EXHIBIT (99)(i)9
STATE OF NEW YORK
PUBLIC SERVICE COMMISSION
At a session of the Public Service
Commission held in the City of
Albany on October 24, 2001
COMMISSIONERS PRESENT:
Maureen O. Helmer, Chairman
Thomas J. Dunleavy
James D. Bennett
Leonard A. Weiss
Neal N. Galvin
CASE 00-E-1273 - Proceeding on Motion of the Commission as to the Rates,
Charges, Rules, and Regulations of Central Hudson Gas &
Electric Corporation for Electric Service.
CASE 00-G-l274 - Proceeding on Motion of the Commission as to the Rates,
Charges, Rules, and Regulations of Central Hudson Gas &
Electric Corporation for Gas Service.
ORDER ESTABLISHING RATES
(Issued and Effective October 25, 2001)
BY THE COMMISSION:
The following order generally adopts terms set forth in Joint
Proposal submitted by Central Hudson Gas & Electric Corporation (Central Hudson,
the company); staff of the Department of Public Service (Staff); the Consumer
Protection Board (CPB) ; Multiple Intervenors (MI); and Strategic Power
Management, Inc., an energy services company (ESCO). We thereby establish a rate
and regulatory plan intended to take effect as of July 1, 2001 and to continue
for at least three years from that date.
Today's order determines the rates Central Hudson will charge for
delivery of electricity and gas to customers that purchase those commodities
from Central Hudson, and to customers that purchase the commodities elsewhere
and rely on Central Hudson for delivery only. (The commodity portion of the bill
is determined by energy prices in markets outside our regulatory jurisdiction.)
The order will freeze electric and gas delivery rates for three years, after
initially reducing electric delivery rates by 1.2% overall.
In addition to rate levels, a major issue in this case has been
the disposition of a "benefit fund" that will have accumulated as a result of
Central Hudson's operations pursuant to the Rate and Restructuring Plan
instituted in February 1998.(1) The fund includes, most significantly, the
proceeds from the company's sale of its Danskammer and Roseton generating plants
and its interest in the Nine Mile Point No. 2 (NMP2) generating plant. For
purposes of the joint proposal, the parties have estimated the benefit fund as
$164 million. Under a proposal pending in another proceeding,(2) the fund might
be augmented by additional amounts related to the NMP2 sale.
Under today's order, $42.5 million of the benefit fund will be
used to offset rate base and thereby achieve the three-year rate freeze noted
above. Another $45 million will be used as refunds to customers over the three
years of the rate plan. As the $45 million is a net-of-tax amount, the refunds
actually received by customers will total about $72 million. The remainder will
be applied toward other customer benefits which may include additional refunds,
reliability improvements, bill mitigation in the event of commodity price
volatility, and economic development programs. To the extent that portions of
the fund are held in reserve rather than used immediately, they will accrue
interest on the customers' behalf.
We also are adopting more stringent service quality criteria, and
expanded programs to help residential customers that have difficulty paying
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(1) Case 96-E-0909, CENTRAL HUDSON GAS & ELECTRIC CORP. - ELECTRIC RATES AND
RESTRUCTURING, Opinion No. 98-14 (issued June 30, 1998).
(2) Case 01-E-0011, NIAGARA MOHAWK POWER CORP. ET AL., PETITION UNDER PUBLIC
SERVICE LAW ss.70.
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their utility bills. And, to enhance customers' ability to obtain energy
supplies from providers competing with Central Hudson, we are prescribing
backout credits which will determine what portion of the Central Hudson bill a
customer may avoid by shopping elsewhere for the electric or gas commodity. We
also will require that Central Hudson reimburse ESCOs for ancillary service
charges imposed on them by the Independent System Operator, a cost element whose
volatility has deterred market entry by ESCOs.
BACKGROUND AND PROCEDURAL HISTORY
Central Hudson serves about 260,000 customers in eight mid-Hudson
counties. In the February 1998 Rate and Restructuring Plan, we set rates
intended to continue through June 2001 and directed the company to divest its
electric generating plants, unbundle its rates, and institute full retail
access. The current proceedings were instituted to consider new tariffs for
unbundled delivery service only, proposed in August 2000 and amended in October
2000 after sale of the Roseton and Danskammer plants. The company designed the
proposed tariffs to increase its annual electric and gas delivery revenues by
about $14.1 million (8.8%) and $3.6 million (4.7%) respectively for the year
ending June 30, 2002.
After full evidentiary hearings and numerous public statement
hearings, a recommended decision (RD) issued April 24, 2001 called for electric
and gas revenue decreases of $1.7 million and $2.1 million respectively. The RD
provisionally addressed the disposition of the benefit fund, but it recommended
further negotiations on that issue and others. Settlement discussions had been
conducted intermittently throughout the proceedings, on notice to potentially
interested parties (in compliance with 16 NYCRR 3.9). After two rounds of briefs
on or opposing exceptions to the RD, negotiations resumed, and culminated in the
joint proposal under review here. To allow for negotiations and Commission
review of any resulting proposal, the company has waived the expiration of the
statutory suspension period through October 31, 2001.
The joint proposal was filed August 21, 2001 and was followed by
two rounds of written statements in support or in opposition. Supporting
statements and replies have been filed by Central Hudson, Staff, CPB, and MI.
Statements opposing at least some elements of the joint proposal have been
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filed by the Office of the Attorney General (OAG); Small Customer Marketer
Coalition (SCMC), representing certain ESCOs; and John J. Mavretich, PRO SE.
TERMS SUBMITTED PURSUANT TO THE JOINT PROPOSAL
Should we adopt the terms proposed by the parties, significant
results would include the following:(3)
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(3) For a complete statement of the joint proposal's terms, one must rely on
the text of the proposal itself (Attachment B of this order).
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REVENUE REQUIREMENT
Delivery rates would be frozen for three years through June
2004,(4) at levels designed to produce (over the three years) a $2
million decrease in annual electric delivery revenues and no
change in gas delivery revenues. Within certain limits, the
company could use deferral accounting as a means of extending the
freeze beyond three years.
The implicit return on common equity would be 10.3%, assuming that
the 47% equity ratio declines to a target of 45% by the third
year. To the extent that the equity return for the electric or gas
department exceeded 11.3%, the excess would be shared 50:50
between shareholders and customers. Excesses over 14% would be
allocated entirely to customers. The rate plan would be subject to
reopening if either department's equity return fell below 8.5%.
The benefit fund would be applied for the following purposes (in
amounts that remain to be quantified through further negotiations,
if not specified here):
a. $45 million (about $74 million, stated on a net-of-tax
basis), for three annual refunds of about $24 million each
year, to customers on a per-kWh basis;
b. $42.5 million as a permanent offset to electric rate base;
c. $13 million over three years for distribution system
reinforcement and increased tree trimming;
d. $10 million for site remediation at a former gas
manufacturing site in Newburgh;
e. recovery of stranded costs caused by competitive electric
rate restructuring, if consistent with Commission policy to
be established in other proceedings;
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(4) Under orders in these proceedings extending the suspension period
(issued June 25, August 29, and September 28, 2001), rates are to be set as if
the new revenue allowance had taken effect July 1, 2001.
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f. economic development initiatives (other than the present
Revitalization Rate Program), to be formulated through
collaboration among the parties starting November 1, 2001;
and
g. other items to be proposed through collaboration starting
in mid-January 2002, which might include additional
refunds, delivery rate mitigation after the three-year plan
expires, and commodity price spike mitigation.
COST ALLOCATION AND RATE DESIGN
In lieu of the present fuel adjustment clause, a purchased power
recovery (PPR) charge would recover energy and capacity costs that
Central Hudson incurs to serve its remaining electric sales ("full
service") customers. The PPR charge would be calculated separately
for each class, rather than on a uniform per-kWh basis as the
company had advocated.(5) A variable cost recovery (VCR) charge
for all customers would reflect the costs and benefits associated
with Central Hudson's remaining generating plants and independent
power producer contracts.
Central Hudson will have access to relatively low-cost power
supplied by Dynegy, from the Roseton and Danskammer plants
(under a Transition Power Agreement or TPA); and by
Constellation, from NMP2 (under a Purchase Power Agreement or
PPA), if NMP2 is transferred as proposed in Case 0l-E-0lll, SUPRA.
Under the terms submitted in the joint proposal, TPA/PPA power
would be allocated to both full service and delivery customers,
based on each class's kWh as a percentage of total system kWh
sales, and among customers within classes based on each customer's
usage characteristics.
Class electric rate decreases would range from 0.5 to 1.25 times
the overall electric revenue decrease, as needed to reduce
variances between class and system rates of return. For
residential electric service,
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(5) In addition to the PPR, a variable cost recovery (VCR) charge
would recover non-avoidable variable energy costs, including purchases from
qualifying facilities and fuel for the company's remaining generators.
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a. the $7.15 monthly customer charge would increase to $12.00
in three steps between now and June 2004 (moving it closer
toward the estimated marginal per-customer cost that the
charge is intended to recover), with offsetting decreases
in other residential charges;
b. the space heating discount would be eliminated; and
c. time of use metering would continue to be offered.
Restoration of disconnected residential electric or gas service,
now billed at $10 for restoration during workdays and $25 after
hours, would increase to $20 workdays and $40 after hours or, if a
work crew is needed, $100 workdays and $140 after hours.
CUSTOMER SERVICE
Bills could be paid by credit card.
The service quality incentive formulas would continue to provide
potential penalties only, without affirmative rewards for good
service. The maximum annual disallowance would be 25 basis points
(bp) of common equity return for customer service, 25 bp for
electric reliability, 6 bp for gas reliability, and 3 bp for
non-emergency gas leak repair.
The low-income customer program would limit the monthly gas and
electric minimum charge to $5.00 for eligible customers, and
require that participating customers pay at least $5.00 per month
toward arrears if a local community action agency certifies their
ability to pay.
COMPETITIVE INITIATIVES
To encourage retail access, Central Hudson would:
a. offer a single-bill format;
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b. bill customers for Independent System Operator (ISO)
ancillary services, and reimburse ESCOs for ancillary
charges that the ESCO pays the ISO;
c. develop metrics to be used in an ESCO/marketer satisfaction
incentive mechanism, including potentially an award of 10
bp on common equity, and designate an ESCO/marketer
ombudsman; and
d. improve the company's outreach program to enhance public
understanding of competitive options, with a potential
award of up to 10 bp of common equity return for a
successful program.
Pending the outcome of the generic rate unbundling proceeding,(6)
electric backout credits would be set at $.0005 (0.5 mills) per
kWh (S.C. 13), $.002/kWh (S.C. 3), $.003/kWh (S.C. 2 demand), or
$.004/kWh (S.C. 1, S.C. 2 non-demand, and S.C. 6) . The gas
backout credit would be $.l5/mcf.
UNRESOLVED ISSUES
The following matters require discussion here because the joint
proposal does not expressly address them or because the parties disagree.
METERING PROGRAMS
As noted above, the joint proposal calls for collaborative efforts
to consider disposition of benefit fund amounts not immediately addressed in
today's order. According to the joint proposal, potential future uses of the
fund could include competition-related initiatives that we might designate.
As one such initiative which we are prepared to designate now, the
company and parties should explore the development of advanced pricing and
metering offerings for a broader range of its customers, including approaches
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(6) Case 00-M-0504, COMPETITIVE ENERGY MARKETS AND RETAIL COMPETITIVE
OPPORTUNITIES, Order Directing Expedited Consideration of Rate Unbundling
(issued March 29, 2001).
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that would better enable customers to respond optimally to improved price
signals. Properly implemented, this initiative could result in multiple
benefits, including lower customer bills; reduced wholesale market prices due to
improved demand responsiveness; and reduced costs, to the utility and other
load-serving entities, of recording and transmitting customer usage and billing
data. In particular, the company and parties should consider:
the potential benefits resulting from enhanced pricing offerings
for a broad range of customers beyond those now eligible for the
company's existing real-time pricing tariffs;
appropriate methods for providing customers access to the
education and control technologies that may be necessary to adjust
their usage in response to actual market prices; and
appropriate sources of funding for enhanced metering and meter
reading technologies, ideally through competitive means, to
effectively record and transmit usage and billing data among
customers, the utility, and competitive load-serving entities.
CREDIT CARDS
The joint proposal includes an uncontested provision that the
company would be allowed to collect bill payments by credit card. In adopting
this element of the proposal, we note that it leaves unresolved several matters
of implementation. First, we seek assurances that Central Hudson will not use
the availability of the credit card option as leverage to extract payments from
financially troubled customers for whom the payment and interest charges are not
truly affordable. Second, future determinations of the company's revenue
requirement will require recognition of cost offsets, such as reductions in
working capital and uncollectibles, resulting from credit card usage subsequent
to the three-year rate plan. Third, the joint proposal is silent regarding a
significant disagreement that arose during the litigation of this issue: whether
costs associated with the credit card option should be allocated to all
customers, or to some classes exclusively, or only as a service fee to those
customers who actually make a credit card payment. To address these concerns,
Central Hudson should provide our staff the details of any proposed
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credit card payment program before implementing it.
SERVICE QUALITY AND MARKETER SATISFACTION INCENTIVES
Regarding the proposed service quality program and the program to
gauge marketer satisfaction, we assume the parties recognize that we need to
review the progress and results of the company's efforts periodically.
Therefore, in adopting the proposed terms, we do so with the understanding that
compliance with today's order will require an annual report concerning these
programs. The company should consult with the Director of our Office of Consumer
Education and Advocacy as to specific details of this requirement.
REFUNDS VS. RATE BASE REDUCTIONS
OAG advocates that we reject the joint proposal's terms insofar as
they would limit the rate base reduction to $42.5 million. OAG says we should
enlarge this amount by reallocating, into additional rate base offsets, the $45
million that would be used for direct customer refunds under the joint proposal.
OAG notes that a rate base offset is permanent, while a refund is transitory.
Therefore, OAG argues, rate base offsets would be preferable, because they would
not culminate in a bill increase upon exhaustion of the benefit fund and because
their permanence assures customers a larger dollar benefit over time than any
finite amount of refunds. OAG adds that any benefit fund balance not
specifically allocated to other purposes should be applied toward immediate rate
base reductions, instead of being held in reserve pending collaborative
discussions as contemplated in the joint proposal.
OAG misstates the comparison between rate base reductions and
refunds, and (as MI observes) misreads the RD's comments about the relative
advantages of rate base offsets and refunds. The RD regarded refunds as
preferable from the customer's standpoint, in view of tax considerations which
nearly double the effective short-term benefit to customers from refunds as
compared with rate base offsets.(7) And the customer benefit from a refund may
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(7) MI's analysis, uncontradicted on the record, estimates that each
dollar allocated to refunds engenders approximately a $0.40 tax savings. This
benefit is unavailable in connection with amounts allocated to rate base
reduction.
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be just as permanent as the benefit of a rate base offset, because any refund is
a potential earnings source for the customer. For these reasons, an immediate
refund may well provide a customer greater long-term economic benefits than a
rate base offset of the same dollar amount, even if (as OAG emphasizes) the rate
base offset may provide a larger long-term reduction in the customer's utility
bill. Finally, as Staff observes, the possible consequences of the massive rate
base reduction implicit in OAG's position have not been examined on the record
or addressed by the parties.(8)
The proposed allocation from the benefit fund provides a rate base
reduction designed to stabilize rates at a slightly reduced level, provides a
similar amount in refunds, and creates the possibility of additional allocations
in the future to bill mitigation and additional refunds. Notwithstanding OAG's
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(8) Staff, the company, and MI object to OAG's arguments, regarding
this and other issues, on the ground that OAG raised them initially in the
second round of statements instead of the first. OAG responds that its statement
legitimately addressed the initial round of other parties' statements; the
objections to OAG's statement constitute unauthorized surreplies; and OAG's
statement cannot have come as a surprise to other parties, as it reflected
positions advocated by OAG throughout the proceeding. The parties objecting are
correct that OAG's submittal was inconsistent with the procedural schedule,
which specified that the initial round would be the occasion for both supporting
and opposing statements. Cases 00-E-l273 and 00-G-1274, Procedural Ruling
(issued August 22, 2001) . In any event, we find OAG's points unpersuasive for
reasons discussed in the accompanying text.
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comments, we find that the proposal strikes an entirely reasonable balance among
those objectives. Moreover, OAG has not shown that additional rate base
reductions are preferable to using the benefit fund for competitive initiatives,
bill mitigation, or other possible purposes besides refunds. The joint proposal
aptly calls for further collaboration to explore such options in the future, in
light of evolving circumstances which may not be clearly foreseeable now.
Meanwhile, any portion of the benefit fund not used immediately will accrue
interest at a rate equal to the company's pre-tax rate of return, thus providing
customers the same benefit as if the amount thus reserved were a rate base
offset.
