By Michael Kuser
The impact of a carbon price would likely reverberate throughout New York’s wholesale electricity markets, industry experts said Monday.
Carbon pricing could be “a real game-changer in terms of likely impacts on the market,” Couch White attorney Michael Mager said during a June 18 meeting of the state’s Integrating Public Policy Task Force (IPPTF), the group charged with exploring how to price emissions into NYISO’s markets. Mager represents a coalition of large industrial, commercial and institutional energy customers.
During the meeting, NYISO presented its proposed approach to analyzing the effects of a carbon charge on various wholesale market processes, including its Installed Capacity (ICAP) market and related demand curve reset.
NYISO may have to adjust ICAP rules to reflect carbon pricing if it believes the carbon charge is not appropriately reflected in prices, said ISO staffer Nathaniel Gilbraith.
Capacity prices are generally expected to make up for “missing money” from the energy market, and it’s important for capacity rules to capture relevant energy market revenues when setting prices, Gilbraith said.
Issue of Timing
The ISO’s estimation of the energy and ancillary services revenue offset is a key component of its annual process for updating its demand curve. (See FERC OKs NYISO Demand Curve Reset.) But Mager pointed out that if the ISO’s annual update considers only rolling historical revenues and neglects to factor in carbon prices, it will miss the mark.
“One issue is timing. If carbon pricing is implemented, when is it implemented vis a vis the demand curve reset process?” Mager said. “The second is how do you deal with the [energy and ancillary services] revenues in light of a dramatic change like this.”
Power Supply Long Island Director of Wholesale Market Policy David Clarke said, “We would prefer the demand curve to ramp smoothly … consistency would be sensible with what’s assumed in the [locational-based marginal price] and what’s assumed in the bid for demand curve reset purposes.”
Ethan Avallone, NYISO senior market design specialist, explained that the ISO performs economic analyses of new transmission facilities in its Congestion Assessment and Resource Integration Study (CARIS) studies and as needed for its Public Policy Transmission Needs Planning Process. Those analyses include production cost simulations and already account for the Regional Greenhouse Gas Initiative price, and would similarly incorporate the carbon charges on suppliers, he said.
Representing New York City, Couch White attorney Kevin Lang said, “We don’t really build transmission on a CARIS basis or on an economic basis in this state, and I’m not sure when — or if — we ever will. … So in terms of priorities, this is a much lesser issue than grappling with the demand curve.”
“If you’re accounting for RGGI you should be accounting for the carbon price; that just makes sense,” Lang said. “From our view, we’d like to see the transmission response of how we’re going to encourage more transmission to be built, and I don’t know whether that’s economic, or whether it’s public policy, or potentially reliability planning.”
Clarke said there is a potential disconnection between the marginal carbon component price in the LBMP and the actual change in carbon emissions associated with a new transmission line.
“For example, suppose wind is on the margin before and after a transmission line is added, but the line also unbundles some additional wind that can be added into the market,” Clarke said. “There would be a circumstance where you don’t have a price difference associated with that — the marginal unit hasn’t changed — but you have changed the amount of low carbon resources that are able to enter the market. The change in the carbon may not be reflected in the marginal price.”
IPPTF Chair Nicole Bouchez, the ISO’s principal economist, said such deep transmission planning “is probably a bit beyond what we’re doing here,” adding that the group is “just looking at the impact of a carbon price on the market, not evaluating different transmission opportunities and what the consequences of them are in a carbon adder world.”
Timothy Duffy, the ISO’s manager for economic planning, presented three separate planning scenarios. The first case — the reference case — was modeled for three different years (2020, 2025 and 2030), and the remaining two for 2030 only.
The reference scenario presumes 226 MW of offshore wind by 2020, with the state’s full commitment of 2,400 MW calculated into the 2025 and 2030 iterations. All scenarios consider coal plants retired and include western New York and generic AC transmission upgrades.
The scenarios vary on the nuclear component, considering that Indian Point will retire in stages over 2020/21, and that the state’s zero-emission credits supporting nuclear will expire in 2030.
Erin Hogan, representing the Department of State’s Utility Intervention Unit, asked what would happen in 2023 when Indian Point will be retired and the AC upgrade will not yet be completed.
“We didn’t feel that there would be much information gleaned from that particular scenario that wouldn’t be gleaned from running, for example, 2025 with both high and low energy loads,” Duffy said.
The ISO’s broad analysis “captures the bookends of what would be the LMP impacts [and] load-shaving impacts associated with a carbon price,” Duffy said.
“People talk about price signals, and then the reality is that people have choices with price signals,” Hogan said. “If we are going to have a year with exceptional high price signals with the congestion, not having [Indian Point] and not having the AC transmission, we need to know that. That could go beyond what you’re characterizing as the high load scenario.”
Lang questioned the ISO’s professed need to fit the carbon price analysis into “the allotted time frame.”
“There’s no Tariff requirement, there’s no statutory requirement for that, and we’ve had lots of other cases where things have been delayed because the analysis takes longer than expected,” Lang said.
“I’m extremely troubled that we’re looking at something that could have a very significant consumer impact — we don’t know yet because we haven’t seen the analysis — and all I keep hearing from the ISO is ‘we can’t do the broad analysis that folks are asking for because we don’t have the time to do it.’”
Duffy said the situation was a catch-22.
“You’re telling us that you need to know the results of the analysis before you can decide to move forward, but you’re not letting us get the analysis because we’re debating the assumptions we would use in the analysis,” Duffy said. “We’re trying to get to the point where actually we can run the analysis and present the results.”
If at that point there’s a consensus to continue the analysis, “that’s fine, but please let us get to the point where we start presenting results so we can start talking about those as opposed to what-ifs and maybes,” he said.
The task force next meets July 9 at NYISO headquarters.