The Public Utility Commission met on September 16 and held a work session to discuss a number of items. Topics discussed where critical natural gas facilities/entities, electric infrastructure reliability, and wholesale electric market design. A video of the meeting and the agenda can be found here.

 

This report is intended to give you an overview and highlight of the discussions on the various topics taken up. It is not a verbatim transcript of the discussions but is based upon what was audible or understandable to the observer and the desire to get details out as quickly as possible with few errors or omissions.

 

Opening Comments

  • Lake – Is about continuity of service and service design; will not take up items 1-3, or 5-19

 

Agenda Items

Agenda Item 20: Project No. 52345 – Critical Natural Gas Facilities and Entities. (Discussion and possible action).

Wei Wang, Executive Director of the RRC

  • After SB 3 from the 87th Regular was signed; agencies have worked aggressively to enact this bill
  • Bill makes it clear the two agencies should collaborate on this matter
  • Lake – Staff has prepared a proposed rule

 

Commission Staff

  • First of a couple of fazes, HB 3648 is the quick action bill for loadshed events
  • Will revisit after statewide mapping exercise; will need to do more comprehensive loadshed review for water and others
  • SB 1876 is about in-stage renal facilities priority during loadshed; we have added this to code
  • HB 3648 is about the critical gas designation process
  • RRC adopted their proposal on Tuesday; last two open meetings to implement this, RRC Nov 10th and PUC is Nov 15th
  • RRC sets the criteria for the exemption for critical facilities
  • Still developing how information to flow to facilities; current proposal says email should go to PUC first and then facilities
  • McAdams – For this process, should have a collaborative meeting with industry and staff
  • Motion passes to propose amendments for publication and public comment

 

Agenda Item 4: Discussion and possible action on electric reliability; electric market development; powerto-choose website; ERCOT oversight; transmission planning, construction, and cost recovery in areas outside of ERCOT; and electric reliability standards and organizations arising under federal law.

  • Lake – Focused on demand response and distributed generation
  • Lake – Today are to establish the existing demand response activities now and what is currently being achieved by price signals and market forces
  • Lake – Need to look at removing barriers to leveraging technology; cannot change building codes and the like, need to focus with is in the PUC’s scope

