31,995      92.83%   $ 4,802,322   12,228,595    $ 0.3927
                                      -------   --------    -----------   ----------
                        Total          34,465     100.00%   $ 5,173,095   15,866,687
</TABLE>

Daily Balanced Service

<TABLE>
<CAPTION>
                                                    2%         % of Total    Balancing
                                                   Peak         Peaking       Svc Chg
Peak Consumption                        Mcf     Consumption   Requirements    ($/Mcf)
                                      -------   -----------   ------------   ---------
<S>                                   <C>       <C>           <C>            <C>
S.C. No. 9                              2,968          59          14.13%    $  0.0112
S.C. No. 11 - Trans. & Dist.           10,860         217          35.35%    $  0.0164
S.C. No. 11 - DLM                       5,741         115           8.00%    $  0.0203

Other Classes                         107,142       2,143           6.70%    $  0.0263
                                      -------
                                      126,711
</TABLE>

(a)

<TABLE>
<CAPTION>
                                                      Total Extreme
                                      Total Extreme     Day Demand    Total Extreme
                                        Day Demand        w/LAUF       Day Delivery   Deficiency   % of
                                          (Mcf)           2.50%           (Mcf)          (Mcf)    Demand
                                      -------------   -------------   -------------   ----------  ------
<S>                                   <C>             <C>             <C>             <C>         <C>
S.C. No. 9                                    2,968           3,042           2,622          420     14%
S.C. No. 11 - Trans. & Dist.                 10,860          11,132          10,517          614      6%

S.C No. 11 - DLM                              5,741           5,885           4,449        1,436     25%
                                      -------------   -------------   -------------   ----------
                        Total                16,601          17,016          14,966        2,050
</TABLE>

Note:

The above amounts are based on actual data as of February 1, 2006.

<PAGE>

                                   Appendix L

                    Central Hudson Gas & Electric Corporation
                           Cases 05-E-0934 & 05-G-0935

                    Detailed CSI Margin of Error Calculation

For purposes of supplementing the Customer Satisfaction Index (CSI) value which
is currently provided by Central Hudson at the end of the year, and for purposes
of determining if that CSI value has changed in a significant manner from the
prior year's CSI level, Central Hudson will provide the following margin of
error (MOE) calculations.

1. To provide an estimate of the 95% confidence interval regarding the responses
to each of the eight individual survey questions whose results are combined to
create the overall CSI, Central Hudson will perform the following MOE
calculation for each question.

          MOE(Qi) = P(Qi)+/-1.96 x (square root) P(Qi)*(1-P(Qi))/n(Qi)

Where the subscript "Qi" signifies each of the eight individual satisfaction
survey questions, "p" is the proportion of customers surveyed who answered "Very
Satisfied" or "Satisfied" on each individual question and "n" the base number of
customers who responded to that individual question in that year.

2. To provide a reasonable approximation of the MOE for the overall CSI level
for each year, (which is a weighted combination of the proportions of "Very
Satisfied" or "Satisfied" customer responses to the eight individual questions),
Central Hudson will provide the following calculation

          MOE(CSI) = P(CSI)+/-1.96 x (square root) P(CSI)*(1-P(CSI))/n

Where the CSI level for the year will be treated as signifying the proportion,
"p" of customers who are satisfied overall (as if each surveyed customer were
asked a single question, "are you satisfied overall"), and "n" will signify the
maximum number of annual customer survey responses received on any of the
questions in that year.

<PAGE>

                                  ATTACHMENT 2

<PAGE>

CASES 05-E-0934 and 05-G-0935                                       ATTACHMENT 2

SUBJECT: Filings by CENTRAL HUDSON GAS & ELECTRIC CORPORATION

                Amendments to Schedule P.S.C. No. 15 - Electricity

                     First Revised Leaf No. 218.2
                     Second Revised Leaf No. 231
                     Fourth Revised Leaves Nos. 106, 218.1, 219
                     Fifth Revised Leaves Nos. 165, 185, 205.1, 210, 217, 222
                     Sixth Revised Leaves Nos. 105, 220, 246
                     Seventh Revised Leaves Nos. 104, 169, 205, 218
                     Supplements Nos. 30, 31, 32

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

                     First Revised Leaf No. 181
                     Third Revised Leaves Nos. 68, 71, 72, 158
                     Fourth Revised Leaves Nos. 151, 152, 188, 193
                     Fifth Revised Leaf No. 149
                     Sixth Revised Leaves Nos. 186, 191
                     Eighth Revised Leaf No. 159
                     Supplements Nos. 20, 22, 23