NiMo Proposes New Opt-Out Critical Peak Supply Rate For REV Demo; Also Proposes Pilot Delivery Rates Applicable To Both Utility Supply, ESCO Customers
February 18, 2019 Email This Story Copyright 2010-19 EnergyChoiceMatters.com
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Niagara Mohawk Power Corporation (the "Company") has, at the New York PSC, proposed modifications to its Clifton Park Demand Reduction REV Demonstration Project
The proposed changes, which have a proposed effective date of February 1, 2020, are designed to test two opt-out pricing structures: 1) a time-of-use
('TOU') and critical peak pricing ('CPP') supply rate as initially proposed in the Company’s
Advanced Metering Infrastructure ('AMI') Report (the 'AMI Rate'); and 2) a 'Beneficial Electrification Rate' that combines the TOU / CPP supply component from the AMI Report with
a two-demand delivery charge, or such other rate as approved by the Commission in response to
the Company’s Beneficial Electrification Proposal.
Beginning in the fourth quarter of 2019, the Company proposes randomly assigning
customers in the Clifton Park Demonstration into two groups, an 'A Group' and a 'B Group.'
The Company will place customers in the A Group on the AMI Rate and customers in the B
Group on the Beneficial Electrification Rate
Customers who purchase their supply from an energy service company ('ESCO') will continue
to receive supply from their ESCO; however, for delivery, half of the ESCO customers will see
no change in their delivery rates consistent with A Group customers, while the other half of
ESCO customers will be placed on the two-demand delivery rate consistent with customers in
the B Group (Beneficial Electrification Rate).
For the A Group customers taking utility supply, NiMo proposes testing a volumetric supply AMI
Rate comprised of TOU and CPP components combined with a traditional volumetric delivery
rate. The TOU portion, which is designed to recover energy-related supply costs, includes an on-peak
period from 10 a.m. to 9 p.m. non-holiday weekdays. The Company will set the TOU rate
using the forecasted locational-based marginal price ('LBMP') for each month, as modified by
additional design criteria to ensure a suitable difference between the on-peak and off-peak prices
to incentivize customer response. The TOU energy supply charges will be set monthly and
collections will be reconciled to actual supply costs through the Electric Supply Reconciliation
For CPP, the Company proposes 70 hours of annual peak events designed to recover
Installed Capacity ('ICAP') charges. The CPP rate will be set annually based on a forecast of
the Company’s annual capacity costs. Additionally, the rate will be set using design criteria that
encourages a customer response to reduce or shift load during CPP events. An example of the
methodology to calculate the annual CPP rate is included as Appendix C. The Company will
call CPP events on a day-ahead basis, when the Company expects system conditions may reach
the annual New York Control Area ('NYCA') system peak; such events will not exceed 70
hours per calendar year. As with the forecasted TOU rate, the Company will reconcile the CPP
capacity costs through the ESRM.
The proposed Beneficial Electrification Rate consists of the same volumetric TOU /
CPP supply rate proposed in the AMI Rate combined with a 'two-demand' delivery rate. The
proposed delivery rate includes a non-coincident peak demand component (the 'Customer Peak
Demand'), which is designed to recover a customer’s contribution to local distribution costs.
The Customer Peak Demand includes: 1) the portion of the rate class customer-related costs that
are not recovered in the current (and proposed) customer charge; 2) secondary distribution demand-related costs; and 3) a portion of primary distribution and transmission costs. It is
calculated as the average of the customer’s three highest demands in a billing period that do not
occur on the same day. The demand delivery rate also includes a coincident peak demand component (the
'System Peak Demand') designed to align customer price signals during the summer system
peak billing period with each customer’s respective responsibility for the costs to serving the
Company’s system peak load. The System Peak Demand includes: 1) a portion of primary
distribution-related costs not included in local distribution costs; and 2) transmission costs. It is
calculated as the average of a customer’s three highest demands in a billing period that do not
occur on the same day, but that occur on separate non-holiday weekdays during the hours of 1
p.m. to 6 p.m. from June through September. An example of the methodology used to calculate
the two-demand delivery rates is included as Appendix D.
Finally, the delivery charge includes the current monthly customer charges applicable to
the customer’s rate class.
All customers enrolled in the proposed rates will receive a one-year bill guarantee at the
end of twelve months