Kenan Ă–gelman, ERCOT

  • Load Resource Program and Emergency Response Service are administered by ERCOT
  • Load Management Programs, Peak Load Reduction, Price-Responsive Pricing, and Transmission related programs are not administered by ERCOT
  • Overviews the Load Resource Program; is about ancillary services, expects capacity to grow as data centers are moving into the ERCOT perspective like Bitcoin
  • Lake – Controlling load is automated? Time constraint?
    • Is time constrained at 5 minutes; can adjust reaction automatically or systematically
  • McAdams – What are those trigger points?
    • Depends on service they bid-in on; main area is responsive reserve service
    • Non-spent is deployed early in the process
    • Working to change NPR reserve deployments at 500-MW response
    • Underfrequency replays are automatic triggers, not ERCOT
  • Have 7,000 MWs of capacity registered, but see a lower amount offered around 3,100 MWs
  • A limit to how much is allocated to load, is prorated amongst certain resources
  • Available capacity is around 1,720 MWs
  • Lake – Could “dim” one feature to keep other mechanisms working?
    • Would want to ask industry that; could “dim” one feature
  • Lake – Constraint how much is accepted under ancillary services?
    • Yes, minimum procured from dispatchable resources; no more than 60% limit coming from load resources
    • Looking at potentially changing that 60%, but a lot to consider stakeholder input
  • Overviews four Emergency Response Service types; have three four month contracts, have the right to call off before we call their deployment
  • Lake – What do you mean by that?
    • They curtail or stop consuming electricity; some small-scale generators can turn on their backup generation
  • Lake – Participants are required to reduce consumption of power at the second emergency level? Before that, ERCOT cannot force them to reduce?
    • How it is currently set up
  • Cobos – Explain how the decision to do this at the second emergency level? Seems like there is a flexibility to order earlier
  • Lake – Could deploy a notice before then?
    • Has never been done before, rule does not say that we can
    • As currently contracted, would have to point to an emergency decay
  • Cobos – If you were able to deploy at emergency level 1, seems like you would not get to the second level
  • Glotfelty – Where is your $50 million spending limit coming from?
    • Is in the substantive rule; procure across the full day
    • Was deemed a good amount because the market would not be liquid enough and seemed like a good amount of seed money
  • McAdams – Stakeholders point out $50 million is not enough; how does this work?
    • Is value to increasing the $50 million if you can get more MWs; but currently is symmetrical to ancillary services
    • Argument is there is more out there we could be procuring rather than more payments
  • McAdams – 1,000 MWs, 300 is provided by BG; how is apportionment settled?
    • Do not distinguish between the two, is about the timing/qualifying time period of the bid
  • Weather Sensitive types are only procured during the winter and summer peaks
  • McAdams – HVAC stakeholders qualify latest invertor technology on those thermostat systems, is in the process?
    • Is not, systems are aggregated, offered in, tested, and then in the program
    • Lake – Aggregator would have incentive to get there at the lowest cost
    • Lake – Today, ERCOT is spending millions on smart/responsive air conditioning systems in the summer season
  • Glotfelty – Are consistent?
    • Is a band in which they are allowed to perform; capability varies due to the weather
    • Would caution bidding in certain air conditioning programs because there is not as much need in the winter
  • Cobos – ERS report on how they performed during the winter storm?
    • Generation performance was not as well as expected; may want to spend more time on performance requirements
    • Fuel was an issue as well
  • McAdams – To consider backup storage ancillary service; could change ERS participation?
    • ERS is not ancillary; if qualified for backup fuel, would apply
    • Depends on how that is moved forward; would just be of interest
  • Mark Patterson, ERCOT – Were rotating outages on the distribution system; contributed to a lot of those outages, why the loads seemed like they under performed
    • Qualifications – Can have load to curtail or backup generation, do not have to be ERS
  • Cobos – Point is, smaller number of those who participate?
    • Patterson – 300 MWs out of 1,000 MWs
  • Cobos – Asking because we are looking to improve ERS; some stakeholders have said generation resources should not be a part of ERS
    • Should caveat that with how the winter may look different than the summer
    • Is an important policy consideration
  • Cobos – What else stood out?
    • Patterson – Have two contracts in this program; ERS 30 can be deployed in EEA 1, ERS 10 can be deployed in EEA 2
  • McAdams – How long from EEA 1 to EEA 3? Need to be out front before or else the energy is not there
    • Uri was a fast-moving event
    • Discusses the 2011 storm; ERS was helpful that time
  • Cobos – Seems like many times it is not dispatched at EEA 2?
    • Lead time does matter; many times 30 minutes is too long to wait until EEA 2
    • Issue has been debated, Commission chose to allow those to go away when they felt comfortable
  • Lake – Direction from the Governor is to use these tools before the emergency;
    Commissioners aim to build a bigger margin of safety when these resources are deployed

    • Is a cost to curtailing
  • Cobos – Why is it more expensive?
    • Will be deployed more frequently if it is a watch or reserve
    • Lake – Preferred business model is to get the $50 million without being deployed
  • Cobos – Want to give ERCOT flexibility, but should use tools more quickly; speak on aggregation for CNI customers/residential loadshed? Any pilot programs?
    • More interested in aggregation in the load resource participating in ancillary services in storage and load
    • Open to pilots, but not sure how much value is there
  • Cobos – You are saying there are no opportunities for other resources to participate?
    • There are; potential for aggregated storage on the small scale
    • Would not preclude anything as long as it is behind the meter
  • McAdams and Lake ask how to get more participants in the aggregate market
    • Would be difficult to participate to aggregate in an ancillary services context
    • ERCOT needs to be nimble to address the generation available
    • Want to remove the moratorium around DGRs
  • Cobos – How does ERCOT plan to manage resources on the distribution system during an emergency?
    • Would need to be more granular during a loadshed; would be expensive and difficult
    • Cobos – Heard from Oncor about that
  • TDSPS have load management programs (Oncor, CenterPoint, AEP and TNMP)
  • Is a new price adjustment for their deployment in ERCOT’s system
  • Overviews load reduction and peak; do not have 2021 data; will have an updated December report
  • McAdams – As the peaks change; commission could consider a more disparate CP, like a 12 CP approach?
    • Could have to curtail at the peak every month in that case
    • ERCOT is interested in the net load peak in terms of management; load adjusted for intermittent resources
    • Is not a cost causation between net load peak and coincident peak
  • Lake – Reliability speaking, the most challenging time is when the sun goes down, not when the most power is being consumed?
    • Correct, also when the wind is low
  • Cobos – What about winter?
    • Renewable performance is different during the winter; net load peak is of interest in the summer
  • Amount of growth in settlement only distributed generation continues to grow
  • Are implementing rules not necessarily related to FERC orders
  • Would like to move price responsiveness to the locational marginal price rather than the zonal average price
    • Provides an example of hindering curtailment in RGV because of zonal average price
  • McAdams – Is not in the substantive rule?
    • Substantive rule talks about all resources getting an LMP
    • Can change rules to reflect that; propose all load potentially be settled at the LMP

