“It is worth noting that Mr. Haque emphasized that states, not PJM, have the responsibility to maintain resource adequacy on their electric systems multiple times during the question and answer period. Unfortunately, many states believe that they can impose whatever carbon-free policies they want, and the regional grid operator will just need to make the system work.”
It feels like people aren’t really internalizing this reliability finger pointing
👏 Isaac on another great piece Also 👏 PJM and PUCO for arranging these sessions and caring enough to try to get ahead of the curve. I saw the emails coming through seeking input requests. You are spot on with the coal retirements. Here in Ohio there is very little pressure coming from the State. It comes ismn the form of EPA regs and lawsuits by NGOs. An example wad the ash pond lawsuits for Gavin coal plant Basically a thinly disguised attempt to mothball the plant. Instead Gavin switched to dry ash handling I will admit to watching the que of plant applications with the Ohio Siting Commission and the virtual lack of anything thermal. It doesn't bode well. PJM can't maintain that critical capacity if no one is going to attempt apply to build any. Isaac do you have any suggestions on how to stimulate generators to build?
I believe California is a good model for what is happening in the rest of the country. They are at about 30% renewables, and have been stuck at that level since about 2018. The interconnection queue is huge, actual connection points are few, extremely expensive, and require long lead times. The grid is full. There is no place to plug in, and fixing it will take billions and decades. I think 30% is the magic number…after that interconnection hits a wall of Jello.
California has also kept gas and nuclear plants online that were scheduled to close. They say this is on an emergency basis. The emergency for the coastal gas plants is four years old with no end in sight. The operators are told every year that they’ll be forced to close, then the emergency is renewed. Why improve or maintain when the government tells you you’ll be shut down? California is will lose those gas plants, emergency or not soon due to deferred maintenance.
It is a slow motion train wreck. Fun to watch if you don’t live there.
I see the Texas energy market itself as one of the sources of failure. I am concerned that Texas’s energy market failure may be a harbinger of energy market driven failures to come in other RTOs.
All the RTOs have some sort of day-ahead or real-time market that dispatches generators in order of increasing marginal costs (MC). Zero MC plants, such as wind and solar, get dispatched first with increasing MC plants being dispatched until the quantity supplied of electricity equals the quantity demanded. The last plant dispatched, the so-called marginal plant, sets the market clearing price that all plants receive. Zero marginal cost plants always get paid. They are usually paid enough to cover all their variable costs and some of their fixed costs. The “marginal plant” only covers its variable costs, and all non-dispatched plants get nothing. This price per kWh model does not distinguish been dispatchable and weather dependent generators. The model drives out plants that don’t run very often. Competitive markets may help drive down prices, but they can drive them down to just above failure. If anything out of the ordinary goes wrong, everything can tip over.
Federal subsidies like the production tax credit (PTC), the investment tax credit (ITC), and the Modified Accelerated Cost Recovery System (MACRS) as well as state renewable portfolio standards, tradeable energy credits, feed-in tariffs, and other subsidies can help increase instability.
All of the RTO/ISOs in the United States have some sort of capacity or resource adequacy mechanism. RTOs like PJM and ISO New England have mandatory capacity markets. I believe MISO requires distribution utilities to acquire extra capacity through bilateral agreements or via a yearly non-mandatory auction. In the case of Texas, which has an energy only market, it leverages higher energy prices driven by leveraging an Operating Reserve Demand Curve (ORDC) to provide resource adequacy.
I think that the way the ORDC basically works is that ERCOT sets a desired level of reserves, and when available reserves start to get near the desired level, a price adder is added to the wholesale price of electricity paid to the generators. That price adder continues to rise until a system wide cap is reached. Prior to winter storm URI, I believe that cap was $9,000 per MWh or $9 per kWh. Electricity prices in Texas typical average around 3.5 cents per kWh so $9 per kWh is breath taking.
In theory the ORDC could have some very modest short-term impacts on available capacity, but its biggest design objective to provide incentives for generators to build additional long-term capacity. If a generator expects to make extremely large amounts of money, albeit infrequently, this should provide incentives for them to build new plants.
The ORDC was supposed to create incentives to build excess capacity. Were constraint events too infrequent or too unpredictable for capital markets to fund enough dispatchable generating plants? Was the shape of the ORDC wrong? Should it have started increasing prices sooner? Was the cap to low? Did generators fear that if prices went too high that that the government will respond politically by stepping in and capping prices? Are electricity markets just too complex to provide the lowest everyday electricity prices, while still providing resource adequacy with the reality of unplanned events and a unique market where supply must exactly equal demand exactly at every minute of every day? Why did it fail?
RTO of 252665MW is prediction of the make up of energy sources of the 13 states in 2050. Is that correct? The block labeled storage is H2 or Batteries? What a mess that would be. How do we get the states to realize that they must coordinate to make any sense?
Thank you, Isaac for a fact-based analysis regarding the societal risks of our current natural-gas-centric approach to electricity generation. California is ground-zero for that experiment which began in earnest more than a decade ago. Independent nonprofit Californians for Green Nuclear Power has been tracking the lucrative (for natural gas suppliers) outcomes of several recent "near misses." https://cgnp.org/sb-846-update/ CGNP notes that the California lost productivity during the 1999-2001 ENRON market manipulations were between $200 - $400 BILLION as a consequence of the tight connection between electricity supply and the production of goods and services. Energy expert Meredith Angwin predicted these outcomes in her 2020 book Shorting the Grid: The Hidden Fragility of Our Electric Grid.
Watched the testimony - nice job!
