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).
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.
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(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
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(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.
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(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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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.
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(16) Balancing Service Charge revenues would be credited to the Gas Supply
Charge.
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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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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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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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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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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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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
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(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.
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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-
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-
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-
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-
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-
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-
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-
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-
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-
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-
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-
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-
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-
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-
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-
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-
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-
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.
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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.
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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.
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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-
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.
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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.
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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-
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.
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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.
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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-
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-
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-
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-
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.
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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-
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.
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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.
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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.
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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.
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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
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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
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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.
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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
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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
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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
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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.
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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.
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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
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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
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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."
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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.
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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
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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.
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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
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ATTACHMENT 1
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)
- --------------------------------------------------------------------------------
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
(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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
Appendix A, Schedule 1
Central Hudson Gas & Electric Corporation
Cases 05-E-0934 & 05-G-0935
Electric Income Statements
($000)
Rate Years Ending
------------------------------
6/30/07 6/30/08 6/30/09
Line No. (A) (B) (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%
======== ======== ========
Appendix A, Schedule 2
Central Hudson Gas & Electric Corporation
Cases 05-E-0934 & 05-G-0935
Electric Rate Increase Phase-In
($000)
Rate Years Ending
--------------------------------
6/30/07 6/30/08 6/30/09
--------- --------- --------
Line No. (A) (B) (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
-------- ========
Appendix A, Schedule 3
Central Hudson Gas & Electric Corporation
Cases 05-E-0934 & 05-G-0935
Electric Rate Base
($000)
Electric
-----------------------------------
Rate Years Ending
-----------------------------------
6/30/07 6/30/08 6/30/09
--------- --------- ---------
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
========= ========= =========
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
(1) (2) (3) (4) (5)
Rate Adj Adj to
Initial Net of 2.59% Net Initial Net
Income Return +/- 15% Income Income
----------- ------- ------- -------- -----------
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
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
---------- ---------- --------- -------- -------- ----------
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%
(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
----------- ---------- ----------- ---------- --------- ---------
$ 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)
(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
---------- ---------- ---------- ---------- ---------- ----------------
$ 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%
Increase
--------
Avg. 10.39%
Min 0.75x 7.80%
Max 1.25x 12.99%
Rate Years 2 & 3
Rate Year 2
-----------------------------------------------------
Increase as a Base Rev % Adj. for Rev Unbundled to MFCs
% of System Increase Increase MWh MFC/kWh Total
------------- -------- -------- --------- --------- -------
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
Rate Year 3
-----------------------------------------------------
Base Rev % Adj. for Rev Unbundled to MFCs
Increase Increase MWh MFC/kWh Total
-------- -------- --------- --------- -------
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
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)
Current Rates Rate Year 1 Rate Year 2 Rate Year 3
------------- ----------- ----------- -----------
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
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)
Rate Year 1 Rate Year 2 Rate Year 3
------------- ------------- -------------
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
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.
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.
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%
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%
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
Demand kW Energy kWh Present Rates Proposed Rates Change ($) Change (%)
- ---------- ---------- ------------- -------------- ---------- ----------
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%
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%
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
Demand kW Energy kWh Present Rates Proposed Rates Change ($) Change (%)
- --------- ---------- ------------- -------------- ---------- ----------
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%
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%
Appendix D, Schedule 1
Central Hudson Gas & Electric Corporation
Cases 05-E-0934 & 05-G-0935
Gas Income Statements
($000)
Rate Years Ending
--------------------------------
6/30/07 6/30/08 6/30/09
Line No. (A) (B) (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%
======== ========= =========
Appendix D, Schedule 2
Central Hudson Gas & Electric Corporation
Cases 05-E-0934 & 05-G-0935
Gas Rate Base
Gas
--------------------------------
Rate Years Ending
--------------------------------
6/30/07 6/30/08 6/30/09
--------- --------- ---------
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
========= ========= =========
Appendix E
Central Hudson Gas & Electric Corporation
Cases 05-E-0934 & 05-G-0935
Gas Cost of Service Summary
- ------------------------------------------------------------------------------------------------------------------------------------
Rev. Req. for Bundled Functions @ ROR on
RB = 7.06% Residential Commercial/Industrial
Total System Heating Non-heat Heating Non-heat
- ------------------------------------------------------------------------------------------------------------------------------------
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
- ------------------------------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------
Rev. Req. for Bundled Functions @ ROR on
RB = 7.06% SC8/9 Firm Firm
Interruptible SC11-DLM Intrdprtmntl SC11 t SC11 d
- -------------------------------------------------------------------------------------------------------------
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
- -------------------------------------------------------------------------------------------------------------
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
(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
----------- ------ ------- ------ ----------- -----------
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%
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
---------- -------- -------- -------- ----------
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
(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
----------- ---------- ----------- ---------- --------- ---------
$ -- $ 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
(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
---------- ---------- ---------- ---------- ---------- ---------------
$ 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%
Increase
--------
Avg. 22.30%
Min 0.50x 11.15%
Max 1.50x 33.44%
Rate Years 2 & 3
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
------------- -------- --------- --------- ------ -------- --------- --------- ------
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
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
Current Rates Rate Year 1 Rate Year 2 Rate Year 3
------------- ----------- ----------- -----------
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
Appendix F Sheet 3 of 6
Central Hudson Gas & Electric Corporation
Cases 05-E-0934 & 05-G-0935
Gas Billing Determinants
(Excludes Unbilled)
Rate Year 1 Rate Year 2 Rate Year 3
----------- ----------- -----------
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
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.