 

Lark Lee, Tetra Tech

  • Oversee IOU utility programs; programs were designed in Texas to address peak demand growth
  • Some companies have a higher floor such as CenterPoint
  • Summer peak is defined clearly and is Monday-Friday and not including holidays
  • Winter peak does not address shoulder seasons
  • 2020, IOU programs delivered 537 MWs in peak demand reductions; do not have 2021 data
  • Seen participation go up in the IOU commercial management programs
  • Oncor has the largest IOU residential management program
    • Significant interest for utilities to participate, but is a limit on how many can participate
  • McAdams – Why limits?
    • Set an energy savings goal and everything cannot come from demand response
    • Is an ongoing discussion; utilities are never sure how much should come from demand response
  • McAdams – Tell them they have to do it and set a floor; they play the odds in what a rate case will come back with?
    • Yes, is a floor; rate cases are outside of my expertise
  • McAdams – Are ensuring there is quality in these systems; how are HVAC inverter-based systems accounted for?
    • Programs currently address summer peak; were not called upon during winter peak
    • Current rule could allow for a winter peak program
    • Have a centralized document that sets baselines for utilities; have confidence in calculations
  • McAdams – Are mechanisms to enhance values for latest available technology?
    • Is infrastructure to expand these programs
  • Lake – Opportunities to expand and opportunities to improve value
  • Glotfelty – If demand response is right, should transmission focus on energy efficiency?
    • Is a long-debated topic

 

Bill Grant, Xcel Energy

  • Have seen the energy market from many angles
  • SPP is a fully-bundled utility outside of the ERCOT system; are mostly tariff driven
  • Pricing of demand response is mostly due to capacity decisions
  • Companies have their own sustainability goals; not necessarily participating in the market, are offsetting retail rates or tariff charges
  • Demand response, can limit air conditioning even during not peak times
  • Lake – Customers auto-enrolled?
    • Have to opt-in; ask for three-year commitments when opting into these programs
  • In the Southwest Power market; load can use third-party aggregators to participate in the market
  • Programs are not sizable yet, but are growing
  • Communication with the host utility serving load is critical for us to manage load pricing
  • Are in the middle of compliance-filing; yet to be determined how many are participating in the market
  • Hopes Commission looks into the rules where we can manage load without being subsidized by other customers
  • McAdams – Qualify distributed resources for a capacity bid? Use aggregated DR for that?
    • If a distributive resource we can interrupt; would reduce load requirement to meet the 12% capacity requirement
  • McAdams – New federal policy goals concerning renewables for 2035, what pressure will you have to harness that energy?
    • Accreditation process is changing for renewables to consider the saturation of resources
    • Have decoupled some of our larger entities; using a number of tools to transition into a different type of resource
    • Are struggling with companies reaching their different goals across states
  • Cobos – Added a significant among of wind?
    • Have close to 3,000 MWs of wind of the system
  • Cobos – What pressures are you feeling?
    • RTOs who have no jurisdiction over distribution companies
    • Potential for a lot of costs
    • Industry needs to do a better job at incorporating available renewables
    • Could put ourselves in an unknown operating system with limitations
    • Lake – Found ourselves in a similar place during the winter storm
  • McAdams – Technology is telemetrically controlled?
    • Has to be controlled and interruptible; SPP has hard requirements
    • McAdams – Valued differently?
    • Yes

 