BACKOUT CREDITS
Pending the redetermination of unbundled rates in the unbundling
proceeding,(9) the joint proposal calls for backout credits of $.004 (four
mills) per kWh for S.C. 1 residential and S.C. 2 general non-demand customers.
SCMC advocates, instead, a credit of $.007/kWh for these classes. SCMC says the
larger credit is necessary because Central Hudson, with almost no retail access
penetration several years after the initial order directing its restructuring,
is in a position analogous to that of other utilities years ago when we adopted
more robust stimuli to "jump-start" competition simultaneously with
restructuring. SCMC argues that, in allowing other utilities to offer
non-volumetric, lump-sum incentive payments to retail access customers or ESCOs,
our primary objective has been to stimulate competition rather than calibrate
rates to reflect avoided costs. SCMC adds that Central Hudson has an equitable
obligation to promote competition more vigorously, because the company has
benefited from generation divestiture whose purpose was to create competition.
However, we agree with Staff that the $.004/kWh provision in the
joint proposal is a reasonable measure at this time, given that it will be
adjusted if necessary on the basis of the record in the unbundling proceeding.
Staff notes that $.004/kWh is the same temporary proxy that we also have adopted
for other companies. Conversely (as Central Hudson observes), there is no
evidence in this case either to rebut a $.004/kWh approximation of avoided costs
or to support a $.007/kWh credit as SCMC advocates. In these circumstances,
SCMC's asserted dichotomy between encouraging competition
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(9) Case 00-M-0504, SUPRA.
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and gauging costs is overstated; at this moment, our most effective means of
promoting competition is to establish cost-based rates on the basis of a full
record in the unbundling proceeding.
OAG objects in principle to any backout credits as proposed, on
the ground that such credits would subsidize retail access customers at other
customers' expense. We agree with Staff that OAG's argument errs in two
respects. First, to the extent that the benefit fund can be used to promote
competitive initiatives through measures such as backout rates, it serves the
interests of customers in general and therefore cannot properly be deemed an
unfair burden on full-service customers. Second, unless we adopt backout rates
here (at least as an interim proxy for Central Hudson's avoided costs while
awaiting more accurate cost determinations in the unbundling proceeding), it is
retail access customers that will be burdened with a subsidy, insofar as they
must continue to pay delivery rates that include costs related to the merchant
function. Thus, rather than create subsidies as OAG alleges, the backout credit
will offset them.
PPR VOLATILITY
OAG says the proposed purchased power recovery (PPR) mechanism
should be modified so that the risk of commodity price volatility would rest
"primarily with the company" rather than with low-usage customers. OAG argues
that Central Hudson, as compared with its customers, can better avoid the
consequences of supply shortages during a transition to competition.
OAG's criticism of the PPR is inappropriate in several respects.
First, the joint proposal already incorporates the results of efforts by Central
Hudson to mitigate volatility, by providing customers an allocation of TPA
power. Second, OAG presents no specific mechanism for carrying out its proposed
risk reallocation. Third, the joint proposal already addresses OAG's concern by
calling for further exploration of how the benefit fund might be used to
mitigate price volatility.
RETURN ON EQUITY AND NMP2 ISSUES
Mr. Mavretich contends that there is only a superficial
resemblance between the joint proposal's 10.3% implicit return on equity and the
10.28%
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return allowance recommended in the RD, because the joint proposal's 100 basis
point deadband would allow Central Hudson to retain any earnings up to 11.3%.
Mr. Mavretich, opposed by Central Hudson and Staff, argues that the deadband
should be eliminated so that 50:50 sharing between shareholders and customers
would be applicable to any excess over 10.3%.
This criticism of the joint proposal is a NON SEQUITUR. The
proposal's various provisions are designed to create a reasonable opportunity
for the company to earn a return of 10.3%, corresponding to the cost of equity
as indicated by the record on which the RD relied and which Mr. Mavretich seems
to invoke now. Absent any showing that adoption of the proposed terms would
produce a return greater than 10.3%, we are adopting them so as to establish
rates that reflect the cost of equity. The joint proposal's earnings sharing
provisions are not an indication that the earned return is EXPECTED to exceed
10.3%, as Mr. Mavretich suggests, but only a mechanism to reasonably balance
investor and shareholder if it does.
As a more general matter, Mr. Mavretich supports this and his
other criticisms of the joint proposal (noted below) by arguing that we should
take into consideration Central Hudson's continuing failure to answer
interrogatories regarding the long-term costs of its alleged managerial errors
in connection with the NMP2 generating unit. The company responds by asserting a
record of managerial success. While we would not condone the company's disregard
of a discovery ruling if the issue were directly presented, here the issue is
moot in two respects. First, Central Hudson is not pursuing any challenge to the
Judge's discovery rulings, or to the RD's finding that the lack of interrogatory
responses should be construed against the company pursuant to 16 NYCRR 5.10(1)
when estimating NMP2's costs. Second, the company has abandoned its request for
an allocation from the benefit fund as a reward for exemplary performance. It
was that request which, in Mr. Mavretich's view, established the relevance of
the history surrounding NMP2 for purposes of these proceedings. Thus, the NMP2
discovery issue does not affect our assessment of the balancing of interests in
the joint proposal.(10)
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(10) We need not decide here whether, as Staff suggests, Mr.
Mavretich's arguments about Central Hudson's NMP2 participation "are best
addressed in Case 0l-E-00ll" (the proceeding to consider ownership transfer of
NMP2).
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STOCK SYMBOL
Central Hudson received $2.5 million from the sale of its stock
trading symbol, after its shares ceased to be publicly traded because it became
a subsidiary wholly owned by a new parent company. Staff's litigating position,
accepted in the RD, was that the sale proceeds should be viewed as an offset to
corporate reorganization costs and that $1.0 million of the proceeds therefore
should be used to reduce rate base. Under the joint proposal, we are asked to
reject that approach and disregard the sale proceeds for ratemaking purposes.
Mr. Mavretich opposes this resolution of the issue. Staff and the company
correctly respond that Mr. Mavretich has not accurately characterized the asset
in question. Contrary to his assertions, the sale of the stock symbol did not
occur pursuant to provisions resembling those that governed the auction of the
company's generating plants. Nor is it true that the stock symbol was a rate
base item like other assets "supported through customers['] rates," as Mr.
Mavretich says; and, even if it were, we have broad discretion over the
ratemaking treatment of sale proceeds regardless of whether the asset has been
held in rate base. In this instance, there is nothing unreasonable about the
proposed allocation of the proceeds to shareholders.
RELIABILITY IMPROVEMENT PROGRAM
Mr. Mavretich notes that the RD, in approving an infrastructure
program similar in some respects to the Reliability Improvement Program
described in the joint proposal, called for a progress report after the initial
expenditures. He criticizes the lack of a comparable reporting requirement in
the joint proposal. Central Hudson responds that the program's efficacy would be
reflected in the proposed incentive provisions related to system reliability,
while Staff points out that the joint proposal expressly provides for an annual
plan subject to Staff review. Thus, Mr. Mavretich's concern about the company's
accountability is unfounded."(11)
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(11) OAG raises concerns similar to Mr. Mavretich's, regarding both the
Reliability Improvement Program and the Newburgh gas manufacturing site
remediation project. In both instances, however, we expect that the company's
activities will be subject to ongoing Commission review.
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DISCUSSION
Subject to our determinations described above, we find that the
joint proposal's sponsors have satisfied their burden of showing that adoption
of the proposed terms would satisfy the Public Service Law's requirement of safe
and adequate service at just and reasonable rates. They also have shown that
implementation of their proposals would achieve a fair balance of interests
among the parties and customers, and would produce constructive results that may
not have been achievable except through a negotiated agreement.
In particular, the rates we are establishing reasonably reflect
Central Hudson's cost of service and protect the company's financial integrity,
thus striking a fair balance between customer and investor interests; and the
proposed terms ensure rate stability for at least three years beyond the end of
the current rate plan. The economic benefits the company will have secured, in
negotiating the prices it will pay for electric output from its former
generating plants, will be allocated among customer classes in a fair and
competitively neutral fashion. To encourage progress toward retail competition
among energy suppliers in Central Hudson's service territory, the proposed terms
specify reasonable backout credits, incentives and other mechanisms to promote
cooperation between Central Hudson and ESCOs, and enhanced efforts to inform
customers about their supply options.
The disposition of the benefit fund serves a diverse array of
customer interests, including rate stabilization and an equitable distribution
of refunds among customer classes; bill mitigation; measures to attract and
retain jobs; environmental remediation; backout credits and other competitive
initiatives; and infrastructure reinforcement to improve service reliability.
Reliability, as well as safety and service quality, also will be enhanced as a
result of new performance measures and incentive mechanisms. Low-income
customers in particular will benefit from new programs addressing their needs.
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Finally, adoption of the proposed terms will accomplish these
goals within the context of a rate allowance consistent with an extensive record
in the litigated phase, concerning the company's revenue requirement and cost of
capital. Moreover, the proposals reflect the parties' best efforts to find a
reasonable resolution of issues that the RD identified as potentially productive
areas for further negotiation, particularly the uses of the benefit fund and the
design of cost recovery mechanisms and backout credits.
CONCLUSION
For the reasons stated, we find that our adoption of the joint
proposal's provisions subject to the discussion above will serve the public
interest and satisfy our statutory obligation to ensure safe and adequate
service at just and reasonable rates pursuant to Public Service Law ss.66. We
therefore will direct the company to file tariff revisions consistent with this
finding. To comply with the orders issued in these proceedings June 25, August
29, and September 28, 2001, the filing should be designed to implement the
tariff revisions as if they had taken effect July 1, 2001, notwithstanding the
November 1, 2001 effective date specified in Order Clause 3 (below).
THE COMMISSION ORDERS:
1. Subject to the foregoing discussion and the determinations
and understandings set forth therein, the terms of the Joint Proposal filed in
these proceedings August 21, 2001 are adopted in their entirety and are
incorporated as part of this order.
2. Central Hudson Gas & Electric Corporation (the company)
shall submit a written statement of unconditional acceptance of this order,
within five days following the order's issuance date, signed and acknowledged by
a duly authorized officer of the company. If an acceptance statement is not so
filed, the adoption of the joint proposal's terms may be revoked. The acceptance
statement should be filed with the Secretary of the Commission and served on the
parties to these proceedings.
3. The company is directed to cancel, no later than October
31, 2001, the tariff amendments and supplements listed in Attachment A of this
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order. The company is directed to file on not less than one day's notice, to
take effect no later than November 1, 2001 on a temporary basis, such further
tariff changes as are necessary to effectuate the provisions adopted in this
order. The company shall serve copies of its filing upon all parties to these
proceedings. Any comments on the compliance filings must be received at the
Commission's offices within ten days of service of the company's proposed
amendments. The amendments specified in the compliance filing shall not become
effective on a permanent basis until approved by the Commission and will be
subject to refund if any showing is made that the revisions are not in
compliance with this order. The requirement of ss.66(12)(b) of the Public
Service Law that newspaper publication be completed prior to the effective date
of the proposed amendments is waived, provided that the company shall file with
the Commission, not later than six weeks following the amendments' effective
date, proof that a notice to the public of the changes proposed by the
amendments and their effective date has been published once a week for four
successive weeks in newspapers having general circulation in the areas affected
by the amendments.
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4. These proceedings are continued.
By the Commission,
(SIGNED) JANET HAND DEIXLER
Secretary
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ATTACHMENT B
CASE 00-E-1273 - Proceeding on Motion of the Commission as to the
Rates, Charges, Rules, and Regulations of Central
Hudson Gas & Electric Corporation for Electric
Service.
CASE 00-G-1274 - Proceeding on Motion of the Commission as to the
Rates, Charges, Rules, and Regulations of Central
Hudson Gas & Electric Corporation for Gas Service.
JOINT PROPOSAL AND
JOINT PROPOSAL'S ATTACHMENTS A THROUGH I
STATE OF NEW YORK PUBLIC SERVICE COMMISSION
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Proceeding on Motion of the Commission Case 00-E-l273
as to rates, charges, rules and regulations of Central Hudson
Gas & Electric Corporation for electric service;
and
Proceeding on Motion of the Commission Case 00-G-1274
as to rates, charges, rules and regulations of Central Hudson
Gas & Electric Corporation for gas service
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JOINT PROPOSAL
I. INTRODUCTION
This is a Joint Proposal, dated as of August 15, 2001, for the resolution
of the above-captioned cases by and among the following parties and participants
("Signatories"): Central Hudson Gas & Electric Corporation ("Central Hudson" or
the "Company"); the Consumer Protection Board; Multiple Intervenors; the Staff
of the Department of Public Service ("Staff") and Strategic Power Management,
Inc.
This Joint Proposal is the product of negotiations among parties to the
proceeding on due notice in accord with the Commission's Settlement Guidelines
and of compromises among the Signatories. It has been made on the basis of the
Conditions of the Joint Proposal described below and is intended to resolve all
issues in these proceedings.
In general, both electric and gas rates are frozen at specified delivery
rate revenue levels until June 30, 2004 and specifically identified amounts of
delivery rate revenues are deferred from July 1, 2001 through June 30, 2002
("Rate Year One" or "RY1") to July 1, 2003 through June 30, 2004 ("Rate Year
Three" or "RY3").(1) Additional provisions address enhancements of competition
in gas and electric services and establish uses and procedures for reviewing
additional uses of the "Benefit Fund."(2)
II. JOINT PROPOSAL
A. Electric Rate Freeze: Electric delivery rates will be designed to
recover $153 million in delivery revenues annually and will be
frozen through June 30, 2004.
B. Gas Rate Freeze: Gas delivery rates will be designed to recover
$36.6 million in delivery revenues annually and will be frozen
through June 30, 2004.
C. Term of Electric and Gas Delivery Rate Freezes: The electric and
gas delivery rate freezes are effective through June 30, 2004 and
are further subject to the understandings that:
1. Nothing in this Joint Proposal or the Commission's adoption
of it is intended to prevent Central Hudson from filing
with the Commission requests for changes in rates to be
effective (after any applicable suspension) as of July 1,
2004;
2. Rate mechanisms for the pass-through of the purchase price
of electricity or gas are an integral part of this Joint
Proposal. Nothing in the rate freeze provisions of this
Joint Proposal is intended to preclude those mechanisms
from passing through the purchase prices of electricity
or gas.
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(1) The twelve month period ending June 30, 2003 is "Rate Year Two" or "RY2."
(2) The Benefit Fund results from Central Hudson's prior rate proceeding,
Case 96-E-0909. See, Opinion No. 98-14, issued June 30, 1998 and Order
Adopting Terms of Settlement Subject to Modifications and Conditions,
issued February 19, 1998.
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3. Central Hudson is authorized to reopen this Joint Proposal
if its achieved regulatory return on actual common equity
in either its electric or gas department (or both) falls
below 8.5%.
D. Treatment of Litigated Issues:
1. The Signatories have agreed to levels of delivery rate
revenues, which agreements are for settlement purposes
only, and not necessarily on the disposition of any
particular issue raised during the litigation, other than
as described in this Joint Proposal.
2. The terms and provisions of this Joint Proposal apply
solely to, and are binding only in the context of, the
purposes and results of the mutual agreements reflected in
the Signatories' settlement. None of the terms and
provisions of this Joint Proposal and none of the positions
taken herein by any party may be cited or relied upon by
any other party in any fashion as precedent in any
proceeding before the Commission, or before any other
regulatory agency or any court of law for any purpose
except in furtherance of the purposes and results of the
Signatories' settlement.
E. Income Statements
1. The Income Statements for Electric (Attachment A) and Gas
(Attachment B) services that have been attached to this
Joint Proposal are intended to show that the Joint Proposal
is reasonable and do not necessarily represent the views of
any Signatory.
2. The Income Statements attached hereto have incorporated the
following items:
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a. Return on Common Equity: An assumed return on common
equity of 10.3% has been agreed to as a fall out
from the agreed-to revenue requirements shown in the
Income Statements.
b. Equity Ratio: 47% first year, 46% second year and
45% third year.
c. Cost of Long-Term Debt and Redemption Premiums: As
shown in Attachment C, updated costs and amounts of
long term debt issuances, including the costs of
redemption, and the costs of preferred stock
redemption premiums and unamortized expenses, have
been employed in determining the revenue
requirements shown in the attached Income
Statements. Central Hudson is authorized to recover
the debt redemption premiums and unamortized debt
expense over the remaining life of the redeemed debt
and to recover the preferred stock redemption
premiums and unamortized expenses ratably over the
period ending 2028.
d. Rate base details have been reflected on Attachment
H.
e. Electric Loss Factor: The electric loss factor will
be 1.0437.
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f. Lost & Unaccounted For Gas: The factor for lost and
unaccounted for gas will be 1.025.
