Pat Wood III (PUCT Chairman 1995-2001, FERC Chairman 2001-2005)
Robert W. Gee (PUCT Chairman/Commissioner, 1991-1997)
Judy Walsh (PUCT Commissioner 1995-2001)
Brett Perlman (PUCT Commissioner 1999-2003)
Becky Klein (PUCT Commissioner/Chairman 2001-2004)
Alison Silverstein (PUCT advisor 1995-2001, FERC advisor 2001-2004)
The Texas Legislature has sent to Governor Abbott new statutes to address some of the problems that contributed to this disaster. But beyond these new laws, Texas has more work ahead to protect customers and ensure that our energy infrastructure works adequately. The February outages were triggered by an extreme weather event but were exacerbated by underlying problems that affected the entire energy system from the production of natural gas to the delivery of electricity to the customer.
These problems extend beyond the Electric Reliability Council of Texas (ERCOT) and the Public Utility Commission of Texas (PUCT) to include parts of the energy system regulated by the Texas Railroad Commission, the Texas Reliability Entity, and the North American Electric Reliability Corporation, all of which bear some responsibility for the reliability of our energy system. If Texas is to mitigate future energy system disasters and restore our state’s reputation, we must do more than just tighten governance on ERCOT and the PUCT, weatherize power plants, patch the electric market, and reform some utility and retail practices.
As past PUCT Commissioners, the authors helped to design and implement many elements of ERCOT’s electric system and market structure between 1995 and 2004. The mission of the PUCT is to protect customers, foster competition, and promote high-quality infrastructure. Until this February, the Texas electricity system had largely achieved that goal. We created a strong, competitive, reliable electricity system whose overall performance for more than 20 years lowered electric bills for all customer classes, created innovative options for electricity customers, attracted an unprecedented level of new natural gas and renewable generation, and kept the lights on as our state population grew by 40%.
While the February 2021 event was clearly unprecedented, prior outages should have provided a wake-up call to policymakers and regulators to address reliability issues. The events of February 2021 resulted from several policy failures as well as from operational and planning failures across our state’s electric, natural gas and water systems. We must address the causes of this winter’s weather challenge and prepare to deal with emerging economic, technology and extreme weather realities.
Texas is the world’s ninth-largest economy. We owe it to our families and fellow citizens to learn from this event, plan for the future, and do the right thing for the good of Texas. We offer the following observations and 20 recommendations, which are organized based on the outage’s contributing factors. Some of these require further legislative action; others can and should be implemented by the PUCT under existing authorities.
ERCOT’s publicly released data and other analyses indicate that almost 9 GW (8%) of ERCOT’s generation fleet was already out for maintenance on February 14 and another 22 GW (21%) of ERCOT’s total generation fleet failed before 1am on February 15, when ERCOT was forced to initiate customer load-shedding. Natural gas generators represented the greatest loss of production (26 GW, including units out for maintenance). Most of those plants failed due to insufficient preparation for the intense winter storm and/or because fuel became unavailable (whether on-site, like coal plants, or due to lack of natural gas availability or delivery capability). Forty-six percent of ERCOT’s total thermal generation capacity was unavailable or failed during the outage.
SB3, the new reliability statute, requires the PUCT to adopt power plant winterization standards, informed by adverse weather forecasts, with compliance requirements and penalties for non-performance. This is a good start, particularly given that a recent analysis from the Federal Reserve Bank of Dallas suggests that the weatherization of Texas gas and wind power plants would be cost-effective. The PUCT and ERCOT will have to ensure that these standards are appropriately rigorous and receive adequate enforcement.
SB3 directs the PUCT to examine ancillary services and incentives for dispatchable generation such as natural gas plants, and modify the design, procurement, and cost allocation of ancillary services to assure that appropriate services are available for weather emergencies. ERCOT and the PUCT are also directed to look at whether dual-fuel capability, fuel storage and different fuel procurement supply policies are appropriate solutions for extreme weather performance. The statute even calls for operation under drought conditions. These measures are a good start to assure that gas-fired power plants retain reliable fuel access.
