ConEd To Include New Costs In Electric, Natural Gas Default Service Rates Under Rate Case Settlement
Joint Proposal Includes Retail Access Provisions
Updated Billing, Payment Charge For ESCOs
October 21, 2019 Email This Story Copyright 2010-19 EnergyChoiceMatters.com
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Consolidated Edison (the "Company") would include new costs in its default service supply rates for electricity and natural gas in a joint proposal (JP) filed by various parties in ConEd's current rate cases before the PSC
Under the JP, ConEd would modify General Rule 25.2.2(b), Adjustment Factor - MSC II
(Leaf 333) of the Electric Tariff to include all costs associated with the procurement of
energy and capacity hedges and supplies for Customers, including auction platform
licensing fees, maintenance fees, customization fees and related costs.
Further, the JP includes changes to the Gas Cost Factor (GCF). Under the GCF in General Information Section VII,
fixed gas costs would be modified to include costs for
capacity, including fees, purchased through third party
Asset Management Agreements; and any fixed charges
associated with Renewable Natural Gas ('RNG'). Furthermore, under the GCF in General Information Section VII,
variable gas costs would be modified to include all costs
associated with using online auction platforms
including licensing, maintenance, customization fees
and related costs; and supply costs associated with
Electricity - Merchant Function Charge, Billing And Payment Processing Charge
The JP provides that competitive delivery rates for Con Edison customers, i.e., the MFC including the credit
and collection ('C&C') related component of the Purchase of Receivables Discount
Rate, were set in each Rate Year to reflect the revenue requirement for each Rate Year. The MFC for Con Edison customers consists of two components: a supply-related
component, including a purchased power working capital component, and a C&C
related component. There were separate MFCs calculated for (1) SC 1 customers, (2)
SC 2 customers, and (3) all other customers.
i. For each Rate Year, revised revenue levels for the MFC supply-related and
C&C related components were based on percentages of delivery revenue as
determined in the 2017 ECOS study. The resulting revenue requirement
was then divided by the Rate Year full service customer sales in each group
to determine the $/kWh supply-related portion of the MFC for each service
ii. The Rate Year revenue requirement for the C&C related component of the
MFC was developed by multiplying the total Con Edison T&D Rate Year
delivery revenue requirement by the percentage represented by C&C related
costs for each group, inclusive of C&C costs attributable to the Purchase of
Receivable ('POR') Discount Rate. The total Rate Year C&C related
revenue requirement was split between full service and POR customers
based on the respective split of full service and POR forecasted Rate Year
kWh sales. The C&C related rate component to be recovered through the
MFC from full service customers was then determined by dividing their
share of the C&C related Rate Year revenue requirement for each group by
the corresponding forecasted Rate Year kWh sales.
iii. The C&C related rate component to be recovered through the POR discount
rate was set in each Rate Year to reflect the calculated portion of total C&C
costs attributable to POR customers, the estimated Rate Year POR kWh
sales, and the forecasted level of POR supply costs in the Rate Year.
iv. The proposed rate associated with the purchased power working capital
component of the MFC was computed by dividing the purchased power working capital requirement for each Rate Year by forecasted Rate Year
full-service customers’ sales to derive a per kWh charge that was added to
the applicable competitive supply related MFC component for each service
v. Competitive metering charges, which consist of meter data service provider,
meter service provider, and meter ownership component charges, have been
eliminated and recovery of metering costs was transferred to base delivery
rates at the current (2019) rate level. For Rate I of SCs 5, 8, 9, and 12,
meter costs have been transferred to the minimum delivery demand charges
at the current level of non–mandatory hourly pricing ('MHP') meter
charges and the remaining meter costs (i.e. incremental meter costs
associated with MHP customers) for these classes are recovered in the
demand charges. The metering costs for the mandatory TOD rates of SC 5,
8, and 9, 12, and 13 were transferred to a newly created customer charge,
initially set at the level of the current metering charges. The metering costs
for customers served under voluntary TOD rates of SC 8, 9, and 12 were
transferred into a new customer charge initially set at the weighted average
of the current rate level for MHP and non-MHP customers. Standby rates
also reflect the metering costs in the customer charges. With the elimination
of competitive metering charges, the competitive metering credits applicable
to NYPA were eliminated.
vi. The billing and payment processing charge applicable to Con Edison
customers was increased from $1.20 to $1.28 per bill. For customers with a
combined electric and gas account, the portion of the charge applicable to
electric service is $1.28 less the amount applicable to gas service (e.g.,
$0.64). Likewise, ESCOs pay $1.28 per bill per account, unless a customer
has two separate ESCOs. In that case, the charge to the electric ESCO is
$1.28 less the charge applicable to the gas ESCO (e.g., $0.64).
The JP would update the electric residential and commercial Uncollectible Bill ("UB") factors related to the UB expense associated with MSC and Adjustment Factors-MSC charges based on a UB factor of 0.0046 or
($0.46 per $100). The JP would update in General Rule 25.3(d) of the Electric
Tariff (Leaf 336) to reflect UB factors of 0.0072 for residential
customers and 0.0028 for all other customers.
