Similar to SB 7, SB 2012 seeks to constrain actions by the Public Utility Commission of Texas (PUCT) and the Electric Reliability Council of Texas (ERCOT) relating to the electric market. Multiple troubling elements were initially included, but ultimately removed from the version approved by the Senate on April 5. In its current state, SB 2012 is primarily focused on defining guardrails for the current PUCT proposal known as the Performance Credit Mechanism (PCM).  

PCM Guardrails

The PCM is designed to incentivize the building and maintenance 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 PCM that remain to be fleshed out, including the specific definition of highest reliability risk. However, PCM credits are most likely to apply during periods of high customer demand combined with low output from renewable generation. The PCM was provisionally approved by the PUCT in January, but has received a fair amount of pushback from the Texas Senate.

SB 2012 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.

Cost cap

A key issue regarding the PCM is cost. An analysis commissioned by the PUC found that it would need to cost $5.7 billion a year to achieve the desired level of grid reliability. However, the same analysis found that a substantial portion of this cost would be offset by cost savings elsewhere in the market, with the result that the net cost would be only $460 million a year. These numbers are open to dispute, and in an apparent attempt to resolve the matter, SB 2012 dictates that the costs of the PCM must not exceed $500 million annually.

While the legislature’s desire to guarantee cost certainty is understandable, this requirement is misguided. Cost savings cannot simply be legislated into existence. Even determining the “net cost” of the PCM over time will be a tricky if not futile exercise. The $460 million annual net cost estimate is a modeled value at market equilibrium. Market equilibrium is an important concept theoretically, but not one often 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 thus any estimate of cost savings will be speculative.

A hard cap is especially ill-advised 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 also does not clarify what will happen if the cost cap is exceeded. Should policymakers wish to proceed with the PCM, they must accept that the net costs in any particular year may exceed $500 million. 

Restricting what counts as “dispatchable”

SB 2012 limits which types of resources are eligible to receive PCM credits. Renewables, energy storage and load resources are all excluded from eligibility. These exclusions work against the stated purpose of the PCM, which is to enhance reliability by rewarding resources who show up when the grid needs them most. If that is the goal, 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. Load resources could end up curtailing prematurely to avoid paying for the credits. Restricting who can get the credits would also raise concerns about market power, as it would encourage further concentration in the generation market.

In addition to the problems that may be caused by limiting PCM eligibility, it is unnecessary.

During the 30 highest net load hours of 2021, the generation mix was 89 percent dispatchable generation versus 11 percent renewable, of which 4 percent was wind and 7 percent solar. If load resources and energy storage were allowed to earn credits, these percentages would likely be lower.

Cost shifting

SB 2012 provides penalties for generators that fail to provide during a reliability event, requiring generators to buy back credits they have sold but for which they did not provide the required capacity. It is not clear what purpose this language serves. Given that credits are earned at time of performance, if a generator sells credits they did not earn, they would already have to buy them. It is also not clear whether administrative penalties are needed, or whether not receiving a benefit would be sufficient. Imposing administrative penalties would probably serve as a deterrent to forward contracting, reducing supply and increasing the price of credits.

SB 2012 also provides that the costs of the PCM credits are to be assigned to dispatchable and non-dispatchable generation facilities as well as to load-serving entities (LSEs). Given that the beneficiaries of electric reliability are not generators, but load, it is questionable why load should not bear these costs. Trying to shift costs onto generators will only complicate the market without providing incentives for either increased supply or reduced demand.

Phased implementation

SB 2012 prohibits the phased implementation of the PCM. Yet phased implementation is a reasonable way to lessen the growing pains often associated with introducing a new market design, and should help with price discovery for a new product. Given the novelty of the PCM concept, prohibiting a phased implementation will only increase the downside risk of the proposal.

A few positives

The bill does provide some positive guidelines for the PCM, such as requiring ERCOT to implement real-time co-optimization (RTC) before the PCM can go into effect and prohibiting self-dealing by generators and affiliated retail electric providers.

The legislation would also create a legislative oversight committee to review implementation and compliance with legislative requirements. This is a sensible idea and a return to the origins of Texas’ electric restructuring. For several years after introduction of competition, there was a joint oversight committee, and it was only disbanded due to lack of activity.  These issues are important and oversight would be better provided from a focused joint committee than from both a House and a Senate committee, each with their own very broad and important scopes.

Cost Allocation

The same cost allocation language is included in both SB 2012 and SB 7 and is described as applying to “providing ancillary services and reliability services.”

The ancillary services market is used by ERCOT to help smooth sudden, short-term fluctuations in supply and demand on the grid. Sudden, temporary changes in supply and demand—such as when a power plant suddenly goes offline or certain types of demand sources are suddenly engaged—can create an imbalance in the grid. To deal with this, ERCOT contracts with generators and other resources that are able to turn on or off quickly when necessary to counteract these shifts. ERCOT currently offers a number of different ancillary services, each of which is defined by how quickly resources are expected to respond after being notified and how long they can generate.

Load has historically been assigned the costs for ancillary services. Under SB 2012, by contrast, ancillary services costs are allocated among dispatchable generators, non-dispatchable generators and load in proportion to their contribution to net load variability. LSEs would be 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 units would be allocated a share of the cost if the unit’s forced outage rate is different than its historical average. Finally, non-dispatchable generators would be allocated costs based on the difference between the mean of lowest quartile generation and the mean generation for each unit. 

SB 2012 does not clearly state which hours will be used to calculate the cost allocation. The most logical way would be to look at all hours. However, given that the PCM is to apply to the 30 hours of highest net load, the PUCT might choose to only look at those hours. Looking at 2021 data, if all hours are used the proposed methodology would shift 40 percent of costs away from load and onto non-dispatchable generation—32 percent would be shifted to wind and 8 percent to solar. Looking at only the top 30 net load hours, the shift is much larger, with the resulting breakdown of costs being 37 percent to load, 40 percent to wind and 23 percent to solar. 

Under either scenario, dispatchable generation would not likely be assigned much, if any, costs because changes in forced outage rates (FOR) are small. That said, 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. In addition, 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.


It is understandable that the Texas Legislature would want to have a say in market redesign efforts underway at the PUCT. However, many of the specific requirements in SB 2012 do not represent an improvement over the PUCT’s existing proposal, and some could seriously undermine the competitive market.