Winterizing power plants will not help if power plant fuel supplies and delivery infrastructure (natural gas wells, production and processing facilities, storage, and pipelines) are not also winterized. Therefore, SB3 sets up a process to “map the state’s electricity supply chain” to identify priority electricity service needs during extreme weather events, including natural gas production and delivery facilities. SB3 directs the PUCT and RRC to identify best practices for weatherizing these facilities, adopt a rule for natural gas facilities in the electricity supply chain to weatherize their facilities and prioritize electric service to those facilities.
It is not clear that SB3’s new requirements will be sufficient to assure continuing delivery of natural gas at reasonable prices during future winter emergencies. SB3 places no compliance deadlines on the natural gas weatherization requirement, so the interdependence between natural gas supply and electric power generation could remain unaddressed for some time.
SB3 assumes that weatherization is only needed for identified supply chain facilities, which does not reflect the true interconnectedness of the entire natural gas delivery infrastructure. If only the natural gas facilities that directly serve electric generators are winterized, many others could fail, causing a shortage that drives natural gas prices across Texas and the entire Midwest. Therefore, the Legislature should clearly define “price gouging” for electric emergencies and set an appropriate limit on how high gas market participants can raise natural gas forward and real-time prices during emergency conditions.
In February, Texas and its neighboring states experienced a multi-day run of Arctic temperatures and winds that drove ERCOT electricity demand for heating to unprecedented levels. As much as 35 GW (over 40%) of the total Texas electric demand was for heating. Much of Texas’ housing stock has little or no insulation and relies only on electric resistance heaters rather than gas heat, but at such low temperatures, uninsulated homes cannot be heated effectively. This drove ERCOT’s winter electricity demand to unprecedented levels; had ERCOT not called rolling outages early in the morning on February 15th, we were on the way to an all-time system peak later that day.
Between leaky buildings, lack of electricity and poor public communications, over 100 Texans died of hypothermia or carbon monoxide poisoning during the February blackout.
Texas must fix this by improving the energy efficiency of our buildings. Over half of Texas homes were built before the state adopted building energy codes with insulation requirements in 2001. And over 60% of Texas homes are heated with electricity rather than gas. If these homes had energy-efficient building shells and heaters before February 14, that could have reduced electricity demand by at least 15 GW—enough to drop peak demand down to 62 GW and offset the loss of most of the generators that failed on February 14 and 15. Estimates developed for the U.S. Department of Energy indicate that Texas could use cost-effective energy efficiency measures to reduce 2030 residential electricity use by 18.5% and total electricity sales by 17%.
Since Texas is the fastest-growing state in the nation, we have the opportunity to improve the quality of our housing stock with new builds, saving energy use and lowering energy bills for many residents and businesses. Texas energy efficiency requirements for new buildings were last updated in 2016 to comply with the 2015 International Energy Efficiency Code and 2015 International Residential Energy Code. International building codes are updated every three years; the 2021 IECC and IRC code updates are now available. Texas should enact legislation to require automatic adoption and use of the latest international efficiency codes. The U.S. Department of Energy estimates that new homes built to the IECC code would reduce energy use and bill savings by about 9% each.
As part of Texas’ electric restructuring bill enacted in 1999 (SB 7), the state required electric utilities to undertake limited energy efficiency programs beginning in 2002, giving each utility a minimum demand reduction goal – to reduce the growth in peak demand by 10% each year in programs delivered by retail electric providers. The PUCT increased this requirement in 2010 to reduce 30% of peak load growth plus an energy savings goal. Texas’ energy efficiency programs have some of the lowest energy use reduction goals and per capita spending on energy efficiency compared to all other states.