I keep reading this section over and over again:
“It is worth noting that Mr. Haque emphasized that states, not PJM, have the responsibility to maintain resource adequacy on their electric systems multiple times during the question and answer period. Unfortunately, many states believe that they can impose whatever carbon-free policies they want, and the regional grid operator will just need to make the system work.”
It feels like people aren’t really internalizing this reliability finger pointing
👏 Isaac on another great piece Also 👏 PJM and PUCO for arranging these sessions and caring enough to try to get ahead of the curve. I saw the emails coming through seeking input requests. You are spot on with the coal retirements. Here in Ohio there is very little pressure coming from the State. It comes ismn the form of EPA regs and lawsuits by NGOs. An example wad the ash pond lawsuits for Gavin coal plant Basically a thinly disguised attempt to mothball the plant. Instead Gavin switched to dry ash handling I will admit to watching the que of plant applications with the Ohio Siting Commission and the virtual lack of anything thermal. It doesn't bode well. PJM can't maintain that critical capacity if no one is going to attempt apply to build any. Isaac do you have any suggestions on how to stimulate generators to build?
I believe California is a good model for what is happening in the rest of the country. They are at about 30% renewables, and have been stuck at that level since about 2018. The interconnection queue is huge, actual connection points are few, extremely expensive, and require long lead times. The grid is full. There is no place to plug in, and fixing it will take billions and decades. I think 30% is the magic number…after that interconnection hits a wall of Jello.
California has also kept gas and nuclear plants online that were scheduled to close. They say this is on an emergency basis. The emergency for the coastal gas plants is four years old with no end in sight. The operators are told every year that they’ll be forced to close, then the emergency is renewed. Why improve or maintain when the government tells you you’ll be shut down? California is will lose those gas plants, emergency or not soon due to deferred maintenance.
It is a slow motion train wreck. Fun to watch if you don’t live there.
Two thumbs up, Isaac/Mitch.
The Energy Hierarchy of Needs pyramid is a great visual for Charlaticians. Works well with the First Rule of Holes in particular.
Appreciate the luv
I see the Texas energy market itself as one of the sources of failure. I am concerned that Texas’s energy market failure may be a harbinger of energy market driven failures to come in other RTOs.
All the RTOs have some sort of day-ahead or real-time market that dispatches generators in order of increasing marginal costs (MC). Zero MC plants, such as wind and solar, get dispatched first with increasing MC plants being dispatched until the quantity supplied of electricity equals the quantity demanded. The last plant dispatched, the so-called marginal plant, sets the market clearing price that all plants receive. Zero marginal cost plants always get paid. They are usually paid enough to cover all their variable costs and some of their fixed costs. The “marginal plant” only covers its variable costs, and all non-dispatched plants get nothing. This price per kWh model does not distinguish been dispatchable and weather dependent generators. The model drives out plants that don’t run very often. Competitive markets may help drive down prices, but they can drive them down to just above failure. If anything out of the ordinary goes wrong, everything can tip over.
Federal subsidies like the production tax credit (PTC), the investment tax credit (ITC), and the Modified Accelerated Cost Recovery System (MACRS) as well as state renewable portfolio standards, tradeable energy credits, feed-in tariffs, and other subsidies can help increase instability.
All of the RTO/ISOs in the United States have some sort of capacity or resource adequacy mechanism. RTOs like PJM and ISO New England have mandatory capacity markets. I believe MISO requires distribution utilities to acquire extra capacity through bilateral agreements or via a yearly non-mandatory auction. In the case of Texas, which has an energy only market, it leverages higher energy prices driven by leveraging an Operating Reserve Demand Curve (ORDC) to provide resource adequacy.
I think that the way the ORDC basically works is that ERCOT sets a desired level of reserves, and when available reserves start to get near the desired level, a price adder is added to the wholesale price of electricity paid to the generators. That price adder continues to rise until a system wide cap is reached. Prior to winter storm URI, I believe that cap was $9,000 per MWh or $9 per kWh. Electricity prices in Texas typical average around 3.5 cents per kWh so $9 per kWh is breath taking.
In theory the ORDC could have some very modest short-term impacts on available capacity, but its biggest design objective to provide incentives for generators to build additional long-term capacity. If a generator expects to make extremely large amounts of money, albeit infrequently, this should provide incentives for them to build new plants.
The ORDC was supposed to create incentives to build excess capacity. Were constraint events too infrequent or too unpredictable for capital markets to fund enough dispatchable generating plants? Was the shape of the ORDC wrong? Should it have started increasing prices sooner? Was the cap to low? Did generators fear that if prices went too high that that the government will respond politically by stepping in and capping prices? Are electricity markets just too complex to provide the lowest everyday electricity prices, while still providing resource adequacy with the reality of unplanned events and a unique market where supply must exactly equal demand exactly at every minute of every day? Why did it fail?
RTO of 252665MW is prediction of the make up of energy sources of the 13 states in 2050. Is that correct? The block labeled storage is H2 or Batteries? What a mess that would be. How do we get the states to realize that they must coordinate to make any sense?
Thank you, Isaac for a fact-based analysis regarding the societal risks of our current natural-gas-centric approach to electricity generation. California is ground-zero for that experiment which began in earnest more than a decade ago. Independent nonprofit Californians for Green Nuclear Power has been tracking the lucrative (for natural gas suppliers) outcomes of several recent "near misses." https://cgnp.org/sb-846-update/ CGNP notes that the California lost productivity during the 1999-2001 ENRON market manipulations were between $200 - $400 BILLION as a consequence of the tight connection between electricity supply and the production of goods and services. Energy expert Meredith Angwin predicted these outcomes in her 2020 book Shorting the Grid: The Hidden Fragility of Our Electric Grid.