Victor Sauers is CEO of TKO Energy, LLC, based in Austin, Texas. Mr. Sauers is a seasoned executive in high tech, expert in blockchain for energy, emerging technology market value for oil & gas, microgrids, energy storage, renewable energy, manufacturing and energy efficiency industries. He is a strategic business leader for lean manufacturing technologies in areas of semiconductor, large scale facilities, thin film and distribution, and in energy storage operations.

MA: Welcome and thanks for agreeing to this interview, Mr. Sauers. Your recent article on LinkedIn – the Root Cause of Texas’ Power Outages – lays out a set of recommendations for preventing another massive outage event like the one Texas just experienced.

Specifically, your article discusses how ERCOT and the transmission & distribution utilities (TDUs) could have averted the worst of the prolonged blackouts by using smart electric meters to shed load at a much more targeted, granular level than was recently executed. By granular we’re talking about behind the meter at both the residential and the commercial and industrial (C&I) levels. You’re advocating an algorithm-based, statewide meter priority load-shed program. Texas does not currently have such a program, correct?

VS: No, it doesn’t.

MA: Are you describing a form of advanced demand response (DR) program?

VS: Smart meter priority load-shed is a little bit different from traditional demand response. In an emergency context, we take what we’ve learned from existing demand response, load-shed programs and ask, how can we build on those lessons to design a sophisticated emergency warning system for imminent power outages? Such a system would enable different industry segments and governmental entities to speak with each other and with the public, through a seamless communication network during emergency events. And, importantly, targeted load-shed at the meter level would provide the bandwidth necessary to allow TDUs to circumvent the technical constraints they encountered in the recent event, in which they were unable to roll the blackouts.

These two issues – establishing statewide, integrated communications and messaging between industry, government, and the public – and providing TDUs the ability to maintain rolling brownouts – are key to preventing a recurrence of the February 2021 outage event. The proposed statewide meter priority load-shed program would accomplish those two goals.

MA: Currently demand response service agreements exist between distribution utilities and customers to shed load during periods of high demand. Is the idea to expand these types of agreements at the residential and the C&I levels? If so, would those agreements need to be authorized in legislative statute, or by agency rule? Would they be made on an individual basis between the utility with each resident or facility? How would this work?

VS: Well, if you’re talking about various levels of emergency protocols, let’s say levels 1-4. This would be outside of a traditional demand response service agreement. It becomes part of your agreement with the utility, which says, as a resident or business, I agree for you to put a meter in my home, building, or manufacturing site, then the agreement protocols state that I have to abide by the utility policy for load shedding during an emergency event. That emergency policy might say, if there’s a power shortage, and you’re not a hospital, a police station, or a gas platform, then you are part of one of four levels of load shedding of, say, 10 megawatts.

When we go into an emergency situation, utilities need to be able to communicate to the customer – provide awareness to the customer – that if we hit level four, your power will most likely be cut. It’s all about communicating expectations and awareness so that all stakeholders – from suppliers to generators to TDUs to the end user – understand well in advance what’s likely coming. That failed to occur in this recent event.

MA: As you envision this program, during the leadup to likely outages, at that point, residents, business, and facilities who have previously agree to the terms, would be alerted to pending cuts well ahead of time via text, email and/or automated phone call, correct?

VS: Exactly. In Texas we already have a variety of emergency alerts for tornadoes, hurricanes, child abductions, that go on television, radio, phone, text, and social media. We simply add likely power outages to the list of notifications. With that said, gas, electric, and water utilities need a better understanding of how each other works, both the limitations and capabilities.

MA: You mentioned earlier that power industry Emergency Response Plans (ERP) traditionally don’t contain a public alert component. Are you advocating that industry and regulatory agencies build this type of integrated public alert scenario and algorithmic-based functionality into their plans?

VS: That is correct. It should all be much more granular. It all comes down to the way we can handle an unexpected event. That is, what kind of future polar vortex, or 110-degree day, are we going to experience? The answer is, we don’t know.

However, if I had individual meter control for single and three-phase meters, and the right communication channels, we can protect the citizens of Texas by investing in a more granular system. This can provide for much better modelling in real-time, before power is cut of a circuit wire. Let’s plan for the unknown.

Looked at another way, how much unknown can we afford not to plan for? If everyone – industry, regulators, the public – were on the same page with a master plan, from emergency level one to level four, and customers understand that if we hit a level four, you’re going to be shed, then they can prepare. Texas needs to have a higher level of flexibility for unknown events that’s still cost effective relative to the cost of a multi-day state power outage.

MA: Can you address some of the technical and financial considerations involved with implementing a statewide smart meter priority load-shed model?

VS: Single-phase residential smart meters allow a utility to cut power. Shedding load at the single-phase meter level would allow TDUs greater ability to roll the blackouts.