The PUCT should conduct a formal study to determine more appropriate energy efficiency goals and programs for Texas. Those programs should reflect the need to increase the efficiency of Texas’ installed air conditioning and heating equipment in Texans’ homes and businesses, in order to reduce both energy use and peak loads. These should be assessed using broader cost-effectiveness tests that recognize residents’ and owners’ bill savings, grid operational reliability impacts, jobs benefits, health and equity benefits as well as energy savings. The study should be completed within nine months and the PUCT should adopt implementing rules six months later. The PUCT’s new rules should increase utility energy efficiency program funding to levels that can support higher efficiency goals.
Over 4 million Texans (15.5%) live below the poverty line, and our state has a shortage of low-income housing with only 29 affordable homes for every 100 low-income renters. Low-income homes are less energy-efficient than other homes, and low-income citizens pay a much higher proportion of their incomes on housing and energy than other citizens. Making low-income homes, heaters, and air conditioners more energy efficient will reduce peak demand for all of ERCOT, reduce those customers’ energy bills, and improve their health and comfort.
At present, fewer than 4,000 Texas low-income dwellings per year receive efficiency retrofits using federal DOE-WAP and HHS-LIHEAP-WAP funds; the utility-administered low-income weatherization programs weatherize fewer than 15,000 dwellings per year.
Therefore, the PUCT should require at least 40% of electric utility energy efficiency program savings to come from retrofits of low-income and multi-family housing. The Legislature should modify TDHCA’s low-income programs to include weatherization, building repairs and replacement of inefficient heating and cooling appliances and systems. The TDHCA low-income program requirements should be modified and funded to serve a minimum of 100,000 households per year.
All electric customers could modify their energy use in response to changes in the price of electricity or a call to conserve to protect grid reliability. But few customers practice this demand response capability, often because they don’t have the information, tools or incentives to do so. Some of these tools include smart thermostats, automated building energy management systems, or remote-controlled equipment such as pool pump or water heater controls. Some retail electric providers and energy service companies and aggregators offer formal demand response programs that send price signals or control signals to customers’ equipment, with payment for appropriate load reductions or increases as needed. If more of ERCOT’s load could be managed through planned, deliberate, customer-consensual measures, we could minimize future involuntary load-shedding.
SB3 “allows” electric utilities to establish load management programs for use in the event of a grid emergency. It also tells them to seek voluntary load cuts from large customers before cutting residential loads. These measures are not enough.
Instead, all-electric utilities, municipal utilities, and cooperatives should offer customers compensated demand response options and procure demand response that can cut at least 10% of each entity’s summer peak load and 10% of each entity’s winter peak load through remote actuation. Design these and other measures to maximize and leverage customer-owned and distributed storage and distributed generation as well as customer load management for the provision of ancillary services, to facilitate the integration of intermittent generation and enhanced grid reliability around the clock. Coordinate these with Retail Electric Providers and adjust ERCOT and PUCT rules as needed to facilitate increases in price- and reliability-responsive demand response.
Every customer who enrolls to provide emergency demand response should be required to certify that it is not a critical load under the criteria the PUCT will develop pursuant to SB3. Each distribution utility should verify that no emergency demand response customer it serves is on its critical load registry.
SB3 requires the PUCT and utilities to update criteria and recognition of critical residential customers and critical facilities. It also requires the utilities to conduct annual load-shed exercises. These are valuable first steps. But if Texas identifies more critical customers yet cannot manage distribution outages more effectively, this measure may not help us better manage future outages.
Texas’ electric utilities had to cut service to millions of customers because the critical facilities (those they knew of) are located on large circuits serving large numbers of customers and high electric loads on every circuit. Once those circuits were protected, there was no electricity left to serve the remaining circuits that don’t serve critical facilities, so all the remaining circuits were cut. Although utilities aim to rotate small-scale outages across many circuits, in February there were so many circuits out relative to the available generation that there was no way for the utilities to rotate the outage burden among circuits and customers. Thus, many customers on circuits without critical facilities stayed out of power for several days in a row. The lack of outage rotation in February was the most customer-impacting part of this disaster—many homes reached freezing temperatures during multi-day outages, causing many deaths from hypothermia and carbon monoxide poisoning, and millions of frozen pipes and damaged property and possessions.
