Nash Whitney, director of sales at Generac Power Solutions, explores how distributed generation and microgrids can provide grid flexibility, as evidenced during Winter Storm Uri in ERCOT.
Efficient markets maximize the utilization of resources and, by consequence, provide the lowest cost or price. For instance, ERCOT provides some of the lowest cost electricity in the country, not just because it’s cheaper to operate in Texas, but because the utilization of assets within the Texas grid is higher, ergo it’s efficient. Less idle resources means cheaper power. The challenge that relatively tight markets such as ERCOT have is difficulty responding to events that are outside of normal operation. The performance and price responsiveness of those markets is a condition of how well operations produce within those boundary conditions. In other words, the further outside of “normal operation” a market gets, the more volatile prices can become.
The largest boundary condition for electric markets is weather. There are others, such as fuel supply and congestion, but weather oftentimes serves as precedent for those conditions. When those boundary conditions are overstepped, the performance of the market becomes volatile. Case in point: Winter Storm Uri in Texas.
Inherent to the supply stack of electric markets are captive backstop mechanisms to ward against shocks such as severe weather, undersupply or over-demand conditions. These built-in backstops help provide pricing relief to the system by enabling spare capacities to participate. At the highest level, reserve margin is the broader capacity target that the grid manages. ERCOT’s reserve margin target is 13.75% (over peak demand). Other specific markets for spare capacities are established, such as ancillary services, so that generators can participate in and be ready to respond to pricing events.
Looking back at previous weather-induced pricing events in Texas, the winter storm of 2011 caused over 150 outages at generating plants and resulted in rolling outages across the state. The winter storm of 2014, which nearly resulted in an EEA Level 3 Alert, and the summer heat waves of 2019 caused the newly instituted price caps of $9,000/MWh to be met. It’s widely understood that it can become exceedingly hot in the summer and bitterly cold in the winter. For instance, it got down to two degrees below zero in Austin in the winter of 1949 and zero degrees in San Antonio in the winter of 1989. However, each of these events were prior to Texas’ historic growth rates for energy demand experienced over the past 15 years.
Regardless, there was ample awareness by ERCOT, grid operators, independent power producers, municipalities and electric cooperatives that the coming weather event would likely have extraordinary impacts on the system; i.e., this winter storm would cause the system to be flexed outside of normal conditions and create price volatility.
Generators had witnessed it in 2011, 2014 and 2019. This means that, by all accounts, assuming historical events from years past, the prices they observed, as well as the coming event’s peak-pricing probabilities, market participants either had prepared or were preparing to ensure their equipment was ready to perform wherever possible, or economical. ERCOT does not require weatherization. Post the 2011 winter storm, ERCOT amended its rules to authorize generator site visits to review compliance with weatherization plans, but the standards that weatherization is held to and the compliance to those standards is the sole responsibility of generation owners. The reality is ERCOT is a tight market. Generation responds to load requirements in a way that delivers optimal value for stakeholders under normal conditions. However, it became clear that those boundary conditions, implied or implicit in the operating models of generating plants across the state, were too narrow.
So, “something” went wrong during this event.
Let’s start with some facts:
- Events of 2011:
- ERCOT’s available resources in 2011: 73,000 MW.
- Experienced historic high winter demand of 59,000 MW.
- 193 generators experienced an outage.
- 4,000 MW of load shed was ordered.
- Lowest frequency: 59.58 Hz.
- Events of 2021:
- ERCOT’s current installed generation capacity is over 107,000 MW.
- Experienced effective winter peak demand of 76,819 MW.
- Over 350 generators experienced an outage.
- 25,000 MW of capacity were forced offline on Feb. 14, including 14,000 MW of wind and solar.
- 50,000 MW of capacity were forced offline during the week (48.6% of total capacity).
- 20,000 MW of load shed was ordered.
- Lowest frequency: 59.30 Hz.
The effects on the system compared to the events of 2011 were considerable. Many of the root causes are still unknown, but the ultimate fact remains clear: Nearly half of the generation in the state was tripped offline during this peak demand event. In any market, capacity markets included, this level of shock would slice through reserve capacities and risk backstops across that system.
Base-load natural gas suffered a disproportionate share of outage capacity. However, the response of non-base-loaded natural gas such as simple cycle gas turbines and distributed generation helped mitigate against deeper power cuts to consumers across the state. If you examine the graph above, natural gas was able to recover about 10,000 MW of capacity across the week, a larger recovery than any other generation fuel type. This response from the natural gas supply likely saved thousands of additional consumers from prolonged outages. This speaks both to the resiliency of intermediate and peak power capacities’ ability to respond, as well as to the supply stream of natural gas fuel that helped deliver this capacity when it was needed the most.
Aside from the obvious weatherization plans that will likely be implemented, the real opportunity lies adjacent to making base-load power more robust and reliable. These base-load plants operate very well within the boundary conditions. Sometimes the marginal cost of increasing their ability to respond outside of those boundary conditions exceeds the marginal benefit of that response. In the wake of an event that resulted in over 72 hours of ~$9,000/MW hour prices, many upgrades are easily justifiable. However, there are contractual obligations that are part of that equation whereas base-load plants are often not able to realize peak pricing.
The real opportunity is for distributed generation and microgrids. This opportunity is quantified in the adjacent chart as the difference between the load that couldn’t be served and the available generation at the time: 1.2 million megawatt-hours of generation. This is a substantial opportunity, assuming this generation could very well have achieved peak wholesale pricing at $9,000/MWh, equating to $11.2 billion in missed revenue opportunity.
There are multiple ways that this opportunity can manifest itself through microgrids and distributed generators. Grid-connected generation provides incremental capacities directly into the broader system. These systems require interconnect processes and permits to be completed, but represent a substantial opportunity for those willing to participate. Alternatively, “behind the meter” generation can provide an opportunity to participate in demand response programs such as ERS.
One thing to consider when exploring this potential further is that the laws of supply and demand will still hold true. There was an extraordinary event that shocked the capability of the electric grid. It produced glaring gaps in capability (supply) against a peak demand condition. Because of changes in these conditions, either through an increase in capacity (supply) or more flexible use of curtailing loads (demand), the consequent prices will undoubtedly be affected. However, it should be clear that there is a substantial shortage in flexible capacities and loads across our system that can yield positive returns on investment or, at the very least, substantially reduce the overall cost of resiliency. And that represents an opportunity.
The key message is that distributed generation and microgrids can provide the most economical flexibility that the grid needs to operate effectively outside of boundary conditions that are established predominantly by base-load and intermediate load generation. This “flex” is imperative for the future reliability and growth of the ERCOT grid.
Nash Whitney is director of sales at Generac Power Solutions and is responsible for leading the Energy Management and Utilities team for Generac, developing new business across the country.