F. Agreed-to Dispositions of Specific Items and Other Conditions
1. Required Deferrals and Restorations of Electric Delivery
Revenues: As shown on the attached Electric Income
Statement, electric delivery revenues of $3.1 million in
RY1 will be deferred for restoration in RY3 without regard
for the amount of electric delivery revenues actually
received in any of the RYs. The deferrals and restorations
of revenues will be recognized for purposes of determining
regulatory earnings and regulatory return on common equity
(i.e., revenues in RY1 will be reduced by the deferred
amount and RY3 revenues will be increased by the restored
amount).
2. Required Utilization of Benefit Fund:
a. An amount of $42.5 Million will be removed from the
Benefit Fund and will be included as a credit to
electric rate base for the three Rate Years.
b. The credit will be applied to electric plant
transmission and distribution book depreciation
reserves in proportion to the relative book cost of
plant in service at August 31, 2001 for such plant
categories, subject to the provisions of item l3.b
of this Part II. F. of this Joint Proposal.
c. The $42.5 Million amount will be maintained as a
rate base credit after the end of RY3, subject to
other potential treatment by order of the
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Commission in a subsequent Central Hudson electric
rate case.
d. This $42.5 Million rate base credit amount will be
recognized in calculation of the achieved regulatory
rate of return on common equity for the electric
department.
3. Required Deferrals and Restorations of Gas Delivery
Revenues: Gas delivery revenues of $0.9 million will be
deferred in RY1 for restoration in RY3 without regard for
the amount of gas delivery revenues actually received in
any of the three RYs. The deferral and restoration of
revenues will be recognized for purposes of determining
regulatory earnings and regulatory rate of return on common
equity (i.e., revenues in RY1 will be reduced by the
deferred amount and RY3 revenues will be increased by the
restored amount).
4. Earnings Sharing:
a. There is a regulatory rate of return on common
equity deadband by department between 8.5% and
11.3%.
b. In the event that Central Hudson achieves a
regulatory rate of return on common equity above
11.3% in either the electric or gas department, the
earnings above 11.3% and up to 14.00% in such
department(s) will be shared 50/50 between the
Company and ratepayers. The ratepayer's portion of
such earnings in the electric department will be
added to the Benefit Fund and in the gas department,
deferred subject to further order of the Commission.
c. In the event that Central Hudson achieves a
regulatory rate of return on common equity above
14.00% in either the electric or gas department, the
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earnings above 14.00% in the electric department
will be added to the Benefit Fund and in the gas
department, deferred subject to further order of the
Commission. The 14.00% value is subject to
adjustment pursuant to Parts IX. F. and H.
5. Measurement of Achieved Regulatory Rate of Return on Common
Equity for Earnings Sharing Purposes:
a. Separate determinations of the achieved regulatory
rate of return on common equity for gas and electric
operations will be made annually, on a rate year
basis.
b. The achieved regulatory return on common equity will
be measured by department on the basis of Central
Hudson's actual capitalization for the period being
measured; provided, however, that if the actual
equity ratio in a given RY exceeds the applicable
rate year target equity ratio (RY1: 47%; RY2: 46%;
and RY3: 45%), then the target ratio for that RY
will be used.
c. The financial consequences of the Part VII Service
Quality Mechanisms, the Part V.A.2. Gas
Interruptible Sharing incentive and the Parts IX. F.
and H. incentives will be excluded in determinations
of regulatory rate of return on common equity.
d. Within 90 days following the end of RY1, RY2 and
RY3, Central Hudson
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shall provide Staff with a computation of achieved
regulatory rate of return on common equity by
department for the preceding RY period.
6. Reopener: Central Hudson is authorized to file for
increased rates for either the gas or electric department
anytime that the respective regulatory rate of return on
common equity for a trailing 12-month period, measured in
the fashion used for the annual RY determination, falls
below 8.5%.
7. Deferrals:
a. The Company is authorized to defer the following
kinds of items for recovery in the next electric or
gas, as appropriate, base rate change or other
Commission-ordered disposition:
(1) The Company is authorized to continue its use
of deferral accounting with respect to the
following expenses and costs and all other
expenses and costs for which Commission
authorization for deferral accounting is
currently effective whether by reason of
Commission order or policy of general
applicability or by reason of a Commission
determination with specific reference to the
Company:
(a) Pension Expense under Statement of
Financial Accounting Standards No. 87;
(b) Post Employment Benefits Other than
Pensions under Statement of Financial
Accounting Standards No.106;
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(c) Interest Costs on Variable Rate Debt;
(d) Incremental costs of litigation
regarding claims of exposure to
asbestos at Company facilities;
(e) Research and Development costs under
the Commission's Technical Release No.
17.
(2) Changes in accounting standards, subject to
the understanding that this specific
authority to defer is subject to such orders
as the Commission may issue that provide for
generic treatment of accounting practices;
(3) Changes in federal or state regulations;
(4) Force Majeure; and
(5) Others addressed herein.
b. All previously authorized uses of deferral
accounting continue and shall not terminate because
of the end of the term of this Joint Proposal.
c. Central Hudson retains the right to petition the
Commission for authorization to defer extraordinary
expenditures not otherwise addressed by this Joint
Proposal.
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d. Additional Deferral Provisions Related to Changes in
Federal, State or Other Tax Laws:
(1) The Signatories agree that the attached
Income Statements do not reflect
implementation of the tax law changes
resulting from the 2000 Legislative Session.
Accordingly, tax differences between the
prior State Tax Laws and the 2000 Legislative
enactments will be deferred, in accordance
with the Commission's Order of June 28, 2001
in Case 00-M-l556 for disposition as
determined subsequently by the Commission.
The deferral of state income taxes on
earnings shall be permitted up to the sharing
trigger level of 11.3%. The calculation of
regulatory earnings and achieved rate of
return on common equity for purposes of Parts
II.F.4 and 5 shall recognize the calculation
of state income tax on earnings.
(2) In addition, the company is authorized to
defer increases or decreases in costs related
to changes in federal, state and local tax
law or regulations for the period through RY
3.
8. Net deferred debit and credit balances for the electric
department items shown on Attachment D-2 have been
reflected in the determination of the Benefit Fund.
Deferred debit and credit offsets for the gas department,
using actual deferred balances at June 30, 2001 for the
deferred items listed on Attachment E, will be subject to
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balance sheet offset accounting to the extent necessary to
achieve a net of tax offset of zero.
9. Central Hudson is authorized to record electric or gas
revenue amounts post-June 30, 2004 subject to the
following:
a. The annual amount recorded by department may not
exceed the lesser of the revenue requirement
deficiency for RY3 shown on Attachment A or B, as
appropriate, or the amount of revenues needed by
department to provide a regulatory rate of return on
common equity of 10.5% for the 12-month "RY" periods
subsequent to June 30, 2004.
b. Estimated amounts of revenue will be recorded on a
monthly basis and adjusted to the final amount
within the above constraints in the last month of
the appropriate "RY" period.
c. The amount of revenues that are recorded may be
based on the measurement of earnings for periods of
time that are less than a twelve month RY period.
Earnings for partial periods will be calculated by
determining the level of earnings for the twelve
month period ending on the date new rates are
established and comparing it to the level of
earnings required to provide a 10.5% equity return.
If a deficiency in earnings results, the amount of
revenues recorded for the partial period will be
determined by the ratio of sales for the partial
period to the sales for the twelve month period
ending as of the date new
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rates are established.
d. Central Hudson will submit reports showing any
revenues recorded under this provision, and the
measurement of earnings used in the calculation of
the revenues recorded, for each annual period beyond
June 30, 2004 or period of time ending on the date
new rates take effect. These reports will be
submitted no later than 90 days from the end each
annual period or the date when new rates take
effect.
e. Central Hudson may charge the electric department
amounts accrued hereunder each month against the
Benefit Fund, subject to a subsequent final Order by
the Commission directing otherwise, in which event
Central Hudson shall be deemed to have fully
reserved its rights and nothing in this Joint
Proposal or Central Hudson's participation in it
shall be deemed to prejudice Central Hudson's
position.
f. Central Hudson may record a regulatory asset for the
gas department amounts accrued hereunder each month.
g. This authority continues until the earlier of June
30, 2006 or, with respect to electric department
revenue deferrals, the effective date of new base
electric rates as a result of a general electric
rate filing by Central Hudson and, with respect to
gas department revenue deferrals, the effective date
of new base gas rates as a
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result of a general gas rate filing by Central
Hudson.
10. Common Cost Allocation Factor: 85% electric, 15% gas.
11. Payment By Credit Card: The Company is authorized, but not
required, to accept payments for service by credit card
from residential and small commercial customers.
12. The Company's accounting for the sale of its stock symbol
is affirmed.
13. Depreciation:
a. The Company's electric, gas and common depreciation
studies and methods as presented in its initial
filing are accepted, except for depreciation of Gas
Distribution Mains, which will be based on an
Average Service Life of 85 years and a net salvage
factor of negative 60% (actual negative net salvage
in excess of negative 60% will be charged to
maintenance expense).
b. A method will be developed for reducing, in the next
rate case after the end of the term hereof, the
electric book depreciation reserve so that it
exceeds the theoretical depreciation reserve by no
more than 10 percent. Any Benefit Fund amounts
transferred to the book depreciation reserve will be
excluded from the measurement of the book to
theoretical reserve ratio.
14. The amounts shown on Attachment A, B and H will be used as
the rate allowances for purposes of revenue matching
accounting or other deferral purposes as appropriate.
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III. ELECTRIC ISSUES
A. The Company will implement a Reliability Improvement Program,
subject to the following conditions:
1. The Program will be funded up to a total of $20 Million
(pre-tax) over the period ending June 30, 2004.
2. Funding will be from the Benefit Fund.
3. Capital amounts funded will be removed from rate base and
treated as Contributions in Aid of Construction, and as a
result will carry a book balance of zero.
4. Expense amounts related to the capital projects are
included in the $20 Million allowance and will also be
funded from the Benefit Fund.
5. Outside contractors and labor will be used for the Program,
and none of the Benefit Fund-will be allocated to Company
labor expense.
6. Plans:
a. An Annual Plan will be developed and reviewed with
Staff before the start of RY2 for the remaining two
years of the program.
b. Central Hudson will review RY1 projects with Staff
on an expedited basis following approval of this
Joint Proposal.
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B. The outcomes of generic Commission proceedings such as the
Unbundling, Competitive Markets or Stand-by Rates Proceedings, and
any others during the term of this Joint Proposal that may affect
implementation of electric competition will be reflected
prospectively, subject to the understanding that any stranded or
similar costs resulting from any such proceedings, as determined
by the Commission, may be recovered out of the Benefit Fund to the
extent not inconsistent with any applicable Commission Order or,
if recovery out of the Benefit Fund is inconsistent with the
applicable Commission Order, Central Hudson shall be deemed to
have fully reserved its rights and nothing in this Joint Proposal
or Central Hudson's participation in it shall be deemed to
prejudice Central Hudson's position. Nothing in this Joint
Proposal shall be interpreted to preclude Central Hudson from
participating in any Commission proceeding in any manner it may
deem advisable.
IV. ELECTRIC RATE DESIGN
A. Unbundling: The revenue allocation, as shown in Attachment F will
be utilized to design rates, as amplified below.
B. Purchased Power Recovery ("PPR"):
1. Mechanism will vary by class;
2. Recover all commodity related costs using market prices;
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3. Use bimonthly averaging for bimonthly billed customers;
4. Include uncollectibles & working capital costs; and
5. Be determined and reconciled monthly.
C. Variable Cost Recovery ("VCR"): This mechanism will be reconciled
monthly and will recover the costs of ancillary services and the
variable costs and benefits of the Company's remaining generating
facilities.
D. Central Hudson has entered into a Transition Power Agreement
("TPA") with Dynegy that provides for the purchase and sale of
specified amounts of power to Central Hudson. The TPA was approved
by the Commission in an Order issued December 20, 2000 in Case
96-E-0909. In addition, Central Hudson has entered into a Purchase
Power Agreement ("PPA") with Constellation that provides for the
purchase and sale of specified portions of the output of Nine Mile
Point 2 ("NMP2"). The PPA has been filed with the Commission in
Case 01-E-0111 and that Case is currently pending before the
Commission. The prices in the TPA and PPA will not necessarily
equal the market prices and the differences are referred to herein
as "TPA and PPA Benefits." The TPA and PPA Benefits will be
apportioned to full service and delivery customers as follows:
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1. TPA and PPA Benefits will be apportioned among service
classes on the basis of each class's sales (kWh) as a
portion of the total system sales (kWh) in a given month;
2. Within a given class, TPA and PPA Benefits will be
apportioned among customers on the basis of relative usage
in a month as a portion of the total class usage;
3. Central Hudson shall have no obligation, other than as
specifically provided for herein, to track the amount of
any TPA and PPA Benefits by individual customer. In Service
Classifications 3 and 13, the TPA and PPA Benefits will be
subject to the constraints that:
(1) The total TPA and PPA Benefits credited to a
customer will not exceed the total Central
Hudson delivery charges for that customer in
a billing period; and
(2) Any TPA and PPA Benefits not received by a
customer due to operation of the above
constraint will be reallocated to that
customer in the subsequent billing period. In
any such reallocation, the constraint that
the total TPA and PPA Benefits not exceed the
total Central Hudson delivery charges in the
billing period will continue to be applicable
and may entail reallocation to subsequent
billing periods.
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E. Billing Format: Separate line items will be provided for the
following items:
1. PPR;
2. PPR under/over recovery;
3. VCR;
4. TPA/PPA Benefits; and
5. System Benefit Charge ("SBC").
F. Cost of Service Study & Revenue Allocation
1. The rate changes will be allocated as follows:
a. Service classifications which have a rate of return
below the lower tolerance level of 85% of the system
average would receive a minimum decrease of 0.5
times the average overall decrease.
b. Service classifications which have a rate of return
exceeding the upper tolerance of 115% of the system
average would receive a maximum decrease of 1.25
times the average overall decrease.
c. Application of these maximum and minimum decreases
results in revenues different from the rate decrease
revenue. This difference is allocated to the
unconstrained decreases for S.C. 1, S.C. 2, S.C. 5
and S.C. 13 -Transmission.
2. Peaker & Hydro Costs: The investment in combustion turbine
production plant is classified as demand-related. The
investment in hydroelectric production plant is classified
as energy-related.
3. The marginal customer cost for S.C. 1 is $23.67 per month
and for S.C. 2 is $32.79 per month.
4. Rate design for S.C. 13 will include flat energy charges, a
single basic monthly demand charge and a $500/month
customer charge.
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G. Customer Charges
1. S.C.l residential customer charges will increase from the
current $7.15 to $9.75 for RY1 and RY2 and to $11.50 after
RY2 until June 29, 2004. On June 30, 2004 the customer
charge will be increased to $12.00.
2. S.C.2 small commercial (non-demand) customer charge will
increase from the current $6.25 to $12 for RY1 to $13 for
RY2 and to $14 for RY3.
3. The above changes will be made on a revenue neutral basis
within the affected customer classes.
4. The remaining monthly customer charges are as follows: S.C.
2 Secondary Demand: $20.00; S.C. 2 Primary Demand: $80.00;
S.C. 3: $250 and S.C. 6: $12.00.
5. All customer charges agreed to herein are without prejudice
to the filing by the Company of superseding rate change
filings, effective after June 30, 2004.
H. Time of Use ("TOU") & Space Heating Rates
1. Continue offering S.C. 6 residential TOU.
2. Elimination of S.C. 12 commercial TOU.
3. Elimination of S.C. 2 heating discount.
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I. Charges for restoration of service to the same customer at the
same meter location within twelve months of discontinuation of
service will be as shown below.
During Normal Work Hours:
Without Line or Gas Crew $ 20.00
With Line or Gas Crew $100.00
Outside Normal Work Hours:
Without Line or Gas Crew $ 40.00
With Line or Gas Crew $140.00
J. Treatment of Central Hudson's NMP2 Costs:
1. The existing ratemaking for Central Hudson's NMP2 costs,
approved by the Commission effective February 1, 2001
includes two components: a Competitive Transition Charge
("CTC") (reflecting property taxes and certain O&M costs),
and variable cost recovery through the existing ESC.
2. Upon the effectiveness of the rates produced by this Joint
Proposal, Central Hudson's NMP2 costs will be recovered
through three components: a CTC, the PPR and the VCR.
a. Until such time as the Commission approves the
pending PSL ss.70 asset transfer and the closing for
Central Hudson's NMP2 interests takes place:
(1) the CTC will recover NMP2 property tax and
fixed O&M elements (hydro and GT costs will
be recovered through base rates);
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(2) The PPR will recover the market price of
Central Hudson's share of the power produced
at NMP2; and
(3) The VCR will recover transmission costs, ISO
charges, and recover/pass back the difference
between the market price and the variable
production costs of Central Hudson's share of
NMP2 output.
b. After the Commission approves the pending PSL ss.70
asset transfer and the closing for Central Hudson's
NMP2 interests takes place:
(1) The CTC will cease.
