By Michael Kuser

RENSSELAER, NY – NYISO said Monday it could implement carbon pricing in New York’s wholesale electricity markets no earlier than the second quarter of 2021.

That “date is intended to provide certainty to energy trading markets that are currently pricing power prior to Q2 2021,” Michael DeSocio, senior manager for market design, told a July 16 meeting of the state’s Integrating Public Policy Task Force (IPPTF), the group exploring how to incorporate the cost of CO₂ emissions into NYISO’s markets.

The ISO also proposed wholesale market suppliers with active renewable energy credit (REC) contracts dated prior to Jan. 1, 2020, not be eligible to receive the carbon pricing portion of the market’s locational based marginal prices (LBMP) as part of their payment for supplying energy.

The cutoff date would help reduce or eliminate the potential for double payments to resources eligible for REC payments, DeSocio said.

Emissions Reporting

Speaking at the meeting, Ethan Avallone, NYISO senior market design specialist, presented proposals on emissions reporting, billing and bilateral transactions under a carbon pricing scheme.

The ISO is proposing to develop a process for generators to report how much carbon they are emitting and later true-up their data based on actual emissions. The ISO would issue applicable charges or credits to adjust payments based on reported actual emissions.

Representing New York City, Couch White attorney Kevin Lang asked, “If what they’re reporting is their actual emissions, what is the true-up?”

“In some cases, the initial reporting could be an estimate of emissions,” Avallone said.

“Our understanding also is that there’s a lot of validation that happens to some of this data, so it’s allowing for that validation process to happen,” added IPPTF Chair Nicole Bouchez, the ISO’s principal economist.

Some CO₂-emitting resources submit emissions data to EPA, while others provide data to the state’s Department of Environmental Conservation. Some resources submit no data at all. But the majority of emitting resources should already have processes in place enabling them to provide emissions data to the ISO, Avallone said.

Billing Overview

The proposal calls for emitting resources to provide the ISO with weekly emissions data estimates during the billing month, while also providing updated emissions data when available. Bills from the ISO become final roughly eight months after the initial monthly invoice.

NYISO envisions that adjustments to the carbon charge would be paid to or collected from emitting resources that provide emissions data updates before a specified deadline for emissions reporting, which could be consistent with the current billing challenge period of up to five months after the initial invoice.

Resources that report to the ISO that they are subject to the Regional Greenhous Gas Initiative would be charged the gross social cost of carbon (SCC) minus the most recently posted quarterly RGGI price. Suppliers not covered by RGGI would incur a carbon price equal to the gross SCC.

Lang suggested greater granularity in the RGGI price calculation could help the ISO minimize the risk of over- or underpaying generators.

He said previous RGGI prices have fluctuated and future price estimates vary significantly, adding that generators purchase RGGI allowances at different times and in multiple ways.

For those reasons, Lang said he was concerned about basing the carbon price adjustment solely on a quarterly auction price.

In response to a request to use the actual RGGI price paid by the resource instead of the quarterly price, Bouchez said such a move would shift the risk from asset owners to consumers.

“In our markets we push that risk onto the asset owners,” Bouchez said. “They’re the ones best suited to manage that, and the consumers shouldn’t have to pay for that risk.”

The ISO additionally proposed that CO₂-emitting resources injecting into the grid to fulfill a bilateral transaction would also be subject to the carbon charge.

Transmission customers purchasing energy through bilateral transactions would receive an allocation of the carbon residual. This treatment would be similar to how other billing residuals are allocated to transmission customers’ actual energy withdrawal, Avallone said.

Progress Check

Bouchez presented a review of draft recommendations for expected changes to the carbon pricing straw proposal presented in April. (See NYISO Floats Carbon Pricing Straw Proposal.)

The plan calls for the IPPTF to deliver draft recommendations by Aug. 1, including suggestions regarding additional meetings or work anticipated by the task force. The group will finalize recommendations by the end of October and issue the proposal by the end of December 2018.

“We would request that when NYISO issues its straw proposal August 1, [New York Department of Public Service (DPS)] staff at the same time give a status update on how the process is going and whether or not it’s still supported. It would be helpful to understand DPS’s plans with regard to timeline and decision points on issues that are within its control, as in the setting of the carbon price,” said Ben Carron, National Grid’s senior analyst for regulatory strategy and integrated analytics.

“We’re still as committed as we were day one to review pricing carbon and determine whether or not it’s cost effective,” DPS Manager Alan Michaels responded.

The IPPTF said it foresees no changes to the concept of carbon pricing, and the analysis will use the gross SCC as recommended by DPS staff in April, which was based on a value already adopted by the Public Service Commission using the figure from the Interagency Working Group (IWG) on Social Cost of Greenhouse Gases.

The PSC’s March 2017 Value of Distributed Energy Resources (VDER) Order (15-E-0751) set the compensation value at the higher of the Tier 1 REC or SCC minus RGGI. Converted by DPS to dollars per ton, the latter figure would gradually increase over the coming decade from $40.74/ton in 2020 to $56.77/ton in 2030.

The carbon charge will be applied to internal suppliers, and the task force will add more details to the emissions reporting proposal and also consider that emitting resources might only report EPA-accepted data.

The task force’s remaining work includes adding details to the proposal to estimate the carbon component of the LBMP for transparency, and application of the carbon charge to external transactions, which will reflect the July 9 presentation on benefits and drawbacks of the two options considered. (See New York Looks at Carbon Price Impact on LBMPs.)

Regarding allocation of the carbon charge residuals to loads, issue Track 5 of the carbon pricing initiative will report the allocations of all three possible methodologies, as well as changes to other ISO markets and planning processes, Bouchez said.

The task force next meets Aug. 6 at NYISO headquarters to review draft recommendations for issue Track 5 regarding customer impacts, especially the assumptions used in modeling a dynamic change case.