A proposal to embed the cost of carbon emissions into New York's wholesale electricity markets will likely increase wholesale prices, suppress nuclear subsidies, and raise energy revenues for certain new renewable resources, according to reports by the state grid operator and a research firm.
A stakeholder task force, dubbed the Integrating Public Policy Task Force, was formed by the New York ISO in the autumn of 2017 to study the impacts of incorporating the cost of carbon dioxide emissions into New York's power markets as the state aims to cut greenhouse gas emissions 40% from 1990 levels by 2030. Simultaneously, Gov. Andrew Cuomo directed New York's power utilities to procure 50% of their electricity needs from renewables by 2030 and provided subsidies to four upstate nuclear power plants that were economically at-risk of early closure.
In response to those developments, the NYISO on May 12 released a "straw proposal" on incorporating the "social cost" of carbon emissions into its wholesale electricity market by tacking a charge onto supply offers of generators as measured by dollar-per-ton of CO2 emissions. As such, nonemitting generation, such as nuclear, conventional hydropower, wind and solar, would not incur a carbon charge.
In a May 21 presentation of the proposal to the task force, NYISO officials said the grid operator supports a "reasonably, transparent and predictable" carbon charge that avoids "distorting dispatch decisions." It also wants to implement carbon pricing in an economically efficient manner while avoiding major cost shifts and providing market and regulatory stability.
Under the proposal, the New York State Public Service Commission would set the gross social cost of carbon on generators' emissions at the "point-of-production" but would deduct allowance prices for those suppliers required to hold allowances from the Regional Greenhouse Gas Initiative aimed at cutting greenhouse gas emissions. The NYISO would also charge electricity imports for emissions and credit exports for avoided emissions to prevent emissions "leakage" and market distortions.
NYISO staffer Nathaniel Gilbraith explained that the carbon charge would cover all power generators, including distributed energy and behind-the-meter resources, but only for emissions associated with wholesale energy and ancillary services. He added that carbon pricing would not cover upstream or "fugitive" CO2 emissions or other greenhouse gas emissions such as methane and nitrous oxide.
Gilbraith said the grid operator wants feedback on how to determine carbon charges for cogeneration resources but for now is recommending that only emissions associated with electricity generation, and not heat and steam, be subject to the charge.
The presentation offered two examples of potential carbon charges. The first covers the startup emissions costs of a natural gas combustion turbine, or NGCT, when reaching its minimum generation level of 500 MMBtu at a emissions rate of 0.06 tons CO2/MMBtu and a carbon price of $40/ton. The NGCT would be charged $1,200 for 30 tons of CO2 under this scenario.
The second example outlined the carbon costs for a NGCT that is fully online and generating 500 MWh at a constant heat rate of 9.5 MMBtu/MWh. Burning through a fuel consumption of 4,750 MMBtu at a emissions rate of 0.06 tons CO2/MMBtu, the NGCT would produce 285 tons CO2 and be charged at $40/ton for a total of $11,400, or an average of $22.80 per MWh.
Brattle Group's study on market impacts
The Brattle Group, a research firm, also shared during the same stakeholder meeting the results of its own study that found a carbon charge would increase energy revenues for new "Tier 1" renewables that are supported by the state's renewable energy credits. Prices would not be reduced for fixed-price REC contracts that are in place, the study said.
The study also assumed that each increase in wholesale energy prices for Tier 1 renewables would reduce their REC prices dollar-for-dollar, although this offset could be lower due to differences in risk because unlike carbon charges RECs are guaranteed.
Brattle also looked at the impact of carbon pricing on New York's zero-emissions credits, or ZECs, that compensate at-risk nuclear power plants for avoided emissions. It said the formulated ZEC prices would automatically adjust to changes in wholesale energy and capacity prices. "Carbon charge would increase wholesale energy prices, decreasing ZEC prices on a dollar-for-dollar basis," said Brattle.
Brattle estimated that in 2025 a nuclear unit would earn energy revenues of $52/MWh, capacity revenues of $14/MWh and a ZEC price of $5.70/MWh before the carbon charge. The inclusion of a $40/ton carbon charge would raise energy wholesale prices by $17/MWh at the expense of ZECs but increase nuclear generator net revenues by $9.70/MWh.
