SB 7: Bill Analysis
In the wake of the blackouts associated with Winter Storm Uri, the Texas Legislature has sought to take a more active role in guiding the Texas electric market. SB 7 contains numerous provisions attempting to constrain the operation of the state’s chief electric regulator, the Public Utility Commission of Texas (PUCT), as well as the grid operator, the Electric Reliability Council of Texas (ERCOT). It is appropriate for the Texas Legislature to oversee executive agencies and organizations, and to ensure that their actions are in accord with state policy. At the same time, these agencies were created in recognition of the fact that market dynamics change over time, and that an overly prescriptive approach to market regulation could actually imperil the functioning of the market if circumstances change while statutory text does not.
Ancillary Services Changes
The first set of changes made by SB 7 involve the ancillary services market. Ancillary services are used by ERCOT to help smooth sudden, short-term fluctuations in supply and demand on the grid. When a power plant suddenly goes off line or certain types of demand sources are suddenly engaged, this can create an imbalance in the grid. ERCOT contracts with generators and other resources to be able to turn on or off quickly when necessary to counteract these shifts. Different ancillary services are defined by how quickly resources are expected to respond after being notified and how long they can generate.
Micromanaging the ancillary services market
SB 7 would create a new ancillary service product for which there is no need: a new ancillary service with a two-hour notice and four-hour duration. ERCOT is currently finalizing a new ancillary services product, called the ERCOT Contingency Reserve Service (ECRS), which has a 10-minute notice and two-hour duration. These changes should be implemented this summer, at which point ERCOT would be able to determine whether there is a remaining need for additional services. If there is, ERCOT can make the necessary changes itself without needing specific direction from the legislature.
Legislating a new ancillary service would seem to be overly prescriptive and may limit the ability for ERCOT to adjust to changing system needs quickly. Simply creating the new product would not mean that it would ever be utilized. ERCOT could determine that there is zero need for the product and so never procure resources under it. On the other hand, ERCOT already has the authority to create a similar product without legislation if it concludes it is necessary. ERCOT is tasked with the responsibility to ensure system reliability, and should be allowed to determine the types and quantities of services required.
SB 7 would also require that ERCOT’s use of reliability unit commitment (RUC) be reduced by the amount of this new service. RUC is a process used to ensure that generation resources are available for longer periods. The RUC process can be expensive and is not popular among generators themselves. It is a laudable goal to reduce RUC, but trying to micromanage the operation of the grid in this way is not appropriate and probably not feasible.
Shifting ancillary services costs onto renewable energy
Costs for ancillary services have traditionally been borne by load. SB 7 changes this, allocating ancillary services costs among dispatchable generators, non-dispatchable generators and load in proportion to their contribution to net load variability. Dispatchable generation units pay a share of the cost if the unit’s forced outage rate is different than its historical average. Non-dispatchable generators pay based on the difference between the mean of lowest quartile generation and the mean generation for each unit. Finally, load serving entities (LSEs) are assessed costs based on the mean of highest quartile of metered load during relevant hours of risk and the mean of each entity’s metered load.
Dispatchable generation would not likely be assigned many, if any, costs because changes in forced outage rates (FOR) are typically small. Even so, the words in the bill describe differences in current and historical outage rate, and could be interpreted such that a decrease in historical FOR would increase the allocation of costs. Further, forced outage data for ERCOT generators has historically not been a robust data set, and would likely not be considered good enough for investors to base financial outcomes on.
Looking at data from past years can help provide a rough estimate of how SB 7 would shift costs in the ancillary services market. Based on all hours of 2021, the proposed methodology would shift 40 percent of costs away from load and onto non-dispatchable generation. Of that portion, 32 percent would be shifted to wind and 8 percent to solar. Total ancillary service costs for 2021 were around $500 million, which would mean $200 million in cost shift to renewables.
Over the last two years, a myth has grown up about the Texas electric grid. This myth says that the blackouts associated with Winter Storm Uri were due to the failure of renewable energy, and that the presence of large amounts of renewable capacity in Texas risks a repeat of this event. This is, of course, not true. Generation outages during Uri happened for every fuel type and renewable generators were not particularly affected. Nevertheless, the persistence of this idea has led policymakers to propose a variety of means to punish renewables or otherwise discourage their presence in the Texas electric market, ostensibly with the goal of improving electric reliability. The cost shifting provisions of SB 7 are an example of this.
