Frequently Asked Questions
Q: How did wind perform during the recent ERCOT winter weather event?
A: Like every other generation resource, the wind power experienced outages during the February 2021 extreme winter weather event (a 1-in-100-year event). Despite significant outages of ≈16,000 MW (out of a 25,000 MW fleet) primarily due to severe icing of turbine blades:
Q: If there are ≈25,000 MW of installed wind capacity in ERCOT, why did only 4500 MW on average show up during the winter storm when we needed it? The critical question is how much wind energy showed up compared to the amount forecast by ERCOT in its seasonal forecast.
Wind energy delivered an average of 4500 MW during the event compared to a forecast of 6142 MW–approximately 73% of the seasonal forecast–despite significant outages due to icing of wind turbine blades. While wind slightly underperformed its forecast, ERCOT has publicly stated that wind was the “least significant factor” in the winter weather event.
Q: But I have heard that wind produced a small percentage of its nameplate capacity?
A: It is essential to understand what nameplate capacity represents. Nameplate capacity for all types of generation–not just renewables–is the maximum sustained output that a power plant is capable of producing. Like having a 350 horsepower engine, it is not anticipated that the output will be at the maximum all or even a significant part of the time. Nameplate capacity is not the appropriate measuring stick for any generation resource, thermal or renewable.
Instead, the critical question is how much generation ERCOT had forecast to show up for a given resource versus how much did show up. This number is calculated using what is known as a power plant’s capacity factor. Capacity factor is a measure of how often a power plant runs for a specific period expressed as a percentage. Capacity factor is calculated by dividing the actual unit electricity output by the maximum possible output. In developing its seasonal forecasts, ERCOT uses seasonal capacity factors to project forecasted capacity.
For winter 2021, ERCOT forecast that wind would provide a peak average seasonal capacity of 6,142 MW and 1,700 MW in an extreme low wind scenario. Wind produced an average of 4500 MW over the course of the winter event.
Q: Is it true that thermal resources must pay a financial penalty or procure replacement power from another generator if they do not generate, but wind and solar do not?
Q: Shouldn’t we reward thermal resources for being dispatchable (i.e., you can turn them up or down)?
A: The ERCOT market already rewards dispatchable resources. The day-ahead and ancillary services markets are voluntary forward markets in ERCOT. While the day-ahead and ancillary services markets are open to all resources, they are dominated by thermal resources. The ability to participate in the day-ahead and ancillary services markets at relatively low risk is one way that the ERCOT market financially rewards dispatchable thermal resources by paying them to be available.
Q: Given that wind and solar are variable resources, shouldn’t we assign costs to them for ancillary services needed to maintain grid reliability?
A: Ancillary services are procured for the benefit of all users of the ERCOT grid. The facts are that despite more than 200% growth in wind energy generation over the last decade and substantial additions of solar, the amount and costs of ancillary services procured by ERCOT have remained stable while the amount of wind and solar on the grid has continued to grow.
Legislation to impose ancillary services costs on renewable resources does not solve any problem with grid reliability or the market. Nor does it solve any issues identified as a result of the recent extreme winter weather event. It is a purely punitive action toward renewable resources.
Q: Does the federal Production Tax Credit (PTC) for wind distort prices in the ERCOT market?
A: No. Remember that the price of power in ERCOT is set by natural gas-fired generation ninety-nine percent of available hours. The ERCOT Independent Market Monitor (IMM) and two national laboratories have found that the PTC has a near-zero impact on average annual wholesale power prices in ERCOT. The IMM found a one-cent per MWh difference in average annual wholesale prices. The national labs’ study found “almost no impact” on day-ahead prices and “little impact” on average real-time prices after removing the influence of the PTC from market pricing data.
Q: But what about negative pricing?
A: Again, it is essential to remember that wind very rarely sets the price in the ERCOT market (less than 1% of the time). Negative pricing has little or no effect on average annual wholesale market prices.
As ERCOT has noted, “low and/or negative offers are not limited to any particular resource, and it is not uncommon for thermal generators to submit negative prices to decrease their chances of being dispatched below their desired or capable levels.”
Negative prices are usually reflections of high output and lots of generation trapped behind a transmission constraint. When this happens, generators will often offer a low or negative price to increase the chances of getting their power out from behind the constraint.
Q: Are renewables primarily responsible for the exit of dispatchable generation in the ERCOT market?
A: No. The primary factor impacting thermal resources in the ERCOT market is the low price of natural gas. Gas sets the price ninety-nine percent of available hours in ERCOT. Of the retiring thermal resources, approximately half (≈4800 MW) were coal-fired generation, with the balance being older, less efficient natural gas plants. Coal is unable to compete economically with historically low natural gas prices. Coal’s falling share of generation has largely been replaced by natural gas. Planned new natural gas additions totaling more than 1900 MW are slated to come online at the end of 2020 and through 2021.
Renewable resources have had some impact on older, less efficient thermal units only to the extent that there is abundant zero fuel-cost generation that helps meet demand at many times of the and is cost-competitive even with the low cost of natural gas.
Q: We have a lot of wind energy installed in Texas, so why do we need to keep giving tax incentives to wind energy projects under Chapter 313?
A: Wind energy is a technology-driven, capital-intensive business. Like other capital-intensive businesses, Texas’ dependence on the property tax makes the tax burden on wind energy investment higher than in many other states. While Texas offers a ten-year partial limitation on appraised value, Kansas offers at ten-year one hundred percent tax abatement for wind energy investment.
Chapter 313 has helped attract $42 billion in wind energy capital investment to Texas while growing the school districts’ local tax base. Most of this investment is in rural areas of the state that otherwise have not attracted significant investment. Not only do wind energy projects pay $258 million annually in state and local taxes, but it also makes $70 million in annual lease payments to Texas farmers, ranchers, and families.