(2) The PPR will reflect the Market Price of
Central Hudson's share of the power produced
at NMP2 under the NMP2 PPA.
(3) The VCR will recover transmission costs and
ISO charges.
(4) The TPA/PPA Benefits will recover/pass back
the difference between the market price and
the costs of the PPA for Central Hudson's
share of NMP2 output.
V. GAS RATE ISSUES
A. Revenue Sharing
1. The imputation for interruptible and electric generation
sales is set at $1,900,000.
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2. Accounting:
a. Each August, the Company will reconcile the annual
IT profit received in the prior RY. Profit realized
by the Company pursuant to this mechanism will be
excluded from any determination of achieved
regulatory rate of return on common equity.
(1) If the Company's IT profits exceed the annual
imputation of $1,900,000, the sharing
mechanism will be as follows:
(a) From $1,900,000 up to $2,299,999:
Profit will be shared in an 85%
customer/15% shareholder ratio;
(b) Profit above $2,300,000 will be shared
in an 80% customer/20% shareholder
ratio.
(2) If the Company's IT profits are less than the
annual imputation of $1,900,000, the sharing
mechanism will be as follows:
(a) From $0 up to $1,499,999 in IT
revenue, the short-fall below
$1,900,000 will be borne by the
Company;
(b) From $1,500,000 up to $1,899,999 the
short-fall below $1,900,000 will be
shared in an 15% shareholder/85%
customer ratio.
b. In addition, the Company shall be permitted to
attempt to minimize
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potential monthly short-falls or over collections
through the Gas Supply Charge ("GSC"):
(1) Each month the Company will compare the
profit received from customers taking service
under Service Class NOS. 8, 9 and 14 ("IT
Profit": to $158,333 (1/12 of the annual
imputation of $1,900,000), and
(2) If the IT Profit differs significantly from
the monthly imputation, the Company may
refund or surcharge, as appropriate, through
the GSC in a subsequent month.
B. Agreed-to Dispositions of Specific Gas Items:
1. Gas Manufacturing Site Remediation
a. Write off Newburgh site costs from Benefit Fund.
b. Case 95-M-0874 requirements remain in force for
Newburgh site.
2. The prudence of the Company's gas purchasing policies and
load management practices prior to the date of this Joint
proposal have been reviewed and have not been challenged in
these proceedings.
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VI. GAS RATE DESIGN
A. Unbundling and GSC
1. The GSC mechanism will recover all commodity related and
upstream pipeline demand costs.
2. The GSC will be determined monthly and reconciled annually.
3. The GSC will include uncollectibles, working capital and
carrying costs on cash working capital requirements and
materials and supplies.
B. S.C. 9 Customers Eligible for S.C. 11: The Company's current rate
design methodology, which uses the load factors of existing
customers to establish the price caps, will remain in effect.
C. Minimum Charge and Tail Blocks: The minimum charges in firm
Service Classification Nos. 1,2,6,12 and 13 are increased to
$7.20. To offset the increase in the minimum charge, the second
block of S.C.1 and 12 has been reduced and the third block of S.C.
2, 6 and 13 has been reduced. No rate changes are made to current
tail block prices.
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VII. SERVICE QUALITY MECHANISMS
A. Customer Service Quality Program:
1. Twenty-five basis point total potential penalty on combined
Company basis, per calendar year commencing January 1,
2002.
a. Of the twenty-five basis point total, twelve and
one-half basis points are for the PSC Complaint Rate
(12.5 basis points) and
b. twelve and one-half basis points (12.5 basis points)
are for the Customer Satisfaction Index ("CSI").
2. PSC Complaint Rate:
a. Targets and penalties for the PSC Complaint Rate
(chargeable complaints per 100,000 customers, based
on a 12-month rolling average at the end of each
performance period) follow:
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Penalty To a PSC
Basis From a PSC Complaint Complaint
Points Rate of Rate of
----------------------------------------------------
None 0 <6.0
2.5 (is greater than or equal to) 6.0 <6.5
5.0 (is greater than or equal to) 6.5 <7.0
7.5 (is greater than or equal to) 7.0 <7.5
10.0 (is greater than or equal to) 7.5 <8.0
12.5 (is greater than or equal to) 8.0
b. The PSC Complaint Rates set forth above are
predicated upon existing PSC practices and
procedures for chargeable complaints per 100,000
customers. In the event of a change to those
practices and procedures, the Signatories will
discuss in good faith whether alteration of the
above target and penalty levels are appropriate to
maintain the incentive to the Company at levels
comparable to those above. Any disputes will be
referred to the Commission.
3. CSI:
a. The CSI will be based on the calculations performed
by Central Hudson consistent with the procedures
adopted as a result of Case 96-E-0909.
b. Targets and penalties for the CSI follow:
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Basis
Point
Penalty CHGE CSI From To
-------------------------------------------------
None (is greater than or equal to) 83 NA
3.125 (is greater than or equal to) 82 <83
6.25 (is greater than or equal to) 8l <82
9.375 (is greater than or equal to) 80 <81
12.5 Below 80
4. For purposes of this Joint Proposal, the performance
periods are the calendar years ending December 31, 2002 and
2003 and the six months ending June 30, 2004 (for which the
basis point penalties will be penalties will be halved).
5. The "Appointments Kept" incentive remains at $20 per missed
appointment.
B. Electric Reliability
1. Twenty-five (25) basis point total potential penalty on
electric operations, per calendar year commencing January
1, 2002.
a. Of the twenty-five basis point total, twelve and
one-half basis points (12.5 basis points) are for
SAIFI and
b. twelve and one-half basis points (12.5 basis points)
are for CAIDI.
2. SAIFI indices and penalties, as shown below:
>1.10 6.25 basis point penalty
>1.20 12.5 basis point penalty
3. CAIDI indices and penalties, as shown below:
>2.10 6.25 basis point penalty
>2.20 12.5 basis point penalty
27
4. The SAIFI and CAIDI indices are based on electric service
interruptions that are not related to major storms.
a. The initial SAIFI index levels will be reduced by 2%
from 2002 to 2003 and by 4% from 2003 to 2004.
b. The Company may petition for appropriate adjustment
to the final CAIDI and SAIFI indices for each
performance period to recognize the effects, if any,
of Outage Management System ("OMS") implementation
or interventions by the ISO or similar authority
causing service interruptions.
5. For purposes of this Joint Proposal, the performance
periods are the calendar years ending December 31, 2002 and
2003 and the six months ending June 30, 2004 (for which the
basis point penalties will be halved).
6. Penalties will be calculated with respect to electric
operations.
C. Gas Reliability
1. Number of One-Call Ticket Mis-marks per Thousand One Call
Tickets.
28
Basis Point From To
Penalty Mis-marks/1000 of Mis-marks/1000 of
--------------------------------------------------------
Zero 0 1.25
2 1.26 1.45
3 1.46 1.65
6 1.66 or higher
2. Penalties will be calculated with respect to gas
operations. Mis-marks will be determined based on Central
Hudson's current procedures, including recognition of the
Tolerance Zone as defined in 16 NYCRR Part 753-1.2(t).
3. The measurement periods will be the calendar years ending
December 31, 2002 and 2003 and the six months ending June
30, 2004. The basis point penalty applicable to the six
month period ending June 30, 2004 will be one-half of that
set forth in the above table.
D. Gas Leak Management:
1. Applicable to Type 3 leaks only;
2. Penalty-only plan over the three year term. No penalty for
Type 3 leak inventory levels at or below 362 at December
31, 2002, 337 at December 31, 2003 or 325 at June 30, 2004
or in any calendar year in which 140 or more Type 3 leak
repairs are completed. In addition, no
29
penalty will be applicable to the six months ending June
30, 2004 if 70 or more Type 3 leak repairs are completed in
that time period.
3. A penalty of 3 basis points is applicable to gas operations
in any calendar year in which 140 Type 3 leak repairs are
not completed and the specified Type 3 inventory level is
not achieved (362 at Y.E. 2002 or 337 at Y.E. 2003). A
penalty of 1.5 basis points is applicable to gas operations
in the six months ending June 30, 2004 if 70 Type 3 leak
repairs are not completed and the specified Type 3
inventory level (325) is not achieved.
4. If, in any year during the term of this Joint Proposal the
target level for Type 3 leak inventory is not met, but a
penalty is not due because 140 Type 3 leak repairs were
completed, the leak inventory target level for the
subsequent year shall be 25 less than the actual ending
inventory level for that prior period.
E. Central Hudson will, by March 31, 2003 and 2004 and by September
30, 2004, file a report or reports on its performance under each
of the above incentive programs during the prior performance
period, with the format and contents to be developed in
collaboration, commencing on or about November 1, 2001, between
the Company and Staff.
F. The Service Quality Incentive Plan of Case 96-E-0909 is extended
30
from July 1, 2001 to and including December 31, 2001.
VIII. LOW INCOME PROGRAM
A. The Company will implement a Low Income Program consistent with
Attachment G.
B. The costs of the program, funded out of the revenue requirements,
will be limited to the expense allowances shown on Attachments A
and B. In the event that the costs of the program differ from
those levels, the difference will be deferred and, after review,
1. Any electric shortfall will be added to the Benefit Fund
and any gas shortfall will be returned to customers through
the GSC and;
2. Any electric excess will be recovered from the Benefit Fund
and any gas EXCESS will be recovered through the GSC.
C. Commencing on or about November 1, 2001, the Company and Staff
shall collaborate in the development of any program reporting
requirements, with the Commission resolving any disputes over
those requirements.
IX. COMPETITIVE ISSUES
A. Consolidated Bills will be made available per the May 18, 2001
31
Billing Proceeding Order.
B. Single Bill: Central Hudson will pursue offering a Single Bill
using the Rate Ready format. In order to utilize this option, each
ESCO OR marketer must provide Central Hudson monthly with the
Central Hudson customer account number and a billing rate per kWh
or CCF for each customer in sufficient time in advance (minimum
period to BE established) of the billing dates set forth on
Central Hudson's web site. Central Hudson will comply with the
criteria established in the Billing Proceeding Order and ED1
Proceeding related to single bills.
C. Ancillary Services: The Company will bill all delivery customers
for ancillary services commencing three months after Commission
approval of this Joint Proposal. This non-by-passable charge will
be collected from customers through the Variable Cost Recovery
factor. Central Hudson will reimburse ESCOs for ancillary service
charges incurred to serve Central Hudson load.
1. Each ESCO serving load in Central Hudson's retail access
program must provide the Company with a copy of its NYISO
bill which identifies the ancillary services for the ESCO's
Central Hudson load served (PTID) within a day of billing
by the NYISO. The invoice provided by the ESCO must detail
the load (kWh), rate for each service and total amount
requested for reimbursement.
32
2. Bills and credits issued by the NYISO to the ESCO for prior
periods must also be provided to Central Hudson in the
month received by the ESCO. Central Hudson will be
authorized to collect all such amounts through its VCR.
Reimbursement to ESCOs by Central Hudson for ancillary
service charges will be made prior to the date ESCOs are
required to pay the NYISO for such charges.
3. The Company reserves the right to file a petition with the
Commission to modify this process, including potentially
terminating billing or reimbursing ESCOs for NYISO
ancillary services.
D. Electric Back Out Credits: Credit levels would be set at 0.5 mills
per kWh for S.C. 13 customers; 2.0 mills per kWh for S.C. 3
customers; 3.0 mills per kWh for S.C. 2 demand customers; and 4
mills per kWh for S.C. 2 non-demand, S.C. 6 and S.C. 1 customers
pending the outcome of the Unbundling Proceeding and are subject
to being superseded by the Unbundling Proceeding as provided for
in Part III.B. hereof. Prior to that time, the cost of the credits
will be recovered from the Benefit Fund, subject to a penetration
limit of 20% of electric customers. If it appears likely that the
20% penetration level will be exceeded, the penetration level and
recovery mechanism will be reviewed.
E. Gas Merchant Back Out Credit: The gas merchant function back-out
credit will be set at $.15 per mCf pending the outcome of the
Unbundling Proceeding, and is subject to being superceded by the
Unbundling Proceeding as provided for in Part III.B hereof. Prior
to that
33
time, the cost of the credit will be recovered through the GSC,
subject to a penetration limit of 20% of gas customers. If it
appears likely that the 20% penetration level will be exceeded,
the penetration level and recovery mechanism will be reviewed.
F. ESCO & Marketer Satisfaction Mechanism
1. ESCO/Marketer Satisfaction Survey: After consultation
between Staff and the Company, a survey will be developed
as a baseline for an incentive mechanism.
2. The survey metrics would include the performance of the
Company in satisfying the terms of the UBP and other
operational arrangements (e.g., GTOP) between it and ESCOs
(electric) and marketers (gas) . The survey should include
relevant questions for both ESCOs and gas marketers.
3. The survey would be implemented on an annual basis by an
objective third party selected after consultation
commencing on or about November 1, 2001 between Staff and
the Company.
4. Prior to implementation of the survey, Staff and the
Company will agree to a threshold number of participating
marketers as a basis for implementation of an incentive
mechanism. If the threshold number of marketers
participate, an incentive allowing the Company to receive
up to 10 basis points of earnings in excess of 11.3% on a
combined
34
Company basis will be implemented after the baseline
results are available. In this event, the overall earnings
cap will also be increased by ten basis points.
5. Once the results of the satisfaction survey are available,
the company will have 60 days to report to Staff and
interested parties on how it plans to address marketer
concerns, if any, that were expressed in the survey.
G. The Company will consult with Staff concerning the suitability of
potential aggregation initiatives within the Central Hudson
service territory, subject to the funding provisions of Part X.G.
H. Electric and Gas Outreach and Education Mechanisms
1. Improvements in outreach and education (O&E), to increase
customer awareness and understanding of energy competition,
will be measured by using Central Hudson's existing
residential survey.
2. The survey will be enhanced for better measurement of
awareness and understanding, according to a list of
criteria that will be established after consultation
commencing on or about November 1, 2001 between the Company
and Staff. A method to evaluate the awareness and
understanding of energy competition among small commercial
customers will be established.
35
3. An incentive allowing the Company to receive up to 10 basis
points of earnings in excess of 11.3% on a combined company
basis will be implemented, based on criteria, developed
through consultation commencing on or about November 1,
2001 between the Company and Staff, for measuring
improvements in customer awareness. In this event, the
overall earnings cap will be increased by 10 basis points.
I. Small Customer Aggregation: The potential funding of aggregation
initiatives will be considered in the Benefit Fund Review process.
J. ESCO/marketer Ombudsman: The company will designate a
vice-president level ombudsman to address ESCO/marketers'
unresolved concerns and serve as a liaison with marketers.
X. BENEFIT FUND
A. The total amount of the Benefit Fund is currently estimated at
$164 million, including an assumed $36.5 million in net gain from
a sale of NMP2, or $127.5 Million excluding the estimated NMP2
gain. The components have been shown in Attachment D-l.
B. The Signatories have agreed upon the following general approach:
Allocate a portion of the fund to "Identified Uses" and reserve
the
36
remainder, future NMP2 gain and any unutilized portion of the
Identified Uses to annual collaborations. The Identified Uses are
further defined as "Quantified Identified Uses" and
"Non-Quantified Identified Uses."
C. The "Quantified Identified Uses" of the Benefit Fund are (net of
tax):
1. Rate base offset - $42.5 Million;
2. Gas site remediation - $10 Million;
3. Reliability Improvement Program - $13 Million; and
4. Refunds: $l5 Million per RY.
D. The Non-Quantified Identified Uses of the Benefit Fund are:
1. Other items provided for in this Joint Proposal, including
possible additional customer refunds, offset to potential
post-June 30, 2004 electric rate increases, back out
credits and future stranded or similar costs subject to the
provisions of Part III.B hereof; and
2. Economic Development - to be developed and dispensed in
accordance with below discussion.
E. Refunds: The total net of tax amounts for the three RYs of $45
Million, as shown on Attachment D-l, will be refunded to customers
through a per kWh credit, commencing in the month following the
Commission's approval of this Joint Proposal. The credit will be
developed from the total RY billing units, prorated for the total
number of months until
37
June 30, 2004 following the Commission's approval of this Joint
Proposal. Central Hudson will track and reconcile the amounts
credited. In the event that the entire $45 Million is not credited
prior to June 30, 2004, the un-dispensed credit will be carried
forward subject to further order of the Commission.
F. A carrying charge at an annual rate equal to the pretax-rate of
return set forth on Attachment C will be applied monthly to the
net remaining balance in the Benefit Fund.
G. Other Potential Uses of Net Benefit Fund
1. Potential uses include possible future use for price spike
mitigation; for small customer aggregation efforts; and to
fund such other competitive-related initiatives as the
Commission may approve.
2. These uses would be addressed in the Benefit Fund Review
discussed below.
3. Benefit Fund Review Process: On or about January 15, 2002,
and 2003 a collaborative effort will commence on the use of
the remaining Benefit Pool amounts not otherwise allocated
to specific purposes. The collaborative will be completed
and reported to the Commission by April 1, 2002 and 2003.