Cyrus Reed, Lonestar Chapter of the Sierra Club

  • Demand side focus is one good first step
  • Requests members of the public are included in these discussions
  • PUC has many tools at its disposal; in all categories, are things to be done to increase them
    • Residential DR is limited and summer only
    • Low energy efficiency requirements; can be incentives in those programs
    • ERS is limited, can increase substantially
    • More can be done in ancillary services
    • More can be done in the market itself
  • Energy efficiency and load management incentives can be expanded due to rule language
  • No state has more economic potential for electricity savings than Texas
  • Are ranked last in overall savings goal; could adopt a new goal
  • Some NOIEs are required to report to CICO or ERCOT, do not see a lot of participation
  • McAdams – What is the policy to require some report and not others?
    • Law passed by the legislature; have to report NOIEs 500,000 kilowatt hours
  • PUC does not have authority concerning building codes, but the state could do more there
  • Could aim to reduce the energy demand overall
  • SB 1125 and SB 2011; PUC has expanded and changed goals
  • Are some requirements on low income and hard-to-reach programs
    • Means TDUs have to balance
  • 20% load factor is something that could be adjusted to get more savings
  • Charging rate payers about $1 a month, argument is we could go higher than that
  • Smart Meter Texas; ratepayers have not gotten all of the value from them
  • Could double the $50 million and the impact would not be great
    • A lot more can be done with aggregation
  • Could either look at additional ancillary services or setting a goal for load serving entities for Residential DR and allow it to be tradeable
  • Unregistered DG and Distribution Generation Resources; are ways to grow these
  • Lake – Market redesign, still need to be spending $50-$100 million on ERS?
    • Favor of making TDUs more focused on energy efficiency
    • Not against load management programs during the transition
  • Glotfelty – Working weatherization programs with EE programs?
    • State does a poor job; within the confines of what TDUs are required to do
  • Cobos – Thoughts on moving funds from TDU energy efficiency program to Residential DR focused programs?
    • Lark – Not sure where those funds would be diverted from; working harder on low-income
    • Reid – More can be done on Residential DR with a focus on the winter; investing in heat pumps or new technology to reduce load

 

Derrick Mosley, Reliant Energy

  • Overviews products offered to customers
    • Thermostat Device DR; customers have the option to override the system
    • Behavioral Dr; not eligible for TDU or ERS
  • Long DR events eventually lose participants; works well for a limited period of time
  • High price lasting for a long time is not an incentive to use DR
  • McAdams – Where is the most effect in price responsiveness?
    • Starts tailing off 2 hours into the event; steep decline after 4 hours
  • Lake – Current market shows effective pricing mechanisms in DR?
    • Yes
  • Amount of Residential DR is not enough that it has made a large difference in where price goes
    • Could down the road
  • Cobos – As we look at market redesign such as letting it lag, feelings on that?
    • If prices stay high, it is not a useful market signal
  • Lake – DR competes with other resources, correct?
    • Yes, generation resources that can run longer would want to catch the front end of the high-price window
  • Lake – Is about bringing on more resources on sooner than using reserve margins
    • Cobos – Concern would be this is limited-time, what about emergency situations
    • If there was an eight-hour event, it would make sense to catch the end of the event
  • McAdams – Residential DR makes more money in those events that happen more often?
    • Price signals were unpredictable during the storm
    • Strength in the competitive market in terms of innovation
  • Could help expand DR:
    • Making participation simple and have resources for questions/concerns
    • RAPs were not involved with DR during the weather event
    • Incentives to help reduce the customer’s cost of smart thermostats; could be with Energy Efficiency dollars
    • Reduce administrative hurdles such as the inflexibility to adding new customers during the DR season
  • Lake – Incentive to the DR program to provide the next MW through demand rather than the real time market?
    • Is one of them, other is if we participate in ERS/TDU can get a dollar benefit for participating
  • Lake – Customers can override at anytime; how can you provide reliable demand response?
    • Can gain experience through aggregation of customer behavior; see significant reduction in KW in the summertime
    • Lake – Average is a dangerous game
  • Cobos – Support aggregation to participate in ERS; rely on historical numbers for aggregation?
    • Similar to how we buy supply; will bid into ERS at the minimum level
  • Lake – Anything on the PUC side from preventing company from expanding the program?
    • Do not think so, incentives could make it go faster
  • McAdams – Do not think the $50 million ERS is an issue?
    • Is a hard cap; if is expended would like to see some allocated to Residential DR
  • Lake – May be a business benefit to pass by the $50 million
  • McAdams – How do ancillary services factor into your demand response?
    • Some ancillary service concepts would require telemetry at the individual customer level; not viable
    • Agree with Ă–gelman that ERS is the best vehicle right now
  • McAdams – If the system was operated with a more conservative approach and DR was included as an offset measure would be an incentive for DR?
    • Yes