This outage management process must be overhauled. It is easier to manage outages and rotate outages fairly if circuits containing critical facilities are smaller and require less power, and if non-critical circuits are smaller so that outage burdens can be shared. Dividing the grid into smaller operational segments will enable the utilities to conduct smaller, more granular and targeted outages affecting fewer customers.
Texas customers have funded major utility investments in smart meters and other smart grid infrastructure. But the utilities have not yet leveraged these investments for better outage management. Extreme weather conditions are a perfect opportunity to deliver that functionality. Until it is clear that meter functionality and control capability can be used dependably for surgical outage management, other solutions are needed.
The PUCT should order utilities to modify their distribution systems using sectionalization devices wherever feasible to cut up each circuit into smaller sections, starting on those circuits hosting critical facilities so that a single hospital doesn’t lock in service for a giant chunk of a city and leave others literally out in the cold. Sectionalization around critical facilities and industrial customers will enable more granular outage management and outage rotation among customers.
Require large industrial and commercial customers, including State of Texas facilities, to have the capability to reduce load remotely by at least 30% under emergency circumstances, and require these facilities to cut their loads before ERCOT orders residential customer load-shedding.
Recommendation 3-3—Require all critical facilities to have two days’ worth of backup power
SB3 requires some water utilities to better prepare to maintain water provision to wholesale customers during emergencies. The Legislature dropped provisions to offer matching funds to hospitals, nursing homes, water, and wastewater utilities to acquire backup power systems.
The Legislature should require most critical facilities to have two days’ worth of backup power (combination of PV, battery, and low-emissions propane or diesel generation). This offers two major benefits—it will improve community resilience in the face of diverse threats (such as extreme weather disasters or cyber-attack), and it will help each critical facility and its community ride through a brief grid outage or outage management failure. While this would not be easy or inexpensive, the state can facilitate greater critical facility resilience through state Energy Star loans and energy efficiency improvements and leverage federal funding from FEMA, the Rural Utility Service, and other federal sources.
The February winter storm was a historic event, but the role of scenario planning is to model just such extreme events. ERCOT’s season-ahead forecasts and scenarios have not created sufficiently broad, stressed scenarios for reliability and contingency planning purposes. ERCOT’s pre-winter Seasonal Assessment in November 2020 predicted winter peak demand under normal conditions to be 57.7 GW and an extreme season peak load of 67.2 GW. This compares to the 77 GW ERCOT expected to hit later on February 15 if not for the load cuts, so ERCOT’s planning scenario was at least 15% too low. ERCOT has under-estimated peak load and peak net load in other summer and winter load events.
ERCOT’s pre-season assessment predicted about 8.5 GW of thermal generation on outage and 7 GW of wind capacity out of service. In fact, actual outages were more than five times greater, as the ERCOT graphic below shows. Actual thermal generation during the freeze drastically under-performed ERCOT’s winter assessment. Meanwhile, ERCOT’s assessment anticipated only 963 MW of planned winter-rated wind and solar capacity available,  when in fact generation from those resources actually exceeded those projections.
ERCOT’s extreme case seasonal scenarios have assumed that adverse conditions occur individually (e.g., high demand with low renewables is a different scenario than high demand with low thermal generation) rather than assuming that multiple adverse events occur simultaneously (as often happens in real life, whether due to common modes of failure and/or Murphy’s Law). In the case of this event, ERCOT experienced the combination of a massive spike in cold weather demand with a massive failure of thermal generation, low renewable generation, and a spike in natural gas prices, all stretching over five days. ERCOT’s recent Summer 2021 assessment now reflects multiple adverse condition scenarios.