The Commission will expedite its review of the
Collaborative Report (and any dissents).
38
H. Economic Development
1. An Economic Development Program will be established and
funded from the Benefit Pool in accordance with the
procedure set forth below. The program's purposes would be
to encourage the relocation, growth, expansion, and
retention of business customers in the Company's service
territory and include consideration of any situations in
which reductions in employers' substation costs will lead
to employee retention.
2. The administration of the program would be facilitated by
Staff, through consultation commencing on or about November
1, 2001 among the Company, the Empire State Development
Authority, local government officials and interested
parties. Tariff provisions, guidelines and procedures would
be developed as appropriate in that consultation and would
be submitted to the Commission for approval.
3. Existing electric programs will be terminated with the
exception of the Revitalization Rate.
4. Revitalization Rate:
a. Current electric customers will receive their
existing discounts until the time set for expiration
in their existing agreements.
39
b. For new customers, a rate discount would be offered
on the delivery rate for those who meet the existing
program's criteria.
c. The discounts would be set at percentage levels
comparable to those in the existing program, but
applied to the delivery prices.
d. The discounts will be funded from the Benefit Fund.
e. Customers receiving the rate would be contacted in
writing 6 months prior to the end of their
Revitalization Rate term informing them of the
expiration and providing them with a contact at the
Company to answer any questions or concerns.
XI. CONDITIONS OF JOINT PROPOSAL
A. This Joint Proposal is intended by the Signatories to be a
complete resolution of all issues in Cases 00-E-1273 and
00-G-l274. Each Signatory is obliged to support the Joint Proposal
before the Commission. The Signatories to the Joint Proposal agree
that the provisions of the Joint Proposal are, in aggregate, a
reasonable resolution of each of the proceedings.
40
B. It is understood that each provision hereof is in consideration
and support of all the other provisions, and each Signatory has
expressly conditioned its support upon the acceptance of this
Joint Proposal in its entirety by the Commission. In the event
that the Commission proposes to alter any provision of the Joint
Proposal, no Signatory has any further obligation relative to the
Joint Proposal other than the obligation to discuss in good faith
with the other Signatories whether any such alteration is
acceptable to it. In addition, Staff will make its best efforts to
present to the Commission by September 25, 2001, the Company's
Petition of May, 2001, as updated, in Case 01-M-0323.
C. In the event that the Commission alters any provision of the Joint
Proposal, each Signatory will be deemed to have fully reserved its
rights to contest the altered Joint Proposal, and any such
alteration. In the event that the Commission fails to adopt this
Joint Proposal according to its terms, then each Signatory shall
be free to pursue its respective positions in this proceeding,
without prejudice, upon reasonable notice to the other
Signatories. This Joint Proposal is an integrated whole, with each
provision in consideration for, in support of, and dependent on
the others. Thus, if the Commission does not approve this Joint
Proposal in its entirety without modification, each of the
Signatories reserves the right to withdraw its participation and
support by serving written notice on the Commission and the other
Signatories and, if necessary, to litigate, without prejudice,
41
any or all issues as to which such signatory agreed in this Joint
Proposal; in such event, any such Signatory shall not be bound by
the provisions of this Proposal, as executed or as modified.
D. In the event of any disagreement over the interpretation of this
Proposal or the implementation of any of the provisions hereof,
which cannot be resolved informally among the Signatories, such
disagreement shall be resolved in the following manner: The
Signatories shall promptly convene a conference and in good faith
shall attempt to resolve such disagreement. If any such
disagreement cannot be resolved by the Signatories, a Signatory
may petition the Commission for relief on a disputed matter.
E. This Joint Proposal represents a negotiated agreement and
settlement and, except as otherwise expressly stated herein, none
of the Signatories shall be deemed to have approved, agreed to, or
consented to any principle, methodology, or interpretation of law
underlying or supposed to underlie any provision hereof, and this
Joint Proposal shall not be cited or relied upon with respect to
any matters other than those specifically addressed herein.
F. The Signatories recognize that certain provisions hereof require
that actions be taken in the future to effectuate fully the
agreements and compromises set forth in this Joint Proposal.
Accordingly, each Signatory agrees to cooperate with each other
Signatory in GOOD faith in taking such actions.
G. Survival of Conditions: All reservations of rights of any
Signatory (including, but not limited to, Parts XI.A. through
XI.F., inclusive), the continuation of deferral accounting
authority, the post-June
42
30, 2004 revenue deferral provisions, the provision concerning
development of a method for reducing the book to theoretical
depreciation reserve, and the Benefit Fund provisions shall
survive the June 30, 2004 term of this Joint Proposal.
H. The Supplemental Environmental Assessment Form attached hereto as
Appendix I accurately describes the potential environmental
impacts, if any, that could result from implementation of the
terms of this Joint Proposal, and the Commissions' determination
of significance regarding this Joint Proposal should be the
adoption of a negative declaration.
I. All titles, subject headings, section titles and similar items are
provided for the purpose of reference and convenience only and are
not intended to affect the meaning, content or interpretation of
this Joint Proposal.
J. The Commission reserves the authority to act on the level of the
company's base electric and gas rates in the event of unforeseen
circumstances that, in the Commission's opinion, have such a
substantial impact on the range of earnings levels or equity costs
envisioned by this Joint Proposal as to render the company's
return unreasonable or insufficient for the provision of safe and
adequate service at just and reasonable rates and in the event
that the Commission exercises such authority as it possesses in
that regard, each Signatory reserves its rights and no Signatory
shall be bound or prejudiced by its entry into, or performance
under, this Joint Proposal.
K. Submission of Settlement: This Joint Proposal is being executed
43
in counterpart originals and shall be binding on each Signatory.
Each person executing this Joint Proposal represents by his or her
signature that he or she has full authority to bind his or her
principal. The Signatories hereto agree to submit this Joint
Proposal to the Commission and individually to support and request
adoption by the Commission of their mutual settlement as set forth
herein.
WHEREFORE, this Joint Proposal has been agreed to by and among each of
the following, who, by its signature, each represents that it is fully
authorized to execute this Joint Proposal and, if executing this Joint Proposal
in a representative capacity, that it is fully authorized to execute it on
behalf of its principals.
44
SIGNATURE PAGE
The undersigned party to Public Service Commission Case Nos. 00-E-1273
and 00-G-1274 has participated in the negotiations among the parties which led
to the Joint Proposal dated August 15, 2001 and agrees to the provisions of such
Joint Proposal.
Central Hudson Gas & Electric Corporation
By: /s/ ARTHUR R. UPRIGHT
------------------------------------------
Arthur R. Upright
Dated: August 15, 2001
SIGNATURE PAGE
THE UNDERSIGNED PARTY TO PUBLIC SERVICE COMMISSION CASE NOS. 00-E-1273
AND 00-G-1274 HAS PARTICIPATED IN THE NEGOTIATIONS AMONG THE PARTIES WHICH LED
TO THE JOINT PROPOSAL DATED AUGUST 15, 2001 AND AGREES TO THE PROVISIONS OF SUCH
JOINT PROPOSAL.
Consumer Protection Board
By: /s/ C. ADRIENNE RHODES
----------------------
C. Adrienne Rhodes
Dated: August 17, 2001
SIGNATURE PAGE
The undersigned party to Public Service Commission Case Nos. 00-E-1273
and 00-G-l274 has participated in the negotiations among the parties which led
to the Joint Proposal dated August 15, 2001 and agrees to the provisions of such
Joint Proposal.
Multiple Intervenors
By: /s/ MICHAEL B. MAGER
----------------------------
Michael B. Mager, Esq.
Couch White, LLP
Attorneys for Multiple Intervenors
Dated: August 17, 2001
SIGNATURE PAGE
The undersigned party to Public Service Commission Case Nos. 00-E-l273
and 00-G-1274 has participated in the negotiations among the parties which led
to the Joint Proposal dated August 15, 2001 and agrees to the provisions of such
Joint Proposal.
Staff of the Department of Public Service
By: /s/ LEONARD VAN RYN
--------------------------------------
Leonard Van Ryn
Dated: August 20, 2001
SIGNATURE PAGE
The undersigned party to Public Service Commission Case Nos. 00-E-l273
and 00-G-l274 has participated in the negotiations among the parties which led
to the Joint Proposal dated August 15, 2001 and agrees to the provisions of such
Joint Proposal.
Strategic Power Management, Inc.
By: /s/ DANIEL P. DUTHIE
----------------------------------
Daniel P. Duthie
Vice President and General Counsel
Dated:August 16, 2001
LIST OF ATTACHMENTS
1. Attachment A: Electric Income Statements
2. Attachment B: Gas Income Statements
3. Attachment C: Cost of Capital, Debt and Preferred Redemption
Costs and Related Expenses
4. Attachment D-l: Estimate of Benefit Fund Balance
5. Attachment D-2: Electric Department Deferred Items Included
on Attachment D-l
6. Attachment E: Gas Department Deferred Items for Balance
Sheet Offset
7. Attachment F: Electric Department Revenue Allocation
8. Attachment G: Low Income Program
9. Attachment H: Rate Base Details, Gas and Electric
10. Attachment I: Supplemental Environmental Assessment Form
CASES 00-E-1273 and 00-G-1274 ATTACHMENT A
Filing by: CENTRAL HUDSON GAS & ELECTRIC CORPORATION
Amendments to Schedule P.S.C. No. 15 - Electricity
Original Leaf No. 206.1
First Revised Leaves Nos. 4, 5, 14, 94, 104, 105, 106, 107,
108, 123, 124, 136, 164, 165, 168, 169, 170, 171, 172, 185, 186, 199,
200, 204, 209, 210, 211, 213, 215, 217, 219, 225, 237, 238, 239, 240,
241, 242, 243, 244, 245, 246, 247, 253, 254, 255, 256, 273, 274, 275,
276, 277, 278, 279, 281, 282, 283, 284, 285, 286, 287, 288, 289, 290,
291, 292, 293, 294, 295, 296, 297, 298, 299, 300, 301, 302, 303, 304,
305, 306, 307, 308, 309, 310, 311, 312, 313, 314, 315, 316, 317, 318,
319, 320, 321, 322, 323, 324, 325, 326, 327, 328
Second Revised Leaves Nos. 166, 205, 206, 212, 216, 218, 220
Supplement No. 2
Supplement No. 3
Supplement No. 10
Supplement No. 12
Supplement No. 13
Amendments to Schedule P.S.C. No. 12 - Gas
First Revised Leaves Nos. 4, 63, 68, 69, 71, 72, 148, 149, 150, 151,
152, 153, 154, 158, 188, 193
Second Revised Leaves Nos. 70, 73
Third Revised Leaves Nos. 186, 191
Fourth Revised Leaf No. 159
Supplement No. 2
Supplement No. 4
Supplement No. 7
Supplement No. 8
Supplement No. 9
ATTACHMENT A
CENTRAL HUDSON GAS & ELECTRIC CORPORATION
CASE NOS. 00-E-1273 & 00-G-1274
JOINT PROPOSAL - ELECTRIC REVENUE REQUIREMENTS
SETTLEMENT PERIOD $(000)
OPERATING REVENUES: RY1 RY2 RY3
-------- -------- --------
Own Territory Base Revenues 153,000 154,407 155,633
Revenue (Surplus)/Deficiency (3,072) (0) 3,072
-------- -------- --------
Total Revenue Requirement 149,928 154,407 158,706
NMP2 CTC 21,302 21,309 21,316
Other Operating Revenues 6,093 5,938 5,831
-------- -------- --------
Total Operating Revenues 177,323 181,654 185,853
OPERATING EXPENSES:
Non Fossil Production Maintenance 187 191 195
Right of Way Maintenance 4,838 4,944 5,123
NMP2 Operations 16,309 16,316 16,323
Direct Labor 37,996 39,332 39,674
Research and Development 1,667 1,692 1,747
Expenses Projected Based on Inflation 8,899 9,087 9,268
Miscellaneous General Expenses 1,895 1,922 1,949
Transportation Depreciation 1,434 1,519 1,605
Fringe Benefits 4,666 4,825 4,869
Other Post Employee Benefits (OPEB) 1,429 1,429 1,429
Pension Plan (10,210) (10,210) (10,210)
Major Rents 1,974 1,986 1,998
Uncollectible Accounts 784 791 798
Regulatory Commission Expenses 1,278 1,305 1,333
Data Processing Costs 2,719 2,631 2,674
Other Operating Insurance 543 554 567
Telephone 1,377 1,406 1,434
Legal Services 1,434 1,464 1,493
Special Services 951 971 991
Injuries and Damages 1,465 1,496 1,526
Storms Expense 2,900 2,961 3,023
Environmental 244 249 254
Low Income Program 306 530 995
Expenses Allocated to Affiliates (506) (506) (506)
-------- -------- --------
Total Operating Expenses 84,579 86,885 88,552
-------- -------- --------
OTHER DEDUCTIONS:
NMP2 Decommissioning 999 999 999
Taxes Other Than Income Taxes:
Property 16,450 17,112 17,797
Revenue 6,805 6,812 6,842
Payroll 2,911 2,989 3,054
Other 2,125 2,088 2,052
NMP2 3,061 3,061 3,061
Depreciation 19,035 19,888 20,696
-------- -------- --------
Total Other Deductions 51,386 52,949 54,501
-------- -------- --------
Federal Income Tax 12,728 12,770 12,911
-------- -------- --------
Total Operating Revenue Deductions 148,693 152,604 155,964
-------- -------- --------
Operating Income 28,630 29,050 29,889
-------- -------- --------
Rate Base 380,215 386,309 399,582
Rate of Return 7.53% 7.52% 7.48%
Return on Common Equity 10.30% 10.30% 10.30%
ATTACHMENT B
CENTRAL HUDSON GAS & ELECTRIC CORPORATION
CASE NOS. 00-E-1273 & 00-G-1274
JOINT PROPOSAL - GAS REVENUE REQUIREMENTS
Settlement Period $(000)
OPERATING REVENUES: RY1 RY2 RY3
------------------ -------- -------- --------
Own Territory Base Revenues 36,597 37,007 37,378
Revenue (Surplus)/Deficiency (885) (0) 885
-------- -------- --------
Total Revenue Requirement 35,712 37,007 38,263
Interruptible Sales to Generators 1,900 1,900 1,900
Other Operating Revenues 2,077 2,002 1,921
-------- -------- --------
Total Operating Revenues 39,689 40,909 42,084
OPERATING EXPENSES:
Labor 9,007 9,285 9,632
Research and Development 331 303 303
Expenses Projected Based on Inflation 2,302 2,350 2,399
Miscellaneous General Expenses 287 291 294
Transportation - Depreciation 307 325 344
Fringes 986 1,009 1,029
Other Post Employee Benefits (OPEB) 307 307 307
Pension Plan (2,273) (2,273) (2,273)
Environmental 43 44 44
Major Rents 123 125 127
Uncollectible Accounts 210 220 227
Regulatory Commission Expenses 258 263 269
Data Processing Costs 423 481 526
Other Operating Insurance 90 92 94
Telephone 201 206 210
Legal Services 377 385 392
Special Services 171 175 178
Injuries and Damages 374 382 390
Low Income Program 48 82 153
Expenses Allocated to Affiliates (89) (89) (89)
-------- -------- --------
Total Operating Expenses 13,483 13,963 14,556
-------- -------- --------
OTHER DEDUCTIONS:
Taxes Other Than Income Taxes:
Property 4,559 4,737 4,923
Revenue 1,598 1,661 1,719
Payroll 641 659 672
Other 277 280 283
Depreciation 5,757 6,013 6,227
-------- -------- --------
Total Other Deductions 12,832 13,350 13,824
-------- -------- --------
Federal Income Tax 4,361 4,457 4,511