Natural Gas - Merchant Function Charge, Billing And Payment Processing Charge
The JP sets forth the total revenue requirement targets, in dollars, for the Supply-Related Component and C&C Component of the Merchant Function Charge, and C&C Component of the Purchase of Receivables (POR) discount rate. The JP does not translate these into per kWh or therm, or % amounts, at this time.
For natural gas, separate MFC charges will continue to be established for SC 1, SC 2 Rate I, SC 2 Rate
II, SC 3, and SC 13. For the Supply-Related component and for the C&C component,
different unit costs will be set for residential and for non-residential classes. At the end
of each Rate Year, the supply-related and C&C components of the MFC will be trued up
to the Rate Year design targets and any reconciliation amount will be included in the
subsequent year’s calculation of the MFC.
The charge for Uncollectible Accounts Expense (UBs) associated with supply will continue to be based upon actual supply
costs for each month included in the Company’s monthly Gas Cost Factor (GCF). The
UBs associated with supply costs will be included in the MFC. Separate UB factors will
be calculated for each of the three GCF groupings and will be update to reflect the
overall uncollectible rate of 0.46%, with uncollectible rates of 0.72% for residential
customers and 0.28% for non-residential customers.
The billing and payment processing charge (BPP Charge) for gas will increase to $1.28 for single service gas customers who purchase both their commodity and delivery from the Company and for retail access
customers receiving separate bills from the Company and the ESCO. Dual service
customers will pay no more than $0.64 for gas BPP.
The parties agree that no party supporting the Joint Proposal has waived its right
to file a petition with the Commission to address, on a generic basis, issues related to the
methodology used to compute the MFC and Credit and Collection Costs and Billing Back
Retail Access Issues
The JP includes the following provisions concerning retail access
The Company will create a centralized process for regular updates to energy
service companies ('ESCOs') via the Retail Access newsletter that is emailed to all
ESCOs and posted on the Company’s website. Day-to-day communications with ESCOs will continue outside of the newsletter process. The Company will endeavor to respond
to simple inquiries -- i.e., inquiries that do not require investigation or detailed review --
that are made to ConEd's retail access email address within three business days. If the Company
requires additional time to respond to inquiries, the Company will notify the ESCO that
additional time is necessary. Further discussion on the types of inquiries and response
expectations to be addressed at first annual meeting referenced in below.
Regular Gas Marketer Collaborative Meetings: Regular Meetings will be held at least twice each rate year (though Collaborative
Members may collectively decide to hold additional meetings). Meeting notices and
proposed agenda items shall be circulated via email to the email distribution and made
available on the Company’s ESCO website for the Gas Marketer Collaborative at least
one week prior to scheduled meetings. Any Collaborative
Member may propose to add items to the proposed meeting agendas.
Special Collaborative Meetings: The Company agrees to convene a Special Collaborative that will be limited in
duration to six months, beginning within 90 days of the Commission’s Order adopting
this Proposal. During that time, Special Collaborative Meetings will be held at least once
during each of the first two months and then every other month thereafter. By consensus,
the Collaborative members may agree to schedule additional meetings and/or
teleconferences. The Special Collaborative will discuss the following issues:
• Intraday Nomination Flexibility for Virtual Storage;
-- How Virtual Storage Inventory Costs are Computed;
-- Intraday City Gate Allocations;
• Baseload peaking basis costs;
• Timely Cash Out Invoices;
• Alternative method to satisfy credit and security requirements related to
• POR Disbursements Adjustments;
• An informational presentation on the components of the MRA;
• Details of how Con Ed will notify ESCOs of changes proposed by upstream
pipelines that will affect rates;
• A presentation on how gas operations handles nominations for excess city gate
• No harm-no foul rule for non-firm daily balancing.
Within 60 days of the last Special Collaborative Meeting, the Company will
submit a report to the Secretary describing the Special Collaborative discussions. Any issues considered in either the Regular Collaborative or the Special
Collaborative will be resolved in a manner that is revenue and earnings neutral to the
Annual Electric Marketer Meeting
Starting in 2020, the Company will hold an annual meeting each year with ESCOs
and other third parties to answer questions on the electric retail choice program. Four
weeks before the meeting, the Company will solicit comments, suggestions on topics to
be covered and questions from ESCOs using the Company’s distribution lists for gas and
electric ESCOs. The Company will provide a summary of the agenda items discussed at
the annual meeting in its Newsletter.
Updated Reference Materials for CSRs
The Company agrees to provide annual updated reference materials for call center
representatives to update them on retail access developments including changes in rates
charged ESCO customers and changes in UBP rules. The Company agrees to provide
communications to remind CSRs [Customer Service Representatives] of the procedure to follow when ESCO customers call
with questions about their bill. ESCOs can at any time reach out to the Company via
established channels to provide suggestions for materials or information that should be
available to utility call center representatives.