 

Liz Jones, Oncor

  • Overviews the Oncor Residential Response Demand program
  • Cobos, you were concerned about distributed resources for feeders
    • Have struggled with this for over a decade at ERCOT
    • Can manage shallow loadshed events, but cannot do that in every short-supply event
    • Urge to not immediately excluded distributed generation; would also decline benefits offered when firm load shed is not occurring
  • Weatherization presents a benefit to the customer, but is expensive relative to the KW or KWH are saved
  • Demand response is relatively low cost; not involved in buying appliances
  • Provide RDR through energy efficient programs; TDUs are not allowed to provide energy efficient dollars directly to customers
  • Should consider a winter program for peak events and year-round events
  • TDUs implement loadshed in EEA 2 conditions; should look into this
  • Average pricing on residential plans diminishes price sensitivity
  • Lake – Aim to limit individual customers to variable rates; how would you suggest we address that?
    • Have market to pay for customers to pay to change their behavior
  • Lake – Demand response
    • Conservation is an unpaid demand response
  • Lake – Unpaid to who? Is a big value-driver
    • Unpaid to the retail customer; customers are generally uncomfortable with having outside controls in their homes
  • Potential areas of refinements limitation to summer peak periods and system-wide RDR
  • Need to discussed a tiered approach on expectations for a 2 hour turnaround versus peak usage times
  • Not interested in being a market participant, but willing to help if needed
  • PUC must determine RDR size and scope in the wholesale market
  • RDR should not be relied on for emergency events without guaranteed performance and penalties for non-performance
  • McAdams – Is not counted in your load shed numbers?
    • No TDU had a program in February, have in summer only
    • Lake – Aggregate would not apply in those cases
  • Need to ensure RDR program participants do not “double-dip” for the same capacity in multiple programs
  • Cobos – Would want to extend benefits through Residential DR in the winter?
    • Have existing authority to modify it; winter program would be different than summer usage
  • Cobos – Would be helpful to move from EEA 2 to EEA 1?
    • Would be more commercial tolerance for that than residential
    • Not opposed to taking a step back from the scarcity market, but need a price signal
  • Cobos – Tiered TDU load management programs allowed in SB 3, what you are talking about?
    • Area of concern for TDUs; unsure if it is under energy efficiency
    • Not sure where to start; have not designed commercial load management programs
  • McAdams – Cannot advance to EEA 1 in this case, has to be EEA 2
  • Lake – How many MWs between EEA 1, EEA 2, and EEA 3?
    • Ă–gelman – EEA 1 to EEA 2 is frequency-based and reserve reference based
    • Ă–gelman – Watches start at 3,200, EEA 2 is 2,300-1,750, and there is no trigger based on reserves for EEA 3
  • Lake – New direction from legislation is to not get close
    • Those numbers are not mandated outside of ERCOT, is under PUC and ERCOT discretion
    • McAdams – EEA thresholds are ISO set

 

Rick Luna, CPS Energy

  • Overviews demand-response programs
  • Have met energy reliance goals a year early; $70 million dollars a year in programs
  • Offer behavioral programs, smart thermostats, and commercial/industrial programs
  • DR is a valuable tool for grid reliability and protects from prices in a peak market
  • DR performance is consistent and reliable within a certain bandwidth
  • Have run up to 10 days of events, vast majority of customers will not drop off the program; have a $30 incentive
  • Overviews summer 2020 DR data
  • During the winter storm 93% of thermostats enrolled were able to reduce load by 2 degrees in each household

 