Load and net load (customer demand net of real-time wind and solar generation) affect how much and which generation is made available to meet load—i.e., daily and hourly operational reliability—and how much electricity will cost in each period (i.e., electricity price). Consistently low forecasts or consistent misses during peak periods lead to lower generation availability, higher prices and more scarcity pricing events.
ERCOT, its market monitor, and the PUCT should all be scrutinizing ERCOT’s past load forecasting and net load tools in much greater detail and sophistication. They need to identify significant biases and flaws in ERCOT’s load forecasting tools and data, identify and implement better forecast tools, methods and data, and conduct on-going reassessment and improvement to assure on-going forecast accuracy with limited bias or error over time.
ERCOT should design and explore multiple climate change and extreme weather forecasts and demand scenarios in combination with multiple compound failures per event, for planning, resource adequacy assessments, and stress-test analyses. ERCOT’s extreme stress scenarios should factor in potential communications and cyber-security failures as well as compound losses of transmission and/or generation.
The SB3 requirement that Texas agencies consider weather predictions from the State Climatologist is a good start, but the magnitude of climate threats requires us to do better. The Legislature should require the PUCT, RRC and utilities to use forward-looking 30-year climate and extreme weather projections in combination with the worst past extreme weather and grid disaster events over a 50-year history in all planning scenarios and electricity asset reasonableness and prudence evaluations.
During the five-day February power outages, it appears that errors in the design and implementation of ERCOT’s market pricing software and industrial customer curtailments contributed to both dramatically high spot market prices and natural gas scarcity. The PUCT’s decision to keep the $9,000/MWh scarcity price cap in effect for several days – even though the price cap clearly couldn’t bring additional generation back online — exacerbated the disaster.
The ERCOT energy markets are designed to operate when there are sufficient supplies to address demand and to raise prices under scarcity conditions. SB3 directs the PUCT to revise wholesale pricing mechanisms for emergency conditions, including a circuit breaker for use when higher prices cannot incent more electricity production. The statute allows the PUCT to give generators cost-of-service pricing if appropriate for some portion of the emergency event.
Summer heat and winter storms pose very different challenges for generation adequacy in Texas, and grid failures have different human and economic consequences in summer versus winter. To date, most resource adequacy efforts have focused on preparing to meet summer peaks rather than readying for winter weather operations, even though ERCOT’s most stressful periods have historically occurred in January and February. Because so much of the state’s dispatchable supply is fueled by natural gas, the winter demand for gas to heat homes and businesses (which doesn’t exist in the summer) is a significant competing factor that does not complicate summer peaks. But this event reminded us that the consequences of a grid failure in winter can have much costlier human and economic consequences than a summer peak failure. Therefore, the PUCT and ERCOT should examine the distinctions between summer and winter resource needs carefully to determine whether different market products (e.g., winter-focused ancillary services) or operational protocols (e.g., limits on maintenance scheduling) are appropriate to different seasons.
SB3 directs the PUCT to study ancillary services to determine whether and how those services need to change going forward and to evaluate whether additional seasonal and other products are needed to enhance reliability. This will be important work.
Grid operators use “black-start” capacity from stand-alone generators, batteries, or transmission to rebuild a power system, conducting a careful balancing act that powers one generator from another and adds customer load in sequence with generation additions. But in the February outages, it is not clear that all of ERCOT’s designated black-start assets would have been available to restart our grid due to maintenance, frozen equipment, or lack of fuel. If ERCOT had actually lost the entire power system to a full blackout, these black-start units would not have been able to do the job we pay them to do. This is unacceptable.
ERCOT and the PUCT must reassess black-start performance requirements, compensation and penalties. After the February outage, ERCOT said that had the grid collapsed, a black start could have taken weeks or months to complete. This is also unacceptable. ERCOT must stress-test its assumptions and generators’ claims about black-start unit availability and conduct regular drills to be sure that they can rebuild the system quickly after some future grid collapse, using whatever black-start resources are available. The benefits of this readiness go beyond weather-caused events to encompass preparation for and mitigation of impacts from cyber and physical attacks on the power system.