-------- -------- --------
Total Operating Revenue Deductions 30,676 31,770 32,891
-------- -------- --------
Operating Income 9,013 9,139 9,193
-------- -------- --------
Rate Base 119,695 121,525 122,904
Rate of Return 7.53% 7.52% 7.48%
Return on Common Equity 10.30% 10.30% 10.30%
ATTACHMENT C
SHEET 1 OF 3
CENTRAL HUDSON GAS & ELECTRIC CORPORATION
CASE NOS. 00-E-1273 AND 00-G-1274
JOINT PROPOSAL - COST OF CAPITAL
$(000)
PRE-TAX
RATE YEAR 1: WEIGHTED WEIGHTED
- ------------ AMOUNT RATIO COST COST COST
------ ----- ---- -------- --------
Long Term Debt 257,887 48% 5.09% 2.46% 2.46%
Customer Deposits 4,436 1% 6.00% 0.05% 0.05%
Preferred Stock 21,005 4% 4.61% 0.18% 0.28%
Common Equity 251,153 47% 10.30% 4.84% 7.45%
------- --- ----
Total Capitalization 534,481 100% 7.53% 10.23%
------- --- ---- -----
PRE-TAX
RATE YEAR 2: WEIGHTED WEIGHTED
- ------------ AMOUNT RATIO COST COST COST
------ ----- ---- -------- --------
Long Term Debt 268,450 49% 5.15% 2.54% 2.54%
Customer Deposits 4,470 1% 6.00% 0.05% 0.05%
Preferred Stock 21,042 4% 4.61% 0.18% 0.28%
Common Equity 251,176 46% 10.30% 4.75% 7.31%
------- --- ----
Total Capitalization 545,138 100% 7.52% 10.17%
------- --- ---- -----
PRE-TAX
RATE YEAR 3: WEIGHTED WEIGHTED
- ------------ AMOUNT RATIO COST COST COST
------ ----- ---- -------- --------
Long Term Debt 281,778 50% 5.21% 2.63% 2.63%
Customer Deposits 4,412 1% 6.00% 0.05% 0.05%
Preferred Stock 21,057 4% 4.61% 0.17% 0.26%
Common Equity 251,282 45% 10.30% 4.63% 7.12%
------- --- ----
Total Capitalization 558,529 100% 7.48% 10.06%
------- --- ---- -----
ATTACHMENT C
SHEET 2 OF 3
CENTRAL HUDSON GAS & ELECTRIC CORPORATION
CASE NOS. 00-E-1273 AND 00-G-1274
JOINT PROPOSAL - COST OF LONG-TERM DEBT
$(000)
OUTSTANDING MONTHS AVERAGE INTEREST
COST OF LONG TERM DEBT - RY1: RATE 8/30/01 CHANGES OUTSTANDING OUTSTANDING EXPENSE
- ---------------------------- ---- ------- ------- ----------- ----------- -------
PCB - August 1, 2027 Series A 5.45% 33,400 -- 12 33,400 1,820
PCB - August 1, 2034 Series B 2.80% 33,700 -- 12 33,700 944
PCB - August 1, 2028 Series C 2.65% 41,150 -- 12 41,150 1,090
PCB - August 1, 2028 Series D 2.64% 41,000 -- 12 41,000 1,062
PCB - December 1, 2028 4.20% 16,700 -- 12 16,700 701
MTN - September 10, 2001 5.93% 15,000 (15,000) 2 2,750 163
MTN - July 2, 2004 7.85% 15,000 -- 12 15,000 1,178
MTN - January 1, 2007 6.50% -- 65,000 10 54,187 3,522
MTN - January 15, 2009 6.00% 20,000 -- 12 20,000 1,200
------ ------
Totals 257,887 11,701
Amortization of Debt Discount & Expense 1,414
------
Total Cost of Debt 13,115
------
Cost Rate 5.09%
------
OUTSTANDING MONTHS AVERAGE INTEREST
COST OF LONG TERM DEBT - RY2: RATE 6/30/01 CHANGES OUTSTANDING OUTSTANDING EXPENSE
- ---------------------------- ----- -------- -------- ------------ ----------- --------
PCB - August 1, 2027 Series A 5.45% 33,400 -- 12 33,400 1,820
PCB - August 1, 2034 Series B 2.80% 33,700 -- 12 33,700 944
PCB - August 1, 2028 Series C 2.65% 41,150 -- 12 41,150 1,090
PCB - August 1, 2028 Series D 2.64% 41,000 -- 12 41,000 1,082
PCB - December 1, 2028 4.20% 16,700 -- 12 16,700 701
MTN - January 1, 2007 6.50% 65,000 -- 12 65,000 4,225
MTN - July 2, 2004 7.85% 15,000 -- 12 15,000 1,178
MTN - April 1, 2008 6.50% -- 10,000 3 2,500 162
MTN - January 15, 2009 6.00% 20,000 -- 12 20,000 1,200
-------- -------
Totals 268,450 12,403
Amortization of Debt Discount & Expense 1,420
-------
Total Cost of Debt 13,823
-------
Cost Rate 5.15%
-------
OUTSTANDING MONTHS AVERAGE INTEREST
COST OF LONG TERM DEBT - RY3: RATE 6/30/01 CHANGES OUTSTANDING OUTSTANDING EXPENSE
- ---------------------------- ----- -------- -------- ------------ ----------- --------
PCB - August 1, 2027 Series A 5.45% 33,400 -- 12 33,400 1,820
PCB - August 1, 2034 Series B 2.80% 33,700 -- 12 33,700 944
PCB - August 1, 2028 Series C 2.65% 41,150 -- 12 41,150 1,090
PCB - August 1, 2028 Series D 2.64% 41,000 -- 12 41,000 1,082
PCB - December 1, 2028 4.20% 16,700 -- 12 16,700 701
MTN - January 1, 2007 6.50% 65,000 -- 12 65,000 4,225
MTN - July 2, 2004 7.85% 15,000 -- 12 15,000 1,178
MTN - April 1, 2008 6.50% 10,000 -- 12 10,000 650
MTN - April 1, 2009 6.50% -- 8,742 8 5,828 379
MTN - January 15, 2009 6.00% 20,000 -- 12 20,000 1,200
-------- -------
Totals 281,778 13,269
Amortization of Debt Discount & Expense 1,425
-------
Total Cost of Debt 14,694
-------
Cost Rate 5.21%
-------
ATTACHMENT C
SHEET 3 OF 3
CENTRAL HUDSON GAS & ELECTRIC CORPORATION
CASE NOS. 00-E-1273 AND 00-G-1274
JOINT PROPOSAL - AMORTIZATION OF DEBT AND PREFERRED STOCK EXPENSES
TOTAL
ESTIMATED UNAMORTIZED UNRECOVERED
REDEMPTION EXPENSE COST OF AMORTIZATION - RYE
UNAMORTIZED DEBT EXPENSE: PREMIUM 6/30/01 REDEMPTION 6/30/02 6/30/03 6/30/04
---------- --------- ---------- ---------- ---------- ----------
6 1/4% MORTGAGE BONDS - 2007 53,973 53,973 9,156 9,156 9,156
9 1/4% MORTGAGE BONDS - 2021 860,846 860,846 43,404 43,404 43,404
7.97% MTN 6/11/2003 SERIES A 28,587 28,587 15,516 13,071 --
7.97% MTN 6/13/2003 SERIES A 29,978 29,978 14,328 14,328 1,322
7.85% MTN 6/2/2004 SERIES A 47,665 47,665 15,528 15,528 15,528
8.12% MTN 8/29/22 SERIES A 146,034 146,034 6,888 6,888 6,888
8.14% MTN 8/29/22 SERIES A 146,005 146,005 6,900 6,900 6,900
6.46% MTN 8/11/03 SERIES A 41,891 41,891 19,332 19,332 3,227
Tax Exempt NYSERDA 4.20% Due 12/1/28 537,586 537,586 19,608 19,608 19,608
6.00% MTN 1/15/09 Series C 176,915 176,915 23,580 23,580 23,580
5.45% Series A NYSERDA Bonds 8/1/27 646,345 646,345 24,780 24,780 24,780
Var Rate Ser B NYSERDA Bonds 7/1/34 570,240 570,240 17,477 17,477 17,477
Var Rate Series C NYSERDA Bonds 8/1/28 643,020 643,020 31,332 31,332 31,332
Var Rate Series D NYSERDA Bonds 8/1/28 641,714 641,714 29,400 29,400 29,400
$65,000 MTN Issued 9/1/01 Due 1/1/07 208,000 -- 208,000 32,500 39,000 39,000
$10,000 MTN Issued 4/1/03 Due 4/1/08 32,000 -- 32,000 -- 1,600 6,400
$10,000 MTN Issued 10/1/03 Due 4/1/09 32,000 -- 32,000 -- -- 4,299
---------- --------- ---------- ---------- ---------- ----------
Total 272,000 4,570,799 4,842,799 309,729 315,384 282,300
---------- --------- ---------- ---------- ---------- ----------
UNAMORTIZED LOSS ON REACQUIRED DEBT:
REDEMPTION 9 1/4% MTG. BONDS -- 160,082 160,082 57,324 57,324 57,324
REDEMPTION 10 5/8% MTG BONDS 11/1/05 -- 381,108 381,108 87,948 87,948 87,948
REDEMPTION 10 3/4% MTG BONDS 9/15/09 -- 741,496 741,496 90,324 90,324 90,324
7 1/2% POLLUTION CONTROL NOTES - 2014 -- 1,850,442 1,850,442 139,656 139,656 139,656
ADJ RTE POLL CTRL NOTES - DUE 11/1/2020 -- 592,800 592,800 187,200 187,200 187,200
ADJ RATE POLL CTRL NOTES - DUE 5/1/27 -- 393,193 393,193 15,168 15,168 15,168
REDEEMED 11 1/4% POLL CTL BDS - 9/1/12 -- 298,284 298,284 26,712 26,712 26,712
5.375% MORTGAGE BONDS -2028 -- 720,510 720,510 26,280 26,280 26,280
Redeem 9 1/4% Mortgage Bond 2,856,000 -- 2,856,000 144,000 144,000 144,000
Redeem 7.97% MTN Due 5/1/03 300,000 -- 300,000 150,000 150,000 150,000
Redeem 7.97% MTN Due 5/13/03 300,000 -- 300,000 150,000 150,000 150,000
Redeem 8.12% MTN Due 8/29/22 500,000 -- 500,000 23,810 23,810 23,810
Redeem 8.14% MTN Due 8/29/22 500,000 -- 500,000 23,810 23,810 23,810
Redeem 6.46% MTN Due 8/11/03 (100,000) -- (100,000) (46,154) (46,154) (7,692)
---------- --------- ---------- ---------- ---------- ----------
Total 4,356,000 5,137,915 9,493,915 1,076,077 1,076,077 1,114,539
---------- --------- ---------- ---------- ---------- ----------
UNAMORTIZED DISCOUNT ON L/T DEBT:
First Mtg. Bonds - 9 1/4% due 5/1/21 -- 512,640 512,640 25,632 25,632 25,632
5.45% Ser. A NYSERDA Bonds due 8/1/27 -- 78,045 78,045 2,976 2,976 2,976
---------- --------- ---------- ---------- ---------- ----------
Total -- 590,685 590,685 28,608 28,608 28,608
---------- --------- ---------- ---------- ---------- ----------
Total Debt Issuance and Redemption Expenses 4,628,000 10,299,399 14,927,399 1,414,414 1,420,069 1,425,447
---------- --------- ---------- ---------- ---------- ----------
PREFERRED STOCK:
- ---------------
6.20% Cumulative Preferred 675,000 412,554 1,087,554 150,007 150,007 150,007
6.80% Cumulative Preferred 1,600,000 454,230 2,054,230 78,256 78,256 78,256
---------- --------- ---------- ---------- ---------- ----------
Total Preferred Stock Issuance
and Redemption Expenses 2,275,000 866,784 3,141,784 228,264 228,264 228,264
---------- --------- ---------- ---------- ---------- ----------
ATTACHMENT D-1
CENTRAL HUDSON GAS & ELECTRIC CORPORATION
CASE NOS. 00-E-1273 & 00-G-1274
JOINT PROPOSAL - BENEFIT POOL
Settlement Period
($000, Net of Tax)
RY1 RY2 RY3
-------- -------- -------
NET BENEFIT FUND:
Net Fossil Proceeds 76,708
Deferred Excess Earnings 9,377
Net Settlement Benefits 41,621
NMP2 Proceeds 36,500
-------
Total Benefit Pool 164,206
Less: Rate Base Credit (42,500)
-------
Net Benefit Fund Available 121,706 100,692 88,204
Identified Uses (net of tax):
Reliability Program - $20 million,
3 Yr Program (4,333) (4,333) (4,333)
Offset of Gas Site Remediation
Costs - $15 million (9,750) -- --
Refunds (15,000) (15,000) (15,000)
-------- -------- -------
Remaining Balance 92,623 81,359 68,871
Add Cumulative Carrying
Charges - Net of Tax 8,069 6,845 5,875
-------- -------- -------
Net Benefit Fund Balance 100,692 88,204 74,745
-------- -------- -------
Identified uses include electric backout credits, and other new stranded costs;
potential uses include economic development fund, price spike mitigation, small
customer aggregation, other competitive initiatives and additional refunds.
ATTACHMENT D-2
ELECTRIC DEFERRED ITEMS INCLUDED IN BENEFIT FUND
The June 30, 2001 balances of the following deferred debit and deferred
credit accounts, net of tax, are included in the Benefit Fund. No subsequent
deferrals to these accounts will be included in the Benefit Fund except for
those to make accounting adjustments to the June 30, 2001 balance.
DEFERRED DEBITS
Adjustable Rate PCB Notes
Deferred DSM Costs
Tax Rate Change - 1993
Storm Costs - April 1997
Restructuring Costs - Formation of Holding Company
Lost Revenues - Job Retention Provision (COPS)
Pension Carrying Charge
Pension Fund Withdrawal
DEFERRED CREDITS
Research & Development Costs
Management Audit
Adjustable Rate Preferred Dividends Over/Under Collection
NMP-2 Vendor Litigation - Ratepayer
NMP-2 Vendor Litigation Carrying Charge
NMP-2 Deferred Settlement Agreement Costs
Carrying Charge on NMP-2 Settlement Agreement Costs
Carrying Charge on DSM Rate Base
DSM Lost Revenues
Customer Benefits Account (COPS)
Royalty Charge (COPS)
R&D 1994 Audit Adjustment
Deferred Letter of Credit/Remarketing Fees
Deferred Pension Cost Over/Under Collection
Deferred OPEB Expense
OPEB Carrying Charge
Deferred Excess Earnings
ATTACHMENT E
GAS DEFERRED ITEMS FOR BALANCE SHEET OFFSET
The following gas department deferred debit and deferred credit items will
be subject to balance sheet offset accounting to the extent that a net of tax
offset of zero is achieved using actual deferred amounts at June 30, 2001.
DEFERRED DEBITS
Adjustable Rate PCB Notes
Amortization of Unbilled Revenue (Case 90-G-0673)
Carrying Charge of Newburgh Site Investigation
ULIEEP Over/Under Collection (Including Carrying Charges)
Pension Carrying Charge
DEFERRED CREDITS
Unamortized Interruptible Gas Depreciation
Research & Development Costs
Management Audit
Gas Special Franchise Tax
R&D 1994 Audit Adjustment
Deferred Letter of Credit/Remarketing Fees
Deferred Pension Cost Over/Under Collection
Deferred OPEB Expense
OPEB Carrying Charge
ATTACHMENT F
CENTRAL HUDSON GAS & ELECTRIC CORPORATION
ELECTRIC INTERCLASS REVENUE ALLOCATION
ALLOCATION OF PROPOSED REVENUE INCREASE (DECREASE) EXCLUDING REVENUE TAX
USING 15% TOLERANCE BAND ON RATE OF RETURN
CASE 00-E-1273 COMPLIANCE FILING
$(000)
SC Nos SC SC No. 6 SC
2 & 12 No. 5 RESIDENTIAL No. 8
LINE SC No. 1 SMALL SC NO. 3 AREA TIME STREET SC No. 13
NO. TOTAL RESIDENTIAL GENERAL PRIMARY LIGHTING OF USE LIGHTING SUBSTATION TRANSMISSION
- ----- ------------------------------ --------- ---------- -------- ---------- -------- ----------- -------- ----------- -----------
1. Net Income (1) $22,717 $10,984 $7,323 $1,708 $198 $1,232 ($34) $345 $961
- ----- ------------------------------ --------- ---------- -------- ---------- -------- ----------- -------- ----------- -----------
2. % Rate of Return 5.34 4.58 5.89 11.67 4.51 10.08 (0.49) 10.73 5.02
- ----- ------------------------------ --------- ---------- -------- ---------- -------- ----------- -------- ----------- -----------
3. 5.34 +/- 15% 5.09 4.58 5.89 6.14 4.54 6.14 4.54 6.14 5.02
- ----- ------------------------------ --------- ---------- -------- ---------- -------- ----------- -------- ----------- -----------
4. Adjusted Net Income $21,652 $10,985 $7,347 $898 $199 $750 $314 $197 $961
- ----- ------------------------------ --------- ---------- -------- ---------- -------- ----------- -------- ----------- -----------
5. Adjusted to Initial $22,717 $11,525 $7,708 $942 $209 $787 $330 $207 $1,009
Net Income
- ----- ------------------------------ --------- ---------- -------- ---------- -------- ----------- -------- ----------- -----------
6. Difference $541 $385 ($766) $11 ($445) $364 ($138) $48
- ----- ------------------------------ --------- ---------- -------- ---------- -------- ----------- -------- ----------- -----------
7. Revenue $819 $583 ($1,161) $17 ($674) $552 ($209) $73
(Line 7/.66)
- ----- ------------------------------ --------- ---------- -------- ---------- -------- ----------- -------- ----------- -----------
8. Revenue Increase (Decrease)-
NET OF FUEL Excludes
Revenue Tax ($2,297) ($1,300) ($692) ($95) ($12) ($87) ($37) ($19) ($55)
- ----- ------------------------------ --------- ---------- -------- ---------- -------- ----------- -------- ----------- -----------
9. Total Revenue Decrease ($2,297) ($481) ($109) ($1,256) $5 ($761) $515 ($228) $18
- ----- ------------------------------ --------- ---------- -------- ---------- -------- ----------- -------- ----------- -----------
10. Present Rate Revenues $149,179 $84,441 $44,966 $6,160 $758 $5,623 $2,406 $1,225 $3,600
(Excluding Revenue Tax)
- ----- ------------------------------ --------- ---------- -------- ---------- -------- ----------- -------- ----------- -----------
11. Percent Increase (Decrease)
Unconstrained (1.54) (0.57) (0.24) (20.39) 0.66 (13.53) 21.40 (18.61) 0.50
- ----- ------------------------------ --------- ---------- -------- ---------- -------- ----------- -------- ----------- -----------
12. Percent Increase (Decrease)
Constrained (1.54) (1.52) (1.52) (1.93) (0.79) (1.94) (0.79) (1.96) (1.50)
- ----- ------------------------------ --------- ---------- -------- ---------- -------- ----------- -------- ----------- -----------
13. Total Revenue Increase
Constrained ($2,297) ($1,283) ($683) ($119) ($6) (109) ($19) ($24) ($54)
- ----- ------------------------------ --------- ---------- -------- ---------- -------- ----------- -------- ----------- -----------
14. DSM Adjustment ($42) ($6) ($29) ($7)
- ----- ------------------------------ --------- ---------- -------- ---------- -------- ----------- -------- ----------- -----------
15. Final Total Revenue Increase ($2,339) ($1,289) ($712) ($126) ($6) ($109) ($19) ($24) ($54)
- ----- ------------------------------ --------- ---------- -------- ---------- -------- ----------- -------- ----------- -----------
(1) PRO FORMA COST OF SERVICE STUDY FOR THE RATE YEAR ENDING JUNE 30, 2002,
WITH HYDRO CLASSIFIED 100% ENERGY AND TURBINES CLASSIFIED 100% DEMAND.