Corey Amthor, Enchanted Rock

  • Provide resiliency through micro-grids through natural gas; grocery stores, hospitals, senior living facilities
  • Have a dual purpose microgrid to provide either backup to the customer or the grid
  • Overviews performance during the winter storm; 143 sites protected, 70-140 MW of grid supply
  • Glotfelty – The generation you provided during the hurricane?
    • Provided sites with 99.7% reliability when the grid was unable to provide it itself
  • Distributed resources provide aggregate reliability; removal of upcoming moratorium would be helpful in expanding
  • Need to allow DGR/DESR participation even if connected to curtailable circuit
  • Current requirements do not align with system-level ancillary services
  • Allow aggregation of resources to participate as a single DGR/DESR; include portfolio-level current operating plans
  • McAdams – You are an ancillary services, and you are asking to be on aggregator?
    • Number of sites across the state are already a significant level
    • Would never bid entire service
    • Want to prevent what happened last Feb; don’t want to take chance of not using assets available
  • Cobos – Microgrid systems can provide day-to-day reliability; diversity of microgrids ends up preventing blackouts?
    • So much geographical diversification that you don’t have to worry about outages
  • Cobos – In event of rolling blackout, would be relying on other tools to bring system back; but in respect to microgrids, could provide benefits but maybe not depending on size?
    • Same case with hurricanes knocking out transmission grids; reliability of diverse system just as good as generators that we already have operating
  • Amthor – 99.4% and 100% availability for ERS with past two weather events; extreme weather events impacted ability to provide services
  • Budget cap for ERS should be raised; 30% increase in peak load since initial establishment of budget
  • Need to examine how current ERS is dispatched; any time your response time is close to 0, should be considered most valuable and important
  • Differentiate compensation for higher value 10-minute resources
  • With any reforms, prioritize equal market access for distributed resources
  • Transparency and consistency in interconnection requirements will facilitate more efficient development of distributed resources; for example, metering improvements
  • Consider cost-sharing policies for upgrades that benefit utility customers and subsequent interconnections; for example, transfer trips
  • McAdams – What is the inconsistency in interconnection requirements?
    • Once you go into transfer trip, can increase time by 10 months
  • Cobos – Seems interconnection standards is where you could use help from us?
    • Yes
  • Cobos – One thing that SB 3 includes in it is that ERCOT has to require generator owners to register with them; as we look to distribute generation into a variety of programs and use facilities for reliability, will also help
  • Lake – Run natural gas generators? How do you ensure fuel supply?
    • Always buy firm no-notice natural gas, pay large premium in price to get gas
    • Operating pressure can run down to 5psig; doesn’t affect us, but pay higher price to make sure they’re available for customers
  • Lake – Any specific contracts?
    • Not on interstate pipelines, buying service from other companies
  • Cobos – With respect to lessons learned, some natural gas facilities that froze during Feb. storm?
    • Took notes during entire week, had certain brakers that might have frozen up, adding heaters and changing heater settings; nothing with freezing up though

 

Amy Hart, Sunrun

  • Largest solar storage provider in country; focus on residential sector; 4.2 gigawatts of networked solar capacity
  • Had solar and battery backup systems that were able to power through power outages during Feb. winter storm
  • During storm Nicholas, 1/3 of customers in Houston area had power outages but were able to have backup power due to solar backup systems
  • How can we leverage home battery system to create a resilient grid
  • Demand response can play an important role; aggregated DERs are a critical resource to increase stability for grid and TX families; DERs as Demand Response
  • Partnerships with Ford and South Carolina; looking at different technologies and what other companies have done
  • Seamless switches to battery backups during power outages; no instances in which backup battery ran out of power; systems designed for need and their financial situation
  • Aggregate load reduction, can use Demand Response to aggregate systems
  • McAdams – So what does that look like?
    • A meter of some sort; aggregating these systems makes it powerful but can still see lower levels
  • Hart – Think about rules allowing third party to aggregate; set up market rules that would allow 3rd party aggregators to make sure systems show up
  • Enhancing compensation; two main barriers is economic signal and technology; providing right signal that you want more resources
  • Have bid into New England capacity market; 4 hour peak in summer, 2 hour peak in winter
  • In California, it’s day ahead peak programs you can sign up for
  • McAdams – Get bid for capacity payment and cloud coverage comes, how does penalty work?
    • Penalty is significant; risk on Sunrun; under promise and overdeliver; never want to be short and pay penalty; payment gets passed on to customer whether or not they need them in aggregate
    • At customer level, it is seamless; get reduction in battery price because participating in capacity market
  • Lake – What if power goes out and you’re drawing from customer’s battery?
    • Will not be called on if power is out; always reserve 20-50% of battery for backup use
    • Part of conversation in contract; what are customer’s expectations; there is an understanding; why you have so many homes participating in program
    • Always have generation coming into battery; you design system so you know you have generation coming
  • Hart – Ensure technology can respond; day ahead signals today
  • Expanding Demand Response should be a part of overall market design strategy to fully utilize benefits of customer-sited DERs
  • Cobos – Haven’t seen a lot of proliferation of solar and storage in ERCOT; Sunrun has a lot of customers; is it because panels and storage centers are smaller, so it’s more economic?
    • As opposed to utility use of solar, for residential use, there’s a lot of built environment, like roofs, to take advantage of
    • Homes need ability to control and manage electricity bill
    • Have found a more interested market because customers are engaged in electricity choices; peace of mind of backup power front and center in most of conversations
  • Cobos – Since Feb. winter storm, have you seen demand increase?
    • Yes, considerably; 50-75% of systems now have storage attached; was 15-20% before