Changes to Transportation Customer Information System
The Company will make changes to its Transportation Customer Information
System ('TCIS') that reject nominations from approved gas marketers that over-nominate
at City gates for firm supply under the Company’s DDS program. The
Company will complete these changes to TCIS by December 31, 2021.
Electricity - Optional Demand-Based Rate With Time Of Use Supply Rates
Under the JP, the Company will establish an optional demand-based rate, which will be
available with no cap to (a) existing residential geothermal customers and (b) new
residential geothermal customers that meet the Company’s requirements for its heat
pump program to be launched during 2020. This rate will also be available to up to 5,000
other residential customers, including residential geothermal customers that do not meet
the requirements. This rate will be based on the rate structure of Rider Z, Rate IV, and
include a $27.00 customer charge, which reflects the full customer cost set forth in the
2017 ECOS study. The supply component of this rate will assess time-of-use supply for
full service customers. In addition, this Optional Demand-Based Rate will be subject to
review in the Company’s next electric base rate case.
Electricity - New RTO, Generation Charges
The Signatory Parties agree that whenever the Company is or will be subject to
governmental or regional transmission organization ('RTO') transmission and/or
generation-related charges, costs or credits (e.g., FERC, NYISO, PJM, or EPA) not
already listed in or otherwise covered by the then-effective Supply and Supply-related
Charges and Adjustments and the MAC tariff language, notwithstanding the
Commission’s adoption of this Proposal, the Company may make a tariff filing with the
Commission providing for recovery of such charges/costs, or application of these credits,
through the Supply and Supply-related Charges and Adjustments and the MAC
mechanism and/or comparable adjustment mechanism, as appropriate. The proposed
tariff amendment may include charges/costs/credits applicable to the period prior to the
effective date of the tariff amendment.
Bill Redesign & New Customer Service System (CSS)
The JP provides that, concerning ConEd's ongoing Bill Redesign Program., ConEd shall file evaluation reports annually by March 1 with the Secretary.
The reports will include the number of
customers adopting ebills, reduced costs for printing and postage, and
customer use of the digital platform.
The Company will also submit to
the Secretary the results of its Phase Two analysis and prototype bill
redesign recommendations for review with Staff prior to implementation.
The JP would authorize the Company’s implementation of a new CSS, subject to a $421 million cap on capital
The JP provides that the Company will schedule two stakeholder meetings during 2020 to discuss
stakeholder requests regarding CSS technical features and requirements.
During the term of the Electric Rate Plan, the JP provides that the Company will implement two
energy storage projects as described below.
Fox Hills Project
The Company will implement one in front of the meter energy storage project at
its Fox Hills substation. The current plan is for the project to include a battery that will
discharge over a peak period of four hours at an output of 7.5 MW/30 MWh to provide
relief during system contingencies during high load days.
Nevins Street Projects – Battery Storage and Electric Vehicle
The Company will implement two projects at its Nevins Street location in
Brooklyn -- Battery Storage and DCFC Charging. Pursuant to the Battery Storage
project, the Company will make the site ready for a battery installation and lease the
property to a third party(ies) to own and operate a battery facility(ies) on the site. The
Company will file a Public Service Law Section 70 petition for approval of this lease.
In addition, the Company will propose as a REV demonstration project that it will
contract with a third party to own and operate a DCFC facility, which will be supported
by the battery energy storage project to mitigate the effects of DCFC load during peak
The Company’s Innovation Hub is a corporate-wide initiative, "to implement
transformative innovation projects."
This group will meet with DPS Staff twice each rate year,
in February and August, to review the group’s existing portfolio, provide updates to
existing projects and discuss the Company’s then-current strategy for the group. The
Company will also meet annually with interested parties to discuss the Innovation Hub’s
The JP does not include any provision for adoption of ConEd's proposed voluntary renewable energy supply option for electricity customers (see details here)
The JP was filed by Consolidated Edison Company of New York, Inc. ('Con
Edison' or 'Company'), New York State Department of Public Service Staff ('Staff'),
the City of New York ('NYC'), Association for Energy Affordability ('AEA'),
Blueprint Power, CALSTART, ChargePoint, Inc., Consumer Power Advocates ('CPA'),
Direct Energy Services ('DES'), Environmental Defense Fund ('EDF')(Case 19-E-0065
only), Metropolitan Transportation Authority ('MTA'), Natural Resources Defense
Council ('NRDC') (Case 19-E-0065 only), New York Energy Consumers Council
('NYECC'), New York Geothermal Energy Organization ('NYGEO'), New York State
Office of General Services ('OGS'), New York Power Authority ('NYPA'), New York
Retail Choice Coalition ('NYRCC'), the Sabin Center for Climate Change Law at
Columbia Law School, Bob Wyman, and other parties whose signature pages are or will
be attached to this Proposal (collectively referred to as the 'Signatory Parties').