On the other hand, commercial and industrial (C&I) smart meters are generally three-phase meters, which do not provide the utility with on/off system capability. So, what is the most elegant way to manage power at the meter for C&I, and what does it cost? Utilities or the facility can install a recloser, which costs around $20,000. This is significantly more expensive than a residential smart meter, which is about $1500.

MA: Who would foot that recloser bill to allow this level of granular control? The customer or the utility?

VS: In the long term the utility may have grant money, or they put in set of PUC rules they incorporate into the rate cases. What does the PUC, the Railroad Commission, need from the current legislative session for them to be able to do this? Do we need a law that says, at more than X-amount of demand at X- amount of time, that gas and distribution wire utilities need the ability to provide a more granular control? Or, can we do this through a PUC rulemaking session and substitute rules with existing infrastructure?

We’re talking about dollars, right? Is a utility able to do a rate case to incorporate the cost of having control at the meter for commercial and industrial facilities? What is that cost, and what are the pros and cons, that at the end of the day, customers say, hey, that’s a good idea?

By the same token, granular meter-level load-shed takes into account the safety for those Texas residents who are on dialysis, on oxygen, as well as for critical infrastructure like the gas supply chain. So, this provides the utilities the option of taking out two thousand five hundred residential meters in a city, except for the five meters that have people who have a medical need, like oxygen, that needs to run on electricity.

MA: Talk about the algorithm that would underpin this smart meter priority program.

VS: An algorithm is an artificial intelligence-based formula. We’re hearing that ERCOT itself currently uses an algorithm to trigger scarcity pricing. But, in this recent event, that system was sending confusing signals to power producers. There was a bug identified that prevented price signaling to successfully occur. The intensity of the weather event revealed a weakness in our pricing signal software, which raises the question, do we need to be able make pricing decisions outside of protocol? How do we know if the signals are getting through to generators accurately? What’s our alternative way to get signals through?

All emergency events must have at least two communication backups, the last one being manual. That’s exactly what happened in this event, where they actually had to do pricing manually. Therefore, any new algorithm for statewide meter priority load-shed, which I strongly endorse, will have to be designed with greater precision and granularity. The positive side is that Texas has a large amount of this infrastructure already in place, which can be leveraged to execute a much more effective emergency plan that protects both the citizens of Texas and the Texas grid.

The question is, do we want to have a Smart Grid with the granularity to do emergency planning, where we program-in greater ability to manage our assets during critical events? For example, take the pumping of water. Statewide, our water infrastructure represents gigawatts of energy use. We’ve had enough power outages around the United States to realize that when we lose the ability to pump water due to a power outage, we still have pressurized water for four to eight hours. During that time frame you can easily rotate those city-wide water pumping loads zone by zone, where people would have no idea water pumping load was shed because water still flows. That can be accomplished with an algorithm-based program. That’s one example of how to load-shed to a much more granular level.

MA: Please talk about the role Critical Facilities Lists played in the Texas outages.

VS: It’s not difficult to identify critical infrastructure, which includes power to hospitals, police, fire, natural gas processing plants and pipelines, power plants, nuclear power plants, data centers, various leadership hubs. The lists are easy to generate through existing smart meter portals, and must be updated to stay current with new infrastructure for planning and control development.

MA: What role in your view did renewables, specifically wind, play in the outages?

VS: Some utilities had to cut power indiscriminately at the distribution substation, which killed huge swaths of both oil and gas, as well as wind, because wind sometimes shares the same interconnection and loads. So, say a distribution substation is offline. The wind farms don’t have electricity to run their power electronics to get the wind turbines going. Wind producers were rendered unable to shed ice from the blade to get them going again. So, we lost a couple days where we probably could have gotten another couple of gigawatts of wind on the grid.

A lot of people don’t realize that the wind farms need power to be able to begin operations. It’s the wind version of a cold start, they need power from the utility to get going. Once they’re operating, they supply power on their own.

MA: Can you comment on why NERC and PUC recommendations from the 2011 outage event appear to have been largely ignored?

VS: We’re already hearing the same recommendations from the 2021 event that we heard in 2011. Again, it was a primarily a thermal generation event. Here we are again. And so, when you as a utility say, here’s what we want to do, but we want to do it in a rate case, well, there’s a lot of pushback. How much is it going to cost us? Will it cost us a tenth of a penny on your electric utilities bill, or even as much as a penny. There’s so much push back that full recommendations don’t happen and some with good cause. Some recommendations would result in reduction of generation capabilities during peak summertime demand.

After the 2011 event, when we received those NERC and PUC recommendations to winterize and weatherize, some of that happened. That was due to the pushback from not only other interested parties who were saying, in effect, ‘I would see this as a one-time event, let’s do only this, but not all of this, because it’s going to raise my rates, and if you raise my rates, you guys never bring it down.’

So, the answer is no, don’t do anything. However, there was weatherization to the thermal generation fleet after 2011, and Texas had very good results from the 2014 and 2018 cold weather events. In other words, the recommendations that where applied worked.