The blackouts in February were not due to the lack of generation capacity within ERCOT, but rather to the failure of many generators to prepare their hardware and fuel supplies adequately for the Arctic weather; a capacity market would not have prevented this outcome. Similarly, adding emergency capacity through a fleet of additional generators funded without regulatory scrutiny through a non-market charge or tax will raise costs to every electricity customer and chill other new or existing investors’ willingness to compete in the ERCOT market.
Modern power systems are extraordinarily complex and costly. The extended power outages in February demonstrated the painful human and economic consequences of power system failure. Given these stakes, it is essential that our state assure that the regulatory, technical and management leaders who manage the institutions that run our grid have the expertise, experience, and independence to act in the best interests of our grid and our citizens.
The Texas PUC is significantly under-resourced relative to its workload and to comparable state utility commissions. SB3 will add two more commissioners. The Legislature should increase PUCT funding and headcount to enable the Commission to hire more expert staff and consultants and improve the on-going education of staff and commissioners about pressing market and oversight issues. Prize expertise in Commissioner and senior staff appointments.
ERCOT now has a “hybrid” board of directors, with most members appointed from among the stakeholder communities and five unaffiliated directors. SB3 replaces ERCOT’s “hybrid” board with eight voting expert members, but those experts will be selected by political appointees and subject to a Texas residency requirement. We recommend that future ERCOT board members be selected by ERCOT Board members without any external political screening, to avoid any actual or appearance of political interference with critical, complex Board decisions affecting the ERCOT power system.
The PUCT needs trusted, competent external entities to review and verify compliance with all weatherization and reliability requirements placed upon electric generators and utilities. Additionally, ERCOT and the PUCT need to actively review and act upon reliability review findings. SB3 points in this direction but it is unclear how this process will work in practice. Compliance with weatherization and reliability mandates is essential to move the likelihood of future supply-caused power outages toward zero.
ERCOT is unique among U.S. electric interconnections because it is not synchronously interconnected with other electrical regions. For that reason, Congress and federal electricity regulators have to date granted unusual deference to Texas regulators to set ERCOT’s rules. Although additional transmission lines would not have been able to bring in enough additional energy to fill the deep shortfall ERCOT experienced on the morning of February 15, 2021, they could help to prevent or ameliorate future grid operational problems, particularly black-start energy that could be invaluable to rebuild the grid in the event of a future collapse. Last, given Texas’ wealth of wind, solar and natural gas resources, the state could benefit from exporting generation. These issues and opportunities should be studied in a thorough and apolitical fashion.
An independent expert committee studied the question of transmission integration (called alternative current interconnection) with the Eastern Interconnection in 1995-6 pursuant to a 1995 Legislative directive. That study concluded that the costs exceeded the benefits of such interconnection. The new SB1 budget authorization directs the PUCT to again study the costs and benefits of interconnection with the Eastern and Western Interconnections and with Mexico. Such a study can address the questions above.
There are investigations underway by ERCOT, the Public Utility Commission of Texas, the Texas Attorney General, and the Federal Energy Regulatory Commission with the North American Electric Reliability Corporation. The scopes and timetables for all of these investigations are unknown to the public.
The public and policymakers deserve to know what power plants failed, when they failed, the reasons they failed, when fuel deliveries became unavailable and why, where transmission constraints limited electricity deliveries from plant to customers, and whether each transmission and distribution utility cut all the load it was directed to cut and whether those load-shed allocations were appropriate. We should also confirm who profited from the $50 billion spent on power during the four-day-long outages—six times more than the cost of power in all of ERCOT in 2020.
It is not clear whether and when the results of these investigations will be made available for public understanding and policy development, even though responsible policy development depends on accurate information.
