Texas grid regulator eyes big changes for DERs

Texas is a land of contradictions and extremes. Our power grid is no different. It is, simultaneously, both an exemplar of innovation and a complete mess. 

Texas is number one for wind power and is soon to be tops in solar. Texas is also #1 in coal. 

The ERCOT market is wide open. The regulatory and permitting burdens that stop projects in their formative stages in other states, barely exist here. Things get built in Texas and we’re going to need to build a lot more things to transition to a cleaner resource mix. 

But the lack of regulation that helps so much for power plants and transmission projects has a dark side. Lack of even minimal regulation of gas supply and power plants contributed to the longest blackout in modern American history in February, in which at least 246 Texans, and likely more than 700, lost their lives.

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One area where Texas is among the worst is on the demand side. Following February, just about every discussion at the Texas Legislature focused on energy supply. But part of the problem was that energy demand was off the charts; Texans needed 15% more than ERCOT imagined in an extreme weather scenario. Largely because of the colossal failures of February 2021, local sources of power, usually referred to as distributed energy resources (DERs), are now getting a moment in the sun.

On April 20, following a discussion among commissioners at the previous open meeting, Public Utility Commission of Texas Commissioner Will McAdams filed a memo asking for comments on DERs. He noted that Texas is up to nearly 3GW worth of DERs with 740MW added in 2021 alone. PUC Staff added some questions in a subsequent memo in the refurbished docket #51603.

This is a major opportunity for anyone working to bring resilient energy resources onto the distribution system to raise issues and engage with the Commission. Those interested in responding should not be constrained by the questions in the memo, as staff noted the responses “will assist the Commission in identifying all of the relevant issues and scoping further inquiries in this area.”

The PUCT is asking some important questions particularly regarding distribution planning and data accessibility but they leave some key questions unasked. For instance, the Commission appropriately asks who should be involved in distribution planning and what costs will be associated with integrating DERs, but does not ask what costs could be avoided through DERs ($5.47 billion according to a 2019 study). This has been the emphasis in many states: customer investments are adding equivalent amounts to large plants (740MW in 2021!), how can those investments lower overall grid costs?

The Commission wants comments on the consistency of interconnection. This is a long-overdue discussion; DER developers and installers have complained for many years about wildly different standards. One DER provider testified to the Commission that they pay $450,000 to interconnect with one Texas utility and nothing with another. 

DERs can provide grid services like responsive reserve and other ancillary services. The Commission asks: “What market signals should be considered related to DERs aimed at providing grid services?” This is a key question. Stated differently, how and how much should DERs be compensated for the value they bring to the grid? 

One thing not mentioned in the commission’s questions is any suggestion of a “Distribution System Operator.” The notion of a Transmission System Operator (TSO, usually referred to as ISO or RTO) is very common in the US, but a DSO is not—yet. 

The DSO’s function is to coordinate resources on the distribution grid. This isn’t a terribly big deal when there’s only 1-2% of grid power from the distribution grid but with 3GW now, and very likely 4-5GW by the end of this year, Texas will be ~5% and likely climbing far higher, particularly when you start factoring electric vehicles including buses and trucks and F-150s. These, too, are distributed energy resources. Again, the PUCT asked no questions about EVs except for a catch-all at the end: “What other issues should the Commission consider and address while developing rules related to DERs?” They should consider EVs.

At some point, some entity will likely need to be designated the Distribution System Operator. A recognized entity will need to be able to adjust a combination of price signals and/or incentives to ensure that DERs are located where they have the biggest cost and reliability benefits. The same entity will need to ensure that not all home storage and EV batteries are charging simultaneously. If every F-150 Lightning charges at 5:30 on a summer evening, we likely will have problems. Conversely, if even a small percentage of those are available to flow power into the grid if the customer agrees to the price they’d be paid, the grid could be more resilient and affordable. These price signals are critical: if I go to buy an electric car and I know I could be paid for discharging, I may opt for the bigger battery. The Lightning will have a standard 98 kWh and an extended range 131 kWh battery. Could the grid payments offset a significant portion of the added cost of the bigger battery? How much is that capacity worth to the grid operator or the DSO?

There’s lots of work to do to figure all this out.

Veterans of DER work at ERCOT and the PUC will remember years of work in various working groups and task forces on these very issues that led to very little result (see Loads in SCED, Multi-Interval Real Time Market, the Distributed Resource Energy & Ancillaries Market (DREAM) Task Force). The difference between those times and this one is the involvement and focus of a Commissioner. McAdams deserves credit for putting attention on this critical area and clearly signaling his intent to lead. The demand side of the supply-demand equation and distribution grid will only increase in importance with each passing year. Smart charging, cycling of equipment, storage solutions, rooftop, and community PV — all of these and more will be critical solutions.

One last tidbit from the PUC memo that DER developers and advocates should note: the Commission asks us if there should be special “consideration related to DERs associated with critical facilities and entities?”

Texas was dangerously close to a complete grid failure in which six of 13 black start units didn’t work. Critical facilities including nursing homes, hospitals, community evacuation, and cooling/warming centers, fire and police stations, dialysis centers, and more require reliable backup. The state should consider some kind of resilience rate so those critical facilities never again end up in an extended outage. Many elderly Texans lost their lives in nursing homes during Uri. It was unnecessary then and it would be unnecessary and doubly tragic if it ever happened again. But without a policy framework to support deployment, it almost certainly would happen again.

This is a great opportunity for engagement. Commissioner McAdams has opened the door and the other three Commissioners have all voiced support for this project, too. With leadership from the Commission, this time can be different, but the PUCT can only succeed if they hear from a variety of voices. Lots of incumbent interests who would love to slow DERs down will participate regularly and loudly in this process. DER providers, customers, and advocates should, too.