 

Michael Lee, Octopus Energy

  • 5 million individual meter customers; offer good customer experience and low prices
  • Have a software platform that enables them to have 50% less cost than competitors; helping to integrate it into vehicles, thermostats, etc.
  • Focus on how to link prices to devices; it’s about moving load when they see excess supply on grid, not utilizing load when you need it the most
  • The Big Switch has incentivized customers; have been able to move 75 MW hours with no investment or cost, just showing customers when it is most cost-effective to use energy
  • Actively able to move load without a single cost to company, customers, or grid; saves everyone money
  • Monitor time of use rates to incentivize users to use energy at certain times; customers complement grid as it goes through different changes
  • Economic self-interest; as retailer, lots of incentive to do it right; prices ensure reliability; if penalty for nonperformance, then extra financial incentive to perform; sort groups by zip-code
  • ERCOT is perfect market for Demand Response; retailers settle on actual loads, not generic load profiles; energy-only creates direct value; electricity is the largest utility expense for residential households; controllable loads make up large % of overall cost exposure
  • Cultural limitations include: current business models focus on customer “forgetting” so that variable rates can be charged (trust is broken); feedback loops need to be short (need to see immediate reward); customer’s are “powerless” (invisible product)
  • Technology limitations: limited to 2 calls per meter per hour (need more); limited to 24 calls per meter per day (not immediately a barrier but can become one if multiple per day); limited to 3,000 calls to TDU; usability and API support can use improvement
  • Recommendation: increase limits, improve/modernize usability, consolidate at ERCOT
  • Opportunities for DERs: thermostats, EVs, residential storage; all are used for economic self-interest demand response, could be used for aggregation but no great ERCOT platform yet
  • Walled Gardens create risk that customer value is captured/reduced, leading to lower adoption rates; inoperability essential to promoting competition
  • Solar and storage assets and grid; current process creates customer friction; multi-party problem, no advance notice to retailers about upcoming interconnection; load profile update in ERCOT/TDU unnecessarily slow and creates large frustration with customer
  • Role of retailer is prime role to do demand response
  • Ways to create a great customer experience
  • Excited about deploying heat pumps for winter; lots of opportunity to maximize value of grid

 

Erin Burns, Google Energy Partnerships Team, Nest Thermostats

  • A lot of potential for Demand Response in Texas
  • Of the smart thermostats in Texas, sub 10% in DR; Texas should be the super bowl of DR
  • Not a lot of residential use of smart thermostats
  • Rush Hour Rewards; reliable, effective, and dispatchable smart thermostats; maximize load reductions while optimizing customer satisfaction, custom algorithms for each home, and customers are always in control
  • Smart thermostats drive energy efficiency and DR
  • Customers participate in load reduction programs due to incentives and feeling of control
  • Every program is opt-in; value is there, market for smart thermostat is still relatively low
  • During weather event, smart thermostat displays information; very high customer satisfaction with program
  • Programs allow them to feel in control of climate change, help out their community, receive incentives; customers aren’t fatigued as long as it’s simple and they get rewards
  • McAdams – Short duration that is key?
    • Yes, as long as they aren’t hot for long, customers don’t care
  • Lake – Averages are reliable?
    • Yes
  • Recommendations for the Commission:
    • Should increase budgets for TDU DR programs and the ERCOT ERS
    • Should set DR goal to enhance reliability
    • Should conduct a demand response potential study and explore the creation of additional reliability ancillary services for DR