The governor should direct all Texas entities to release all investigation findings on the February outages, with no agency withholding privileges and minimal protection of private entities’ commercial information.
The public deserves to understand what happened when the institutions and infrastructure we rely on fail. Policy-makers need to know why it happened in order to prevent future failures. Understanding energy infrastructure problems requires that both private and public entities and individuals who possess relevant information share it, without excessive retreat behind claims of governmental or commercial privilege. The state should create formal mechanisms and entities to identify, collect and analyze relevant grid and related information for routine and extraordinary conditions (including fuel production and delivery status, power plant and transmission line status, and distribution utility outages and critical facility lists). A few elements of emergency event information may justify protection for the sake of grid security, but we should lean toward requiring all information to be shared analysis and improvement and minimize state agency or commercial barriers against information release.
SB3 and other new statutes adopted by the Texas Legislature have provided a swift and focused response to the February disaster, but there is more work to be done to address all of the causes of the February 2021 Arctic outage and prepare for the challenges ahead.
This paper offers a broad set of recommendations; with multiple investigations under way, we hope to learn more to refine these and other solutions in the future. Although the Legislature has taken initial action, many of the recommendations above can be implemented by the PUCT, RRC and ERCOT under existing statutory authorities, as indicated in the table below.
|RECOMMENDATION||PUCT existing authority||ERCOT existing authority||RRC existing authority||Legislative action needed|
|1-1 weatherize natural gas production and pipelines||More needed|
|2-1 Update energy efficiency building codes||Action needed|
|2-2 Raise utility efficiency program goals and funding||Raise goals||Raise goals and funding|
|2-3 Increase low-income energy-efficiency retrofits||Needed|
|2-4 Increase emergency demand response||Yes||Yes||Raise funding|
|3-1 Utilities to sectionalize distribution circuits||Yes||Helpful|
|3-2 Large customers to reduce load remotely||Yes||Helpful|
|3-3 Critical facilities to have backup power||More action needed|
|4-1 ERCOT to improve demand forecasting||Yes||Yes|
|4-2 ERCOT to use better scenario analysis||Yes||Yes|
|4-3 Acknowledge changing extreme weather threats||Yes||Yes|
|5-2 Evaluate summer v. winter protocols||Yes||Yes||Done|
|5-3 Reassess and toughen black-start||Don’t act|
|5-4 No “generation capacity reserve”||Yes||Yes||Helpful|
|6-1 Strengthen PUCT||Needed|
|6-2 Improve ERCOT Board of Directors||Revise new statute|
|6-3 Establish active compliance oversight||Yes||Helpful|
|6-4 Study ERCOT interconnection to neighboring grids||Yes||Yes|
|7-1 Release all Texas investigation findings to public||Yes||Yes||Not investigating||Governor should act|
|7-2 Routinely collect electric and gas information||Yes||Yes||No||Needed|
 ERCOT’s publicly released information includes presentations to Texas House and Senate Committees on February 25, 2021 and the “Update to April 6, 2021 Preliminary Report on Causes of Generator Outages and Derates During the February 2021 Extreme Cold Weather Event” (April 27, 2021)
 Golding, Kumar & Mertens, “Cost of Texas’ 2021 Deep Freeze Justifies Weatherization” (April 15, 2021)
 Electric Power Research Institute, “State Level Electric Energy Efficiency Potential Estimates” (Technical Update, May 2017)
 The Texas State Energy Conservation Office has the authority to update building codes every six years; this is insufficient
 Air conditioning is the highest single energy use in ERCOT through the summer. Energy efficiency improvements should include installation of high-efficiency air conditioners, which would reliably, consistently lower summer peak loads as Texas temperatures continue rising and heat waves last for more days each year. The federal Energy Star program says a new Energy Star-certified central air conditioning unit is 30% more efficient than units 12 years or older, and new window air conditioners are 15-20% more efficient than 10-year old and older units.