By Michael Kuser
ALBANY, N.Y. — The planning for pricing carbon into NYISO’s markets should be more clearly defined, stakeholders told ISO and New York state officials Monday.
A good starting point: clarify the charter for the state’s Integrating Public Policy Task Force (IPPTF), some stakeholders contended.
“The problem we’re trying to solve is related to the Clean Energy Standard and trying to get 50% of [electricity] consumption from renewables, and one component of that is to incentivize clean generation. That’s what carbon pricing is doing,” said Anthony Fiore, director of energy regulatory affairs for New York City. “The other part is then to actually get that generation where the load is, which I think would be solved by a different set of tools.”
Stakeholders shared their views Nov. 20 at a third public hearing stemming from carbon pricing proposals set out in The Brattle Group report, and the second meeting of the IPPTF, a joint effort established by NYISO and the New York Public Service Commission in October to explore the carbon pricing issue. About 60 people attended the meeting, including PSC Commissioner Diane Burman. (See New York Stakeholders Question Carbon Pricing Process.)
Co-chairing the session was Nicole Bouchez, NYISO’s principal economist of market design, who said the purpose of the IPPTF is “to facilitate dialogue on market design alternatives” able to harmonize the ISO’s markets with the state’s carbon policies.
“That’s the goal. It is not a broader review of the [CES]. It is a fairly defined topic for the task force,” Bouchez said.
Fiore had a more expansive take of the IPPTF’s possible role.
“I understand that we can narrowly focus this task force, but I think it’s a mistake and a missed opportunity if we don’t lay out what the bigger issue is that lies behind this, because this is not the whole thing,” he said.
Erin Hogan of the Utility Intervention Unit at New York’s Department of Public Service shared Fiore’s concerns.
“If we had a defined goal of what we are trying to achieve, it would help develop the criteria to have an alternative analysis of the market design concepts,” she said. “As an analogy, in western New York, we had various transmission proposals and one party was advocating that their larger carbon reduction was a better option than the lower-priced transmission and also increased operability. So by not having those clearly defined criteria, it’s going to make it a little challenging to evaluate the alternative market design concepts.” (See Public Policy Tx Project Wins Key NYISO Endorsement.)
New York City Deputy Director for Infrastructure Susanne DesRoches said, “Our comments to the charter speak to needing to fully identify what the parallel processes are. For instance, how does transmission play into this conversation? We don’t want to be in a position to be pricing power in one part of the state higher than the other because we can’t get low-carbon power to the downstate region.
“Before we can go to the granular level of the questions on the table, we need consensus around what is the objective that we are trying to solve and how our other processes get us to that resolution as well.”
IPPTF co-chair Marco Padula, DPS deputy director for market structure, said, “You should identify those other processes and we should add them to this list. If you believe there are other processes that need to be studied, please, let’s add them.”
The hearing’s agenda listed 15 recommended topics, starting with carbon leakage and resource shuffling.
Carbon leakage is defined as an increase in emissions in states parallel to one reducing them. Resource shuffling refers to the practice of utilities scheduling their lowest-emission generators to serve areas with emission caps, while letting heavier polluters simultaneously serve customers in neighboring regions.
Bouchez emphasized the task force was looking more for questions than answers at this point, and that it would address the leakage issue more fully at a Dec 11 technical conference.
She identified questions arising from the group’s prior hearing, which included:
- How would a carbon charge be applied to interregional transactions?
- Should specific charges be applied to each neighboring region, or should the same charge be applied to all?
- Would crediting the carbon charge on exporting interregional transactions create incentives to sell power out of state?
- Will the biggest emitters see this as an incentive to export more energy from New York?
Mark Younger of Hudson Energy Economics said the question of whether to apply a carbon charge to resources under 25 MW or to any fossil-fuel backed distributed energy resource also has leakage implications.
“In other words, not applying to those examples is a form of leakage,” Younger said. “You can take a relatively efficient wholesale generator, and because you’re adding a carbon charge to it, [you’re] making it look like it’s [more] desirable to run a sub-25-MW, much-less-efficient resource rather than take power from there. And that’s the same thing we’re talking about with external areas as well.”
Miles Farmer of the Natural Resources Defense Council said that leakage is a retail — as well as wholesale — market issue. “As we’ve heard, there’s DER leakage, potentially, leakage to other sectors, and then I think there’s also a role for DPS in setting the policy in regard to leakage that then NYISO could implement,” he said. “To some extent, that’s a substantive question that I imagine different stakeholders will have different views on.”
Pricing Carbon Affects Everything
Stakeholders said many of the topics were interrelated, such as whether locational-based marginal prices should transparently reflect carbon charges, how to apply the cost of carbon to generator emission rates ahead of delivery, how to allocate carbon revenues, and the possible effects of a carbon price on the capacity market.
NYISO Senior Manager for Market Design Michael DeSocio said, “If you take a DER that is a combination of renewable and non-renewable, I’m not sure when we aggregate those two pieces up to a single resource that we will know exactly how to apply that cost of carbon, but we certainly know after it runs what it did and how much to charge it.” He said the carbon charge might be an opportunity cost-based process in which a resource will be charged after the fact but will need to determine beforehand what cost to incorporate into its offer.
“Or do we need to figure out all the permutations of every configuration of every facility to then apply a cost up front directly into the offer?” he said. “There are some pros and cons to both sides. We first start to think about this with generator fuel blends, but then you take it down the path where we had discussions this morning about DERs, and it gets even more complicated.”
Kelli Joseph, NRG Energy’s director of market and regulatory affairs, said that pricing carbon would not change the dynamics of New York’s grid, where lopsided load balances create transmission constraints between upstate and downstate, particularly around New York City and Long Island.
“Thinking about changes and what’s needed in the capacity market, we’ve said look at what New England has been talking about and what PJM has been talking about,” Joseph said. “They’re talking about moving towards a two-tiered clearing market where you have resources that are brought on because of state policy, and that’s highly likely to continue here even if you price carbon because of this transmission issue. … Even if we price carbon, what we do in the capacity market has to be a big part of this discussion.”
Howard Fromer, director of market policy for PSEG Power New York, asked how the sector will determine the social cost of carbon.
“We can’t have a situation where we define the problem at $45 but our solutions are multiples of that,” Fromer said. “I don’t know how you sell that to the public and explain to them why you should pay more than what you said the problem is worth. That doesn’t work too well.”
DeSocio said NYISO planned to use a Dec. 5 joint Market Issues Committee and ICAP Working Group meeting to brief stakeholders on what other RTOs are doing to integrate public policy in wholesale markets.
Bouchez said the task force would hold a technical conference Dec. 11, but that it was unclear whether it would be necessary to hold the public hearing scheduled for Dec. 18, given its proximity to the holidays. Regardless of what meetings take place in December, the task force still plans to issue an initial work plan to stakeholders by the end of January, she said.