 

Alison Silverstein, Independent Consultant

  • Takeaway should be that DR and energy efficient services provide many benefits
    • DR and demand flexibility can be used in many different ways
  • DR and energy efficiency response complement each other; a lot of wasted energy in TX, could be energy efficient and maintain DR
  • At least 15% of industrial load in ERCOT is movable
  • Can get well over 10,000 MWs of winter peak load reduction and another 10 gigs of summer peak load reduction
    • Only from residential customers; report will be out next month
  • Capabilities of DR have changed so massively, views of how to use it should be equally expansive
  • Most of barriers to DR are outdated concerns; most have been built into PUC or ERCOT rules
    • Fear of barriers has frozen ability to change; ignored fact that competition between consumers and suppliers is important
  • Supply becoming unreliable and risky; how to use proven customer capabilities and their willingness to move around loads
  • Math of how to do resource adequacy is difficult
  • If you redesign market correctly, still can fund TDU/DR studies; helps diversity, makes sure new forms are working, etc.
  • Energy issues impact low-income customers as disproportionate rate
  • Investing in better technology and better measures reduces risk, improves reliability; putting 90% bet on generators working is not a safe, long-term solution

 

Agenda Item 21: Project No. 52373 – Review of Wholesale Electric Market Design. (Discussion and possible action).

  • McAdams – Want to provide an opportunity to unpack some of statements within memo; want to consider action for next meeting
  • McAdams – Common themes emerging regarding near-term action; issues that have relevant rules in place that necessitate change
    • Normal guide path would take 5 months
    • A lot of common themes impacts price formation in summer 2022
  • McAdams – Should we remove price cap, change value of lost load, change ORDC, emergency pricing program, system-wide offer cap, etc.
  • McAdams – In terms of conservative operating doctrine embraced this summer, MCL should be studied at very least, should take ORDC as parallel consideration
  • McAdams – In terms of emergency response system, whatever changes we make there, need to be in time to impact next summer
  • Lake – You would be asking us to consider is to open these 2 projects up for discussion for next meeting?
    • Yes
  • Cobos – No secret that we wanted to open up discussion; need to study ORDC with third-party consultant
  • Cobos – Not sure what we want to do with price caps; as a Commission, we need to decide what we want consultant to look at
  • Cobos – Need analysis before project even starts; framework right now has been a very nimble action, new rule will help when push comes to shove
    • Have to open rule, just wondering the timing when we are able to take action
  • Cobos – ERS needs to be opened; need to look at both sides of equation
  • Cobos – Legislature has made clear that we need to incentivize dispatch coordination; don’t know if ancillary services is appropriate for PUC to discuss, but perimeters should be considered to be put in a rule
  • Lake – Need to be ready to implement levers that are already in rule but doesn’t exclude other projects
    • Gives PUC groundwork to be able to implement rules once we figure out blueprint in December
  • Lake – October work session will help crystalize what is in the December blueprint or not, but need to prepare for the potential of a new tool to put into the rule but wait until October work session
  • Cobos – Agrees still needs to gather more information in October work session, agrees changes to ERS, but may also want to consider opening up TDU load management program
  • Lake – October will be last work session and will be taking information from stakeholders but feel free to start preparing to layout suggestions
    • This meeting will be inflection point where it shifts to start vetting certain ideas
  • McAdams – Studies will be coming from generators as well and speakers may be available to opine on it
  • Cobos – Would like more information on coupling of CAP and swap as far as opportunities and cost
  • McAdams – Depending on load level talking about real money which is why studies will be helpful, maybe go back to 2014 at starting point to see scale and how things have changed
  • Lake – Sums up; come to October meeting with ideas on market redesign that are not currently in rule and at that time they may consider items to put in place that are not currently in rule
  • Staff – There is a distinction between opening a project and opening a rule, can open a project at any time with no deadline to come forward and can continue to discuss until Commissioners are ready to come forward with a rule