By Michael Kuser
RENSSELAER, N.Y. — NYISO on Monday floated a plan to calculate the carbon pricing impact on locational-based marginal prices (LBMPc) using the social cost of carbon (SCC) as determined by the New York Public Service Commission, while also altering its recommendation for allocating carbon charge residuals.
Both proposals came up as part of New York’s ongoing effort to explore how to incorporate carbon pricing into the state’s wholesale electricity market through the multi-agency Integrating Public Policy Task Force (IPPTF).
Ethan D. Avallone, ISO senior market design specialist, told the IPPTF that the market would generally use the net SCC to determine the carbon reference level for a CO2-emitting generator that functions as the marginal resource.
While the grid operator needs to calculate the LBMPc in order to allocate carbon credits to load-serving entities, most internal generators would not be charged the LBMPc, instead being charged for their actual emissions.
The NYISO straw proposal envisions including carbon pricing in the market using the existing offer structure, Avallone said. During intervals when there are too few marginal resources to calculate LBMPc, the ISO proposes “to persist” the last carbon impact to the LBMP from the prior interval.
IPPTF Chair Nicole Bouchez, the ISO’s principal economist, said, “In practice, we back into the marginal units by looking at whether resources have their offer equal to the LBMP at their location. Given that, when the demand curves are active, we can’t use that method to back into what resources are marginal.”
Pallas LeeVanSchaick of Potomac Economics, the ISO’s Market Monitoring Unit, said that while that approach seems most convenient, it “would have pretty significant implications and you would get very different results from what was presented in the consumer impact studies on this.”
One reason is that hydro units are on the margin nearly 50% of the time in New York, which eventually reflects an energy storage problem, LeeVanSchaick said. “If you back down hydro in one hour, you’re going to get more hydro in another hour, which is likely to reduce output from a carbon-emitting generator.”
“The idea generally is that if you do have to use the next unit on the margin, that’s a change,” Avallone said. “So we’ll take that back and think about it.”
“I’m glad you’re taking it back,” said Warren Myers, director of market and regulatory economics for the state’s Department of Public Service. “This has always been a really big issue conceptually for us — what you do about the storage hydro that’s limited over the course of a year. We know that in a given hour it does not have zero carbon consequences. If it ramps up or down, it affects the carbon in other hours.
“It’s not a trivial implementation, in-the-weeds issue. It’s a big deal.
“With respect to the harmonizing with state policy,” Myers continued, “whenever DPS has tried to figure out what the [carbon] content on the margin is, we do not treat these hours as if they’re zero carbon. We try to somehow, heuristically or however … treat these resources as if they’re combined cycle gas units.”
LeeVanSchaick said the MMU takes a similar view of the opportunity costs for hydro units. He recommended the ISO “consider alternatives to just using the real-time market software’s flags” to determine which fuel is on the margin. He also recommended the ISO address what principles and objectives it seeks to achieve with the method to help evaluate its success in doing so.
As part of the state’s evolving plan to price greenhouse gas emissions, a carbon charge would also be applied to most wholesale market suppliers holding renewable energy credit contracts with the New York State Energy Research and Development Authority. (See NY Carbon Task Force Looks at REC, EAS Impacts.)
For the carbon charge residual that results from charging suppliers for their carbon emissions, NYISO now recommends a proportional allocation approach, saying it would provide an equitable impact to consumers consistent with the current REC contract cost allocation to load, Avallone said.
NYISO originally proposed a levelizing approach but revised its recommendation based on recent analysis, Avallone said. It considered that there was a higher percentage impact to upstate load relative to downstate load under levelizing methodology compared with the proportional percentage allocation.
At the Sept. 24 IPPTF meeting, the Brattle Group provided a comparison of the carbon residual allocation options as part of the carbon pricing consumer impact analysis. That analysis showed that the proportional allocation methodology minimizes cost shifts among consumers, Avallone said. Allocation would not affect revenues to generators, who would receive the LBMP, inclusive of the carbon impact.
Brett Kruse, Calpine’s vice president for governmental and regulatory affairs, told the task force how NYISO’s proposed “clawback” of the carbon price from the LBMP provided to resources with REC contracts might affect lender-required financial hedges required for renewable generation financing.
“As proposed by NYISO, removing carbon prices from LBMP of some contracted generation is very disadvantageous to those of us with hedges in place,” Kruse said.
Under NYISO’s current proposal, the power produced by a unit with REC contracts would be settled at the LBMP net of the carbon charge (that is, after the clawback), but energy hedges would be settled at the actual LBMP, reducing the unit’s revenues.
Calpine proposes applying a discount that modifies the carbon price to account for the estimated carbon emission savings from existing RECs. The company argued that a discount to the SCC that decreases as REC contracts roll off could integrate the beneficial impacts of RECs and carbon pricing without disrupting commercial hedging practices needed by most renewable energy projects.
“The way these hedges work, and this is quite typical even if you’re not talking wind generation, is they sell at the hub,” Kruse said. “Because of the liquidity value at the hub, they don’t settle at the individual generator node. The banks … don’t want to write a hedge that settles at your node.”
The most popular type of hedge is a fixed-for-floating price swap, where a project company receives a pre-agreed fixed dollar-per-megawatt-hour price from a bank, and the project pays the bank the underlying LBMP, which ensures a certain amount of energy revenue for the project, he said.
While the New York Power Authority buys both RECs and power, NYSERDA just purchases the RECs, “so in today’s world, it’s not the late 90s where you had a lot of financing. … The markets started to unbundle … and the banks are very skittish about who they give their money to,” Kruse said.
There are only one or two companies with a large regulated business at their core who do renewables on the side that have big enough balance sheets to finance their own projects. “The rest of us cannot, so we have to get financing for the whole thing, and as a result, the financing requires us to get the hedge on the power side,” Kruse said.
Daymark Analysis Update
Marc Montalvo of Daymark Energy Advisors said his “massive slide deck” of an analysis on the carbon pricing scheme, updated from last month, has as its major theme “humility in the face of complexity.”
“This proposal adds more than a small wrinkle to the marketplace,” Montalvo said. “How we get it implemented matters an awful lot.”
Brattle took a no-arbitrage model with fairly low friction and fairly low transaction costs and estimated net benefits to consumers, he said.
“What I wanted to understand is what happens if you perturb those things?” Montalvo said. “What happens if there is friction, what happens if there are actually higher transaction costs? What happens if the implementation and the consequent behaviors that underlie the no-arbitrage premise don’t hold up?”
Daymark’s perturbed model, particularly regarding border charges, increases market volatility, with asymmetric results, “which means things tend to be worse, not better,” Montalvo said. Similarly, charges on internal resources “and the way the carbon charges are estimated and calculated really does matter.”
The analysis also found that the carbon charges proposed are not sufficient to motivate the volume of buildout being sought under the state’s Clean Energy Standard without further public policy action.
“You don’t get 15,000 MW of renewables over the 12-year study period with the carbon charge by itself … [and] a lot of the non-market barriers are not addressed at all by a carbon charge,” Montalvo said.
The task force next meets via teleconference on Nov. 9 to talk about three recent analyses and updates by Brattle, Daymark and Resources for the Future (RFF), and how they interrelate.