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
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
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)
Electric Department
--------------------------------
Deferred Deferred
Charge Tax Net
--------------------------------
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
================================
(1) Includes Shared Earnings deferred for Customer benefit of $ 22.3 million
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)
Gas Department
----------------------------------
Deferred Deferred
Charge Tax Net
----------------------------------
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 =======
(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.
Appendix G, Schedule 3
Central Hudson Gas & Electric Corporation
Cases 05-E-0934 & 05-G-0935
Deprecation Reserve Rate Moderator
($000)
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
========
Appendix H, Schedule 1
Central Hudson Gas & Electric Corporation
Cases 05-E-0934 & 05-G-0935
Capital Structure and Allowed Rate of Return
($000)
Pre-Tax
Weighted Weighted
Rate Year 1: Amount Ratio Cost Cost Cost
- ------------ ---------- ------ ----- -------- --------
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%
========== ====== ======== ========
Pre-Tax
Weighted Weighted
Rate Year 2: Amount Ratio Cost Cost Cost
- ------------ ---------- ------ ----- -------- --------
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%
========== ====== ======== ========
Pre-Tax
Weighted Weighted
Rate Year 3: Amount Ratio Cost Cost Cost
- ------------ ---------- ------ ----- -------- --------
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%
========== ====== ======== ========
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
========= ========= =========
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)
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)
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%
=========
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)
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)
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%
=========
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)
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)
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%
=========
Appendix I, Schedule 1
Central Hudson Gas & Electric Corporation
Cases 05-E-0934 & 05-G-0935
Deferral Items
($000)
ELECTRIC OPERATIONS GAS OPERATIONS
--------------------------- -------------------------
Rate Allowance Items: Method RY1 RY2 RY3 RY1 RY2 RY3
- --------------------- ------ ------- ------- ------- ------- ----- -------
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
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
Appendix I, Schedule 2
Central Hudson Gas & Electric Corporation
Cases 05-E-0934 & 05-G-0935
Revenue Matching Factors
Rate Year #1 Rate Year #2 Rate Year #3
------------ ------------ ------------
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
============ ============ ============
Appendix J Sheet 1 of 2
Central Hudson Gas & Electric Corporation
Cases 05-E-0934 & 05-G-0935
DEPRECIATION RATES
PSC Average Annual Allocation
ACCT Service Net Deprec Survivor of Excess
NO PLANT ACCOUNT Life Salvage Rate Curve Reserve
- --------- ------------------------------------------------------- ------- ------- ------ ------------- -----------
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)
===========
Appendix J Sheet 2 of 2
Central Hudson Gas & Electric Corporation
Cases 05-E-0934 & 05-G-0935
DEPRECIATION RATES
PSC Average Annual Allocation
ACCT Service Net Deprec Survivor of Excess
NO PLANT ACCOUNT Life Salvage Rate Curve Reserve
- --------- ------------------------------------------------------ ------- ------- ------ ------------- ----------
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
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
Normalized Balancing
Allocation Throughput Svc Chg
Peak Requirements Mcf % Mcf of Costs (Mcf) ($/Mcf)
------- -------- ----------- ---------- ---------
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
Daily Balanced Service
2% % of Total Balancing
Peak Peaking Svc Chg
Peak Consumption Mcf Consumption Requirements ($/Mcf)
------- ----------- ------------ ---------
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
(a)
Total Extreme
Total Extreme Day Demand Total Extreme
Day Demand w/LAUF Day Delivery Deficiency % of
(Mcf) 2.50% (Mcf) (Mcf) Demand
------------- ------------- ------------- ---------- ------
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
Note:
The above amounts are based on actual data as of February 1, 2006.
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.
ATTACHMENT 2
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