51
ATTACHMENT G
SHEET 1 OF 5
CENTRAL HUDSON GAS & ELECTRIC CORPORATION
LOW INCOME PROGRAM
POWERFUL OPPORTUNITIES
PLAN OBJECTIVES:
An effective low income program should provide a practical opportunity for
customers who, due to an illness or disability or loss of job, have fallen
behind in their utility payments and are struggling to pay their arrears. An
effective low income program should empower customers by developing a
comprehensive plan to improve their overall financial situation to become
self-reliant. An effective low income program should teach customers about the
cost of electricity -- and how energy conservation and energy efficiency does
make a difference for affordability. An effective low income program should
bring peace of mind to the customers -- that their utility bills can be worked
out at a level they can handle. An effective low income program should build a
stronger relationship between customers, Central Hudson and the community. And
lastly, an effective low income program should enable Central Hudson to focus
its collection efforts on customers who can but don't pay their utility bills.
PLAN DESIGN & ADMINISTRATION
Powerful Opportunities is a managed approach, designed to accomplish three
primary goals: (1) Provide customers with an affordable payment plan for past
and future utility bills; (2) Provide customers with the tools to obtain
long-term, overall financial stability and self-sufficiency; and (3) Provide
customers with the energy services and education required to enable them to
reduce their energy usage and potentially their payment amount. In addition, our
low income program is designed to include an incentive to encourage customers to
meet their Powerful Opportunities obligations.
To attain the first goal, "provide customers with an affordable payment plan for
past and future utility bills" the following actions are recommended:
Attachment G
Sheet 2 of 5
- Place the customer on budget billing for future bills.
- Place the customer's arrears in suspend; no LPCs will be charged to
this amount while the customer is a participant of the Program.
- Give an incentive: a $ for $ match on payments made above the current
budget amount. The maximum match paid by Central Hudson will be $20
per month per customer.
- If the customer is a heating customer, give one additional GNF benefit
at the end of the Program (last $125 of arrears).
- Offer a lower basic service charge of $5.00 per month for both gas and
electric customer participants.
It is recommended Central Hudson collaborate with community resources to attain
the second goal of "providing customers with the tools to obtain overall
financial stability and self-- sufficiency"; and the third goal, "providing
customers with the energy services and education required to enable them to
reduce their energy usage". A partnership with a community--based organization,
such as Dutchess County Community Action Agency (DCCAA), would contribute to the
overall integrity of the Program. DCCAA has established trust and credibility in
helping families with their self--sufficiency goals. In addition, DCCAA is a
well--known and respected entity within the network of community assistance
agencies. DCCAA can effectively coordinate community resources, educate
consumers, establish individual customer assessments and referrals, and provide
program administration and outreach to our mutual clients.
A partnership with DCCAA would provide:
- A multi-county network, which spans our entire service territory, with
the ability to disseminate, support and monitor implementation of the
program.
- Referrals to local, state and federal assistance programs, and
coordinate with the NYS Weatherization Program.
Attachment G
Sheet 3 of 5
- Expertise in assisting low income customers with the ability to gain
greater competency in their household management through energy
efficient products and consumer education.
- Family development training to promote greater self-sufficiency and
self-reliance to the Program participants, and internal sensitivity
training to our customer--contact employees.
CUSTOMER'S ELIGIBILITY AND OBLIGATIONS
Eligibility for participation in this Program is outlined below:
- Must be a CHG&E customer whose bills are not directly paid to the
Company by a local department of social services office, and the
account must be their primary residence.
- Customer must have an account that is 60 days or more in arrears.
- Customer who has a household income equal to or less than 200% of
poverty level, as determined for that program year.
- Customers will be considered categorically eligible if they are
enrolled in the New York State Home Energy Assistance Program or any
other federal or state assistance program with similar or stricter
income eligibility requirements than 200% of the poverty level.
- Customer must complete a Program application form and financial
statement (DSS 3596), submit required documentation and be approved
for participation.
- Customers in an energy crisis (locked for non-payment) at the time of
application may be eligible to participate, however, the amount they
are required to pay for turn-on will not be matched by Central Hudson.
Attachment G
Sheet 4 of 5
- The maximum Program enrollment targets are:
YEAR TARGET
1 250
2 500
3 1000
In order for the customer to become a participant of Powerful Opportunities,
they must agree (in writing) to the following terms and responsibilities:
- Only if consistent with a DCCAA assessment of an individual
participant's ability to pay, participants shall pay at least an
additional $5 per month (for $60 per year) on their arrears.
- Participate in energy conservation/efficiency training and budget
counseling sessions as prescribed by their Family Development
Specialist.
- Agree to the recommended follow-up schedule, and meet with their
designated Family Development Specialist according to that schedule.
- Apply for community and government assistance as suggested by the
Family Development Specialist.
- Customers who become delinquent on a current bill will be dropped from
the Program after 60 days delinquency and will not be eligible for
re-entry for the same arrears. A minimum $10/month DPA will be offered
and then regular collection cycle will begin.
- Re-entry to the program, however, will be permitted if a participant
who is dropped from the program for nonpayment of current bills
subsequently receives emergency assistance through a Department of
Social Services program and the amount of the delinquency after the
customer's prior enrollment in the program is paid in full.
OTHER ASSISTANCE
- HEAP payments (regular and emergency) will be applied to the
customer's current charges and will not be matched by Central Hudson.
If a HEAP payment is more
Attachment G
Sheet 5 of 5
than the current amount due, the excess will be applied to the
arrears, with no Company match.
- Other community assistance (i.e., Red Cross, Church Charities, etc.)
will be matched by Central Hudson if the funding is paid to the
customer for payment of bills, and the customer passes the payment to
Central Hudson to be applied to their arrears. Community assistance
payments made directly to Central Hudson on behalf of the customer
will be applied to the current bill first, then to the arrears, with
no match.
DCCAA ROLE:
DCCAA will work closely with Consumer Outreach to develop and maintain an
effective low income program. Upon approval of this draft proposal, DCCAA will
prepare and submit for our review and approval a Program outline and fee for
their part in Powerful Opportunities. The Program outline will include:
- Implementation Plan (including targeted outreach, toll- free number,
etc.)
- Procedures (including forms, letters, follow-up, collaboration with
neighboring Community Action Agencies located in our service
territory, etc.)
- Community and Government Assistance Referrals
- Weatherization Plan (including appliance repair and replacement)
- Case Management:
Family Development Training Outline (for long-term
self--sufficiency)
Energy Efficiency/Conservation
Budget Counseling
- Sensitivity Training Outline (for CHG&E employees)
- Evaluation Process
ATTACHMENT H
SHEET 1 OF 2
CENTRAL HUDSON GAS & ELECTRIC CORPORATION
RATE BASE - SUMMARY
FINAL SETTLEMENT POSITION
($000)
ELECTRIC GAS
------------------------------------- -------------------------------------
RY 1 RY 2 RY 3 RY 1 RY 2 RY 3
--------- --------- --------- --------- --------- ---------
BOOK COST OF UTILITY PLANT $ 671,892 $ 703,930 $ 743,956 $ 190,346 $ 196,552 $ 204,205
LESS: ACCUMULATED PROVISION FOR
DEPRECIATION AND AMORTIZATION (244,559) (256,038) (270,252) (69,798) (72,956) (78,056)
--------- --------- --------- --------- --------- ---------
NET PLANT 427,333 447,892 473,704 120,548 123,596 126,149
RELIABILITY CAPITAL PROGRAM (5,354) (16,196) (26,650)
NET SETTLEMENT BENEFITS (42,500) (42,500) (42,500)
NONINTEREST-BEARING CONSTRUCTION
WORK IN PROGRESS 30,160 28,731 29,088 8,434 8,501 8,556
CUSTOMER ADVANCES FOR UNDERGROUNDING (603) (615) (627)
DEFERRED CHARGES 17,559 15,948 14,228 4,290 4,010 3,919
ACCUMULATED DEFERRED TAXES (66,670) (67,869) (69,353) (17,760) (18,908) (20,206)
WORKING CAPITAL 23,507 24,135 24,909 5,181 5,324 5,484
--------- --------- --------- --------- --------- ---------
UNADJUSTED RATE BASE 383,432 389,526 402,799 120,693 122,523 123,902
CAPITALIZATION ADJUSTMENT TO RATE BASE (3,217) (3,217) (3,217) (998) (998) (998)
--------- --------- --------- --------- --------- ---------
TOTAL RATE BASE $ 380,215 $ 386,309 $ 399,582 $ 119,695 $ 121,525 $ 122,904
--------- --------- --------- --------- --------- ---------
ATTACHMENT H
SHEET 2 OF 2
CENTRAL HUDSON GAS & ELECTRIC CORPORATION
DEFERRED CHARGES, DEFERRED TAXES AND WORKING CAPITAL
FINAL SETTLEMENT POSITION
($000)
ELECTRIC GAS
-------------------------------------- --------------------------------------
RY 1 RY 2 RY 3 RY 1 RY 2 RY 3
-------- -------- -------- -------- -------- --------
DEFERRED CHARGES
SOFTWARE PURCHASES $ 2,647 $ 2,221 $ 1,564 $ 1,197 $ 1,253 $ 1,349
MTA TAX 2,426 2,426 2,246 769 769 769
UNAMORTIZED DEBT EXPENSE 8,211 8,459 7,710 1,337 1,337 1,255
INCREMENTAL DEFERRED DEBT EXPENSE 3,783 2,375 2,085 780 535 474
UNAMORTIZED DISCOUNT LONG-TERM DEBT 492 467 443 80 76 72
CARRYING CHARGE ON NEWBURGH SITE
INVESTIGATION 0 0 0 127 0 0
-------- -------- -------- -------- -------- --------
TOTAL DEFERRED CHARGES $ 17,559 $ 15,948 $ 14,228 $ 4,290 $ 4,010 $ 3,919
DEFERRED TAXES
MTA TAX ($ 849) ($ 849) ($ 849) ($ 269) ($ 269) ($ 269)
NORMALIZED DEPRECIATION (59,588) (62,728) (66,162) (18,639) (19,993) (21,439)
INVESTMENT TAX CREDIT (3,102) (2,800) (2,498) (700) (637) (576)
COST OF REMOVAL (1,510) (1,536) (1,572) (174) (87) (32)
CONSTRUCTION OVERHEADS (1,438) (1,329) (1,220)
CONTRIBUTIONS IN AID OF CONSTRUCTION 1,662 1,651 1,638 341 336 330
DEFERRED AVOIDED COST INTEREST
CAPITALIZED 1,303 1,288 1,276 294 299 302
UNBILLED REVENUE 4,231 4,231 4,231 1,811 1,811 1,811
REPAIR ALLOWANCE (6,044) (6,149) (6,244)
ACRS METHOD CHANGE (97) (87) (77) (24) (22) (20)
MORTGAGE TAXES (134) (121) (108) (21) (19) (17)
BONDS REDEEMED (716) (806) (726) (117) (133) (119)
CARRYING CHARGE ON NEWBURGH
SITE INVESTIGATION 0 0 0 (45) 0 0
REDEMPTION PREMIUMS (1,230) (1,097) (1,005) (217) (194) (177)
RELIABILITY EXPENDITURES 842 2,463 3,963
-------- -------- -------- -------- -------- --------
TOTAL DEFERRED TAXES ($66,670) ($67,869) ($69,353) ($17,760) ($18,908) ($20,206)
-------- -------- -------- -------- -------- --------
WORKING CAPITAL
OTHER MATERIAL AND SUPPLY WORKING
CAPITAL 4,248 4,336 4,422 1,408 1,437 1,466
PREPAID PROPERTY TAXES - OTHER 8,571 8,916 9,272 1,623 1,686 1,752
PREPAID INSURANCE - OTHER 398 406 415 112 114 116
OTHER PREPAYMENTS 592 605 617 105 107 109
OPERATION AND MAINTENANCE CASH
WORKING CAPITAL 9,698 9,872 10,183 1,933 1,980 2,041
-------- -------- -------- -------- -------- --------
TOTAL WORKING CAPITAL $ 23,507 $ 24,135 $ 24,909 $ 5,181 $ 5,324 $ 5,484
-------- -------- -------- -------- -------- --------
ATTACHMENT I
STATE OF NEW YORK PUBLIC SERVICE COMMISSION
CASE 00-E-1273 - PROCEEDING ON MOTION OF THE COMMISSION AS TO THE RATES,
CHARGES, RULES AND REGULATIONS OF CENTRAL HUDSON GAS & ELECTRIC
CORPORATION FOR ELECTRIC SERVICE
CASE 00-G-1274 - PROCEEDING ON MOTION OF THE COMMISSION AS TO THE RATES,
CHARGES, RULES AND REGULATIONS OF CENTRAL HUDSON GAS & ELECTRIC
CORPORATION FOR GAS SERVICE
SUPPLEMENTAL ENVIRONMENTAL ASSESSMENT FORM
PREPARED BY:
CENTRAL HUDSON GAS & ELECTRIC CORPORATION,
STAFF OF THE DEPARTMENT OF PUBLIC SERVICE, AND THE
OTHER SIGNATORY PARTIES TO THE JOINT PROPOSAL
Dated: Albany, New York
August 27, 2001
I. INTRODUCTION
This document provides the substantive information solicited by Appendix A
of 6 NYCRR 617.20, part of the regulations promulgated by the New York State
Department of Environmental Conservation pursuant to the State Environmental
Quality Review Act ("SEQRA"), Article 8 of the New York Environmental
Conservation Law. An environmental assessment is an evaluation of the known or
potential environmental consequences of a proposed action. Such an assessment
also determines whether additional relevant information about such impacts is
needed. Environmental assessments help involved and interested agencies identify
their concerns about the action and provide guidance to the lead agency in
making its determination of significance.
An Environmental Assessment Form ("EAF") provides an organized approach to
identifying the information needed by the lead agency to make its determination
of significance. A properly completed EAF describes a proposed action, its
location, its purpose and its potential impacts on the environment. The EAF is
the first step in the environmental impact review process and leads to either a
positive declaration (requiring further analysis of the potentially significant
adverse environmental impacts) or a negative declaration (requiring no further
analysis).
