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Understanding New York ISO’s Carbon Pricing Proposal

Dec 13, 2018 4 MIN. READ
Pricing carbon emissions in the Empire State could fundamentally change the energy market and future carbon pricing.

On December 7, the New York Independent Service Operator (NYISO) released its final draft of a Carbon Pricing Proposal to formally put a price on carbon dioxide emissions in the wholesale power market.

The proposal is the latest step in a process stretching back to April, when NYISO and the NY Department of Public Service released a straw ‘Carbon Pricing Proposal’ to incorporate the full social cost of carbon dioxide emissions. The initial outcomes of the proposal will raise NYISO’s wholesale market prices and change the dynamics of energy asset valuation across the state. Forward NYISO prices show that market participants are factoring a chance that the proposal could be implemented by 2022 into their outlooks. Our white paper, “Carbon Premium: Generator Impacts of New York’s Carbon Pricing Proposal”, discusses the potential immediate impacts on generator revenues in NYISO and attempts to quantify them.

What is the Carbon Pricing Proposal?

The Carbon Pricing Proposal intends to harmonize operation of the wholesale power market with the state’s public policy goals, including a target of 50 percent of electricity generation from renewable sources by 2030. An initial carbon charge of $50/ton (before netting out Regional Greenhouse Gas Initiative allowance prices) has been proposed—a value large enough to have a major impact on NYISO market dynamics.

Key elements of the proposal include an emissions-based carbon charge to be reflected in the energy market bids of all generators, the re-allocation of carbon fees collected from generators to load-serving entities, and charges on external transactions intended to mitigate distortion of energy imports and exports from NYISO. The level of the carbon charge will be based on the social cost of carbon determined by the NY Public Service Commission (PSC), net of carbon allowance prices under the Regional Greenhouse Gas Initiative (RGGI) program of which New York is already a member state. The social cost of carbon is estimated at $50/ton in 2022, escalating to $69/ton by 2030.

What are the potential impacts of the proposal?

This proposal represents a major change to the NYISO market and the largest explicit price on carbon dioxide emissions in any U.S. power market. While New York is a part of the RGGI carbon allowance program, the prices in this scheme have never exceeded $5-6/ton on an annual basis. We estimate an initial impact on wholesale energy prices of $21/MWh, before accounting for any long-term supply changes that might result. This would represent a 50-75 percent increase in NYISO wholesale energy prices.

Exhibit 1: 2022 Average Projected NYISO LBMP

NYISO Carbon charge graph

Under the proposal, the carbon costs paid by generators would be re-allocated to load-serving entities and refunded to retail customers. The IPPTF also expects that higher wholesale prices will reduce the cost of renewable energy credits (RECs) that will need to be issued to meet the state’s renewable procurement goals, and that the cost of zero emissions credits (ZECs) paid to nuclear generators, which are linked to wholesale price levels, will also fall.

While these effects are intended to offset the impact on consumer bills, the proposal would almost certainly result in an increase in total net revenues in the NYISO market, potentially creating opportunities for asset owners and developers. Although we expect that carbon pricing at the levels suggested would not be large enough to guarantee a boom in new development, at the margin it would help tip the scales in favor of new renewables and efficient thermal generators such as CCGTs. Our recently released white paper analyzes the magnitude of the revenue opportunity for renewables and thermal generators.

How likely is the proposal to be adopted?

The proposal will proceed through the NYISO committee process in early 2019. The NYISO has stated that the earliest possible implementation would be in late 2021. Adoption of the proposal is highly uncertain, and it most likely faces an uphill battle. Stakeholder opposition to the proposal is expected, and if filed at FERC, challenges are foreseeable given the far-reaching market and asset impacts of the proposal and likely debate over ratepayer impacts. The complexity of implementing the proposal, including the re-allocation of carbon costs to load-serving entities and the determination of charges at external NYISO interfaces, also poses a significant technical challenge.

However, the market is already beginning to react to the possibility of a carbon charge in the early 2020’s. The graph below shows forward energy prices traded between January 1 and December 6, 2018, for 2022 delivery for NYISO Zone J and neighboring ISOs. Forward prices for 2022 delivery jumped in mid-2018, following the publication of the straw proposal on April 30, and have remained at elevated levels. Notably, the same trend is not observed in forward prices of neighboring ISO-NE and PJM, suggesting that traders began to incorporate a development specific to NYISO—likely to be the potential adoption of the carbon pricing proposal—into their outlook. The increase in forward price of approximately $7/MWh since April, relative to an expected price impact in the $20/MWh range if the proposal is adopted, suggests that market participants view the proposal as possible but far from certain.

NYISO Carbon price graph

Source: EOX forward price data

Implications for the broader electricity sector.

The proposal represents an attempt at addressing a critical issue in today’s restructured electricity markets: the reconciliation of a competitive wholesale market structure with state support for preferred resources. Recent years have a seen a proliferation of state-level subsidy programs and mandates in the electricity sector, including renewable portfolio standards (RPS), procurements of solar, offshore wind and energy storage, and support for nuclear facilities. These actions have led to concern that such “out-of-market” payments will disrupt the role of the restructured market framework in reliably supplying electricity at low cost, and that they represent a path towards re-regulation in which states will increasingly direct market outcomes administratively. Recent proposals to account for sponsored policy resources in capacity market rules of the PJM and ISO-NE markets, among others, reflect this anxiety.

New York’s proposal attempts to address this dilemma by directly incorporating the key attribute targeted by many out-of-market programs—carbon dioxide emissions—into the wholesale market. Unlike most U.S. regional transmission operators (RTO), NYISO encompasses only one state and is thus likely to have an easier path to such an outcome than an RTO covering many states with diverse policy agendas, such as PJM. 

Regardless, a successful carbon pricing mechanism in NYISO could provide an example of compromise between market advocates and state energy goals. Success would ultimately depend on consumer reaction and whether market outcomes under the scheme—for example, if the economics favor efficient gas-fired units—are accepted by the state.