Over the past year and a half, the PUCT has been developing its own plans for electric market reform. The result of this process has been the PCM, tentatively approved by the PUCT in January. The PCM is designed to incentivize availability of so-called dispatchable generation during peak demand periods by providing an additional payment to dispatchable generators who provide power during times of “highest reliability risk.” There are many details regarding the PCM that need to be fleshed out, including the specific definition of highest reliability risk. Such a definition is likely to include periods of high customer demand combined with low output from renewable generation. Despite the semi-approval by the PUCT, the concept has received a fair amount of pushback from the Texas Senate.
SB 7 attempts to provide guidance to the PUCT on implementing the PCM and to resolve some of the controversies surrounding it. While a few of the requirements in the bill are positive, many are either vague or negative, and some could have serious consequences for the broader electric market.
One matter of dispute regarding the PCM is how much it would cost. An analysis commissioned by the PUCT found that to achieve the desired level of reliability, the PCM would need to cost $5.7 billion a year. However, the same analysis found that implementing the PCM would result in substantial cost savings elsewhere in the market, with the result that the net cost would be only $460 million a year. These numbers have been questioned, and, in an apparent attempt to resolve the matter, SB 7 dictates that the net costs of the PCM must not exceed $500 million annually.
While the desire to provide cost certainty is understandable, this requirement is misguided. The legislature cannot simply legislate cost savings into existence. In fact, even determining the “net cost” of the PCM over time is a tricky if not futile exercise. The $460 million annual cost estimate is a modeled value at market equilibrium, which is a theoretically important concept, but one rarely experienced in reality. Once markets have adjusted to the existence of the PCM, there will be no way to check what prices would have been if it did not exist, and hence no basis for determining its cost savings.
A hard cap is particularly ill-suited given that the net costs of the program are likely to vary from year to year, with higher net costs providing a signal for more generation investment. The bill gives no indication of what happens if the cost cap is exceeded. If policymakers wish to proceed with the PCM, they will have to accept that the net costs in any particular year may exceed $500 million.
Restricting what counts as “dispatchable”
The bill also limits who may receive PCM credits, excluding renewables, energy storage and load resources from eligibility. These exclusions are puzzling. If the goal is to reward resources who show up when the grid needs them most, there is no reason to exclude a wide range of resources that do in fact show up. The exclusion of load resources could also lead to unintended consequences, as load resources could end up curtailing prematurely to avoid paying for the credits. Restricting who can get the credits would also encourage further concentration in the generation market, raising concerns about market power.
During the 30 highest net load hours of 2021, the generation mix was 89 percent dispatchable generation and 11 percent renewable (4 percent wind, 7 percent solar). If PCM credits were allowed to be earned by load resources and energy storage, these percentages would be reduced.
SB 7 provides penalties for generators that fail to provide during a reliability event, including a requirement to buy back credits that the generator has sold but for which the generator did not provide the required capacity. Given that credits are earned at time of performance, it is not clear what purpose this language serves. If a generator sold credits they did not earn, they would absolutely have to buy them. It is also questionable whether administrative penalties are needed, or whether not receiving a benefit would be enough. Imposing administrative penalties would likely serve as a deterrent to forward contracting, reducing supply and increasing the price of credits.
The bill also provides that the costs of the PCM credits are to be assigned to dispatchable and non-dispatchable generation facilities and load serving entities rather than entirely to load serving entities. This too is curious. The beneficiaries of electric reliability are not generators, but load. Trying to foist costs onto generators will only complicate the market without providing incentives for either increased supply or reduced demand.
It is not entirely clear from the current version of the bill which hours will be used to calculate the cost allocation. The PCM is to apply to the 30 hours of highest net load. It would make little sense to apply the same cost allocation methodology for PCM and for ancillary services, which are procured for all hours.
Based on the top 30 net load hours of 2021 the resulting breakdown of costs would be 37 percent to load, 40 percent to wind and 23 percent to solar.
The bill prohibits the phased implementation of the PCM. Phased implementation is a rational and lower impact manner to ease into a new concept and should help with price discovery for a new product. Given the novelty of the PCM concept, ruling out a phased implementation only increases the downside risk of the proposal.
A few positives
The bill does provide some positive guidelines for the PCM, prohibiting self-dealing by generators and affiliated retail electric providers, and requiring ERCOT to implement real-time co-optimization before the PCM can go into effect.
Overall, SB 7 represents an attempt by the Texas Legislature to micromanage the conduct of the PUCT and ERCOT. What’s more, many of the requirements imposed are unlikely to improve the performance or cost efficiency of the Texas electric market. The changes to the ancillary services market could result in hundreds of millions of dollars shifted onto renewable generators and the creation of new ancillary services products without clear need. Similarly, the limitations imposed on the PCM would limit the effectiveness of the proposal and could prove unworkable in practice.