II. ENVIRONMENTAL ASSESSMENT FORM INFORMATION (PART I OF EAF)
A. APPLICANT/SPONSOR:
Central Hudson Gas & Electric Corporation
("Central Hudson" or "Company")
284 South Avenue
Poughkeepsie, New York 12601
B. NAME OF ACTION:
Public Service Commission ("Commission") approval of the terms of
the Joint Proposal for the resolution of Cases 00-E-1273 and
00-G-1274
C. LOCATION OF ACTION:
Central Hudson electric and gas service territories
D. DESCRIPTION OF ACTION:
The Company and other Signatory Parties to the Joint Proposal are
petitioning the Commission under the Public Service Law of the State of New York
for approval of the terms of their Joint Proposal for the resolution of Cases
00-E-1273 and 00-G-1274. These cases relate to the rates, charges, rules and
regulations of the Company for electric and gas service, respectively, and to
the Commission's
restructuring and competitive market development policies in Case 94-E-0952(1)
(electricity) and Cases 93-G-0932 and 97-G-1380(2) (gas). The Commission's
consideration of the rate-related aspects of the Joint Proposal is a "Type II
exempt rate action"(3) that does not require SEQRA analysis. Accordingly, the
Commission's consideration of the restructuring and competitive market
development-related aspects of the Joint Proposal is the potential action that
has been evaluated in this Assessment.
The Joint Proposal does not require any construction activities which would
directly affect the environment. As a result, consideration of the terms of the
Joint Proposal is an "unlisted" action as defined in 6 NYCRR 617. While 6 NYCRR
617.6 generally calls for the use of the short EAF set forth at 6 NYCRR 617.20,
Appendix C, because this action does not involve physical construction as
contemplated by the short EAF, a narrative EAF has been utilized.(4)
1. CASE 00-E-1273
Case 00-E-1273 was occasioned by the implementation of the Commission's
policy of supporting increased competition in electricity markets, which it
adopted in Opinion No. 96-12 in Case 94-E-0952. Case 00-E-1273 was preceded and
required by Case 96-E-0909(5) in which, by an Order issued February
- ----------
(1) IN THE MATTER OF COMPETITIVE OPPORTUNITIES REGARDING ELECTRIC SERVICE
(2) Respectively, PROCEEDING ON MOTION OF THE COMMISSION TO ADDRESS ISSUES
ASSOCIATED WITH THE RESTRUCTURING OF THE EMERGING COMPETITIVE NATURAL GAS MARKET
AND IN THE MATTER OF ISSUES ASSOCIATED WITH THE FUTURE OF THE NATURAL GAS
INDUSTRY AND THE ROLE OF THE LOCAL DISTRIBUTION COMPANIES
(3) Opinion No. 98-14 at 41.
(4) A narrative EAF has also been used in similar cases. See, Case
99-G-0336, NIAGARA MOHAWK POWER CORPORATION - GAS MULTI-YEAR RATE AND
RESTRUCTURING PROPOSAL, Opinion No. 00-9 issued July 27, 2000; Case 99-G-1469,
BROOKLYN UNION GAS COMPANY - MULTI-YEAR RESTRUCTURING AGREEMENT, Order
Establishing Interim Rate Plan issued December 26, 2000; Case 98-G-1589,
ROCHESTER GAS AND ELECTRIC CORPORATION - PLANS FOR GAS RATES AND RESTRUCTURING,
Order Adopting Terms of Joint Proposal issued February 28, 2001.
(5) IN THE MATTER OF CENTRAL HUDSON GAS & ELECTRIC CORPORATION'S PLANS FOR
ELECTRIC RATES AND RESTRUCTURING PURSUANT TO OPINION NO. 96-12
19, 1998 and by Opinion No. 98-14 issued June 30, 1998, the Commission adopted
an electric rate and restructuring plan for the Company pursuant to the
Commission's policy of supporting increased electricity market competition as
adopted in Case 94-E-0952.
Case 00-E-1273 and the Joint Proposal address ratemaking associated with
the restructuring of the Company from a vertically integrated utility to a
delivery service company, as envisioned by the Commission in Case 94-E-0952 and
implemented, to the extent of the Company's divestiture of its fossil fueled
generating units and measures to promote retail access, in Case 96-E-0909. This
is in the form of removing from rates those charges associated with the
Company's former interests in fossil fueled generating units and establishing
the methods and procedures for customer acquisition of and payment for electric
supply provided by marketers. Case 00-E-1273 and the Joint Proposal additionally
address the furtherance of the Commission's policy of supporting increased
competition in electricity markets by unbundling rate elements and providing
back-out credits to customers who take supply service from ESCOs or marketers,
funding increased customer understanding of competitive electricity supply
options and efforts to obtain input from ESCOs and marketers regarding the
furtherance of the development of a competitive retail electricity supply market
in the Company's service territory.
On May 3, 1996, the Commission issued a Final Generic Environmental Impact
Statement ("FGEIS") in Case 94-E-0952 with respect to the proposed action of
adopting a policy supporting increased competition in electricity markets. In
adopting such policy in Opinion No. 96-12, the Commission found that the FGEIS
"did not identify reasonably likely significant adverse impacts" of the action
except with respect to air quality, energy efficiency and research and
development in response to which the Commission adopted mitigation measures
including monitoring the environmental impacts of the action.(6) By Opinion No.
98-14 in Case 96-E-0909, based on an EAF filed by the Company on June 17,
1997,(7) the Commission found the potential environmental impacts of the rate
and restructuring plan for the Company therein adopted to be "within the range
of thresholds and conditions set forth in the FGEIS" thereby requiring no
further SEQRA action, but, "as a matter of discretion," monitoring of the
Company's restructuring and environmental impacts was implemented.(8)
2. CASE 00-G-1274
On November 3, 1998, the Commission issued its Policy Statement Concerning
the Future of the Natural Gas Industry in New York State and Order Terminating
Capacity Assignment in Cases 93-G-0932 and 97-G-1380 ("Gas Policy Statement").
In the Gas Policy Statement, the Commission articulated its vision of the future
of the natural gas industry, which is to "facilitate development of a
competitive market; eliminate barriers to competition; provide guidance to LDCs
and marketers, especially with regard to expiring capacity contracts; and
- ----------
(6) Opinion 96-12 at 76-81.
(7) Opinion 98-14, Appendix D.
(8) Opinion 98-14 at 41-42.
address customer inertia.(9) The Commission conducted an analysis under the
State Environmental Quality Review Act, determined that there would be no
significant environmental impact from adoption of the Gas Policy Statement and
issued a Notice of Determination of Non-Significance.(10)
Case 00-G-1274 and the Joint Proposal address the furtherance of the
Commission's policy of supporting increased competition in natural gas retail
supply markets by unbundling rate elements and providing back-out credits to
customers who take supply service from marketers, funding increased customer
understanding of competitive gas supply options and funding efforts to obtain
input from marketers regarding the furtherance of the development of a
competitive retail as supply market in the Company's service territory. In that
regard the Joint Proposal is similar in principle to gas restructuring
settlements pursuant to the Gas Policy Statement of other companies that have
been approved by the Commission.(11)
III. EVALUATION OF ENVIRONMENTAL IMPACTS (PART 2 OF EAF)
Specific environmental impacts that might result from the Joint Proposal
are highly unlikely. The Joint Proposal will not cause direct environmental
effects because the Joint Proposal does not involve physical activities that
might have impacts on the environment. Instead, the Joint Proposal might
contribute to the creation of circumstances that subsequently induce activities
which might cause environmental effects.
In preparing this environmental assessment, the Signatory Parties have set
out an evaluation of a range of potentially conceivable secondary consequences
of the Joint Proposal in order to assist the Commission in its evaluation of
this matter. The Signatory Parties have relied on qualitative judgments as to
the potential changes resulting from the proposed actions and the magnitude and
importance of the corresponding potential environmental impacts.
A. IMPACT ON AIR
The Signatory Parties were unable to identify any direct effects on air
emissions resulting from the Joint Proposal. The Commission, however, clearly
contemplated the possibility that
- ----------
(9) Gas Policy Statement at 3-4.
(10) Gas Policy Statement at 9.
(11) Case 99-G-0336, NIAGARA MOHAWK POWER CORPORATION - GAS MULTI-YEAR RATE
AND RESTRUCTURING PROPOSAL, Opinion No. 00-9 issued July 27, 2000; Case
99-G-1469, BROOKLYN UNION GAS COMPANY - MULTI-YEAR RESTRUCTURING AGREEMENT,
Order Establishing Interim Rate Plan issued December 26, 2000; Case 98-G-1589,
ROCHESTER GAS AND ELECTRIC CORPORATION - PLANS FOR GAS RATES AND RESTRUCTURING,
Order Adopting Terms of Joint Proposal issued February 28, 2001.
increased competition could promote increased energy usage and, thereby, have
adverse air quality impacts. The Signatory Parties believe that the provisions
of the Joint Proposal intended to further the Commission's policy of supporting
the development of competitive markets for retail energy will neither directly
nor indirectly affect the supply market prices in a manner that would encourage
increased energy usage not within the range of thresholds and conditions set
forth in the FGEIS in Case 94-E-0952 or not within that contemplated by the
Commission in its Determination of Non-Significance reached in connection with
the Gas Policy Statement. The Signatory Parties also believe that the associated
unbundling of the Company's rates as provided for in the Joint Proposal will not
result in delivery service rates that would encourage energy usage not within
the range of thresholds and conditions set forth in the FGEIS in Case 94-E-0952
or not within that contemplated by the Commission in its Determination of
Non-Significance reached in connection with the Gas Policy Statement. As a
result, the Signatory Parties believe that any impacts on air quality resulting
from the Joint Proposal are within the range of thresholds and conditions set
forth in the FGEIS in Case 94-E-0952 and within those contemplated by the
Commission in its Determination of Non-Significance reached in connection with
the Gas Policy Statement.
B. IMPACT ON WATER
The Signatory Parties were unable to identify and direct effects on water
quality resulting from the Joint Proposal. As discussed in the Impact on Air
section above, the Joint Proposal could result in an increased demand for
electricity or natural gas. This increased demand in turn could contribute to
the need to construct new production, transmission or distribution facilities to
serve the increased demand. With such new construction there could be the need
to conduct work in environmentally sensitive areas such as wetlands or streams.
While this work could potentially impact the environment, it would be subject to
all applicable federal and state environmental regulatory requirements including
SEQRA review prior to construction. As a result and as the Commission found with
respect to gas restructuring, "these speculative impacts need not be considered
at this time."(12) With regard to electric restructuring, this similar potential
effect would be within the range of thresholds and conditions set forth in the
FGEIS in Case 94-E-0952.
C. IMPACT ON LAND
The Signatory Parties were unable to identify any direct effects on land
use resulting from the Joint Proposal. However, as indicated above, new
construction or expansion of production, transmission or distribution facilities
could have potential environmental impacts. These impacts, however, would be
mitigated by regulatory requirements and SEQRA review at the time as noted by
the Commission in its Determination of Non-Significance reached in connection
with the Gas Policy Statement and within the range of thresholds and conditions
set forth in the FGEIS in Case 94-E-0952.
- ----------
(12) Gas Policy Statement, Notice of Determination of Non-Significance at 1-2.
D. IMPACT ON PLANTS AND ANIMALS
The Signatory Parties were unable to identify and direct effects on plants
and animals resulting from the Joint Proposal. However, as indicated above, new
construction or expansion of production, transmission or distribution facilities
could have potential environmental impacts. These impacts, however, would be
mitigated by regulatory requirements and SEQRA review at the time as noted by
the Commission in its Determination of Non-Significance reached in connection
with the Gas Policy Statement and within the range of thresholds and conditions
set forth in the FGEIS in Case 94-E-0952.
E. IMPACT ON AGRICULTURAL LAND RESOURCES
The Signatory Parties were unable to identify any direct effects on
agricultural land resources resulting from the Joint Proposal. However, as
indicated above, new construction or expansion of production, transmission or
distribution facilities could have potential environmental impacts. These
impacts, however, would be mitigated by regulatory requirements and SEQRA review
at the time as noted by the Commission in its Determination of Non-Significance
reached in connection with the Gas Policy Statement and within the range of
thresholds and conditions set forth in the FGEIS in Case 94-E-0952.
F. IMPACT ON AESTHETIC RESOURCE
The Signatory Parties were unable to identify any direct effects on
aesthetic resource resulting from the Joint Proposal. However, as indicated
above, new construction or expansion of production, transmission or distribution
facilities could have potential environmental impacts. These impacts, however,
would be mitigated by regulatory requirements and SEQRA review at the time as
noted by the Commission in its Determination of Non-Significance reached in
connection with the Gas Policy Statement and within the range of thresholds and
conditions set forth in the FGEIS in Case 94-E-0952.
G. IMPACT ON HISTORIC AND ARCHEOLOGICAL RESOURCES
The Signatory Parties were unable to identify any direct effects on
historic and archeological resources resulting from the Joint Proposal. However,
as indicated above, new construction or expansion of production, transmission or
distribution facilities could have potential environmental impacts. These
impacts, however, would be mitigated by regulatory requirements and SEQRA review
at the time as noted by the Commission in its Determination of Non-Significance
reached in connection with the Gas Policy Statement and within the range of
thresholds and conditions set forth in the FGEIS in Case 94-E-0952.
H. IMPACT ON OPEN SPACE AND RECREATION
The Signatory Parties were unable to identify and direct effects on open
space and recreation resulting from the Joint Proposal. However, as indicated
above, new construction or expansion of production, transmission or distribution
facilities could have potential environmental impacts. These impacts, however,
would be mitigated by regulatory requirements and SEQRA review at the time as
noted by the Commission in its Determination of Non-Significance reached in
connection with the Gas Policy Statement and within the range of thresholds and
conditions set forth in the FGEIS in Case 94-E-0952.
I. IMPACT ON TRANSPORTATION
The Signatory Parties were unable to identify any direct effects on
transportation resulting from the
Joint Proposal. However, as indicated above, new construction or expansion of
production, transmission or distribution facilities could have potential
environmental impacts. These impacts, however, would be mitigated by regulatory
requirements and SEQRA review at the time as noted by the Commission in its
Determination of Non-Significance reached in connection with the Gas Policy
Statement and within the range of thresholds and conditions set forth in the
FGEIS in Case 94-E-0952.
J. IMPACT ON ENERGY
The Commission clearly contemplated the possibility that increased
competition could promote increased energy usage. The Signatory Parties believe
that the provisions of the Joint Proposal intended to further the Commission's
policy of supporting the development of competitive markets for retail energy
will neither directly or indirectly affect the supply market prices in a manner
that would encourage increased energy usage not within the range of thresholds
and conditions set forth in the FGEIS in Case 94-E-0952 or not within that
contemplated by the Commission in its Determination of Non-Significance reached
in connection with the Gas Policy Statement. The Signatory Parties also believe
that the associated unbundling of the Company's rates as provided for in the
Joint Proposal will not result in delivery service rates that would encourage
energy usage not within the range of thresholds and conditions set forth in the
FGEIS in Case 94-E-0952 or not within that contemplated by the Commission in its
Determination of Non-Significance reached in connection with the Gas Policy
Statement.
K. NOISE AND ODOR IMPACT
The Signatory Parties were unable to identify any direct noise and odor
effects resulting from the Joint Proposal. However, as indicated above, new
construction or expansion of production, transmission or distribution facilities
could have potential environmental impacts. These impacts, however, would be
mitigated by regulatory requirements and SEQRA review at the time as noted by
the Commission in its Determination of Non-Significance reached in connection
with the Gas Policy Statement and within the range of thresholds and conditions
set forth in the FGEIS in Case 94-E-0952.
L. IMPACT ON PUBLIC HEALTH
The Signatory Parties were unable to identify any direct effects on public
health resulting from the Joint Proposal because under the Joint Proposal the
Company would continue to have the responsibility to maintain its facilities for
the transmission and distribution of natural gas and electricity in conformance
with all applicable regulatory requirements.
M. IMPACT ON GROWTH AND CHARACTER OF COMMUNITY OR NEIGHBORHOOD
The Joint Proposal's effect of reducing the cost of electricity and gas to
consumers will have a positive effect on the economic well-being of communities
in the Company's service territory. Price reductions along with the funding of
economic development initiatives as provided for in the Joint Proposal will
encourage local business growth and the retention and growth of employment. They
will also encourage the relocation of businesses to the Company's service
territory from outside New York State. In addition, the Joint Proposal includes
incentive regulation provisions which encourage the education of consumers
regarding energy competition to facilitate the development of the competitive
retail energy supply market.
It is possible that lower gas prices could lead to a potential for gas
distribution franchise expansions, as the Commission has recognized previously.
The potential for such expansions under the Joint Proposal is
limited, however, in light of the 20% penetration limitations on the
availability of the gas back out credits. Therefore, the potential impacts are
considered to be indistinguishable from those that would occur in the absence of
the Joint Proposal.
IV. SIGNIFICANCE OF ENVIRONMENTAL IMPACTS
After a review of the changes called for under the Joint Proposal, the
Signatory Parties conclude that no further environmental review is necessary
with respect to the Joint Proposal. No significant environmental impact which
would result from the subject Joint Proposal was identified. Any potential
effects are within the range of thresholds and conditions set forth in the FGEIS
in Case 94-E-0952 with respect to electric restructuring and within the
Commission's Determination of Non-Significance in Cases 93-G-0932 and 97-G-1380
with respect to gas restructuring.