VS: It’s worth asking, how come, in the recent event, did the citizens of Texas appear to have a better situational awareness than ERCOT? Where was the Texas Railroad Commission?

Well, they can borrow my phone and use my weather app. I say that facetiously, but the thing is, we need to look at the information provided to state leadership, and ensure they have the right information to pull emergency levers to protect citizens and infrastructure from damages.

The other thing leaders are faced with is, if we’re going to be frozen in, would that cause a bigger run on our water and food supply chain? It could and did happen. People fear that they are going to be snowed in for a week and need to be prepared. Well, what does that mean to an average citizen? That means people are going to be stocking up on food and water. So, what messaging needs to be communicated to the public from our leaders and the companies that provide services and food to the public that doesn’t cause a run on resources?

MA: You’re asking, where is the line between alerting and preparing people versus generating panic?

VS: Yes, you have to ask, did ERCOT, the Railroad Commission, PUC and our colleagues in industry have the necessary situational awareness the week before the weather event, which would have been on February 9-11, which would have given them an adequate runway for preparation; how much runway do we need to give our generation and fuel suppliers to be prepared for a 10-gigawatt unscheduled demand?

We have algorithms that say, at 36 hours into zero to seven degrees at 7am, for two hundred and fifty-four counties, ERCOT will have unexpected load that’s normally not predicted on the system. We know there was the chance of having zero to seven-degree morning temperatures for five days straight. If the algorithm model tells me that that’s a possibility, then for how many days do the thermal generators and gas suppliers need to be prepared?

The pushback from the gas suppliers and thermal generators, from an operational cost perspective, says, well, we can do this emergency preparations and we can work 24/7, but who’s going to pay for all this preparation? They could provide the trucks, the manpower, and hedging fuels, all kinds of preparations to a higher degree. But it’s going to cost, or preparations don’t happen. Will Texas regulatory leadership allow gas suppliers and thermal generators to recover the cost of efforts for emergency preparation for a five-day cold snap, which might turn out to have been less severe and of a shorter duration?

MA: It sounds like you’re suggesting some kind of a reserve or capacity fund or charge, that would help pay for these preparations.

VS: By some accounts, this recent event generated a $50 billion additional cost to the rate payer. Building a billion-dollar emergency capability rate case makes sense. Note: Prevention typically costs 50 times less than actual cost of damages. If the state of Texas says, that electric, gas, and water utilities are able to have emergency capability of this magnitude, and when utilities exercise these emergency preparations, a predetermined rate cap (amount and time) will cover the cost when utilities exercise the preparation plan with a rate case. That is the language that needs to be discussed and has to put in to the rules.

Natural Gas

VS: Backing up the bus and looking at root causes of the outages, we have to again ask ourselves, how much and what type of preparations would have mitigated the events of February 14-17, 2021?

The Texas grid starts with a grid frequency of 60 hertz (Hz); it’s perfect. At 59 Hz, I get nervous. We’re getting into the emergency situation at 58 Hz and below. We had minutes before the grid collapsed. At this point, ERCOT and the TDUs, were just cutting power to the wire, regardless of who was behind the meter. However, in doing so were shooting ourselves in the foot, because as we were pulling power from the wire, we were cutting power to natural gas wellheads and up the gas supply chain to fuel Texas power plants.

MA: You’ve mentioned the critical facilities list, and how some of these natural gas processing plants were shed at the wire circuit level. Wasn’t it recommended after the 2011 outage event to update that critical facility list, but it wasn’t done?

VS: Yes, February 5th, 2011. I was at ERCOT watching the control panel. The little dots are flashing off. I ask the operators, are you resetting your system? They replied, no, we’re actually having a power outage at this scale.

So, a week later, we’re all in Austin at ERCOT meeting room with one hundred fifty people in the room and one hundred fifty people on the phone. There’s conversation and we’re talking about backup generators, batteries, etc. The same conversation we’re having today. And the feedback during that open meeting was about the stakeholders and various people representing ratepayers. Everyone cried it was too expensive to implement infrastructure upgrades and weatherization. It was my turn to hit the mic, and my commentary was, ladies and gentlemen, we’ve just had 36 hours of $9,000 per megawatt scarcity pricing in Texas – whatever we decide today, we’ve already paid for it.


VS: We need to design and implement a statewide smart meter priority load-shed program built around coordinated Emergency Operations Plans integrated with a robust statewide government-industry intercommunications network.

Also, we need a longer runway for our gas suppliers and thermal generators to maximize their emergency weatherization and emergency preparations, with financing mechanisms in place that allows them to share, avert, or recover those costs.

We couple those steps with a statewide public media alert system. We communicate with and prepare our citizens and our infrastructure at a much more granular level. It’s just utilizing our entire energy and communication infrastructure in a more elegant way.

MA: You offer a compelling, multipronged approach to averting a similar event in the future. Hopefully industry and regulators will take your thinking into account as we move forward. Thank you for your time, Victor.


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Victor Sauers can be reached at

Mike Albrecht can be reached at