Winter 2021 Storm Event in Texas: An Assessment of the Energy System Reliability Failures

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Winter 2021 Storm Event in Texas: An Assessment of the Energy System Reliability Failures


May 24, 2021


John Dulude, Paul Banks, and Chris Norris, J.S. Held


Winter 2021 Storm Event in Texas: An Assessment of the Energy System Reliability Failures

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Clean Currents 2022

Editor’s Note: On the heels of the National Hydropower Association’s May 20, 2021, National Hydropower Association’s Southwest Regional Meeting, where the Texas power outage was discussed in detail, this article provides extensive detail about what happened in Texas and, importantly, speculates on how the Texas event relates to hydro. Access to the presentations from the Southwest Regional Meeting is available for $199 ($75 for employees who work for an NHA member organization – Purchase Access Here)

In February 2021, a severe winter storm occurred in the Southwest, Midwest, and Northeast, that caused a massive electricity-generation failure in Texas. Millions of homes and businesses were left without electric power, resulting in shortages of food, water, and heat.  

This article provides an initial overview and assessment of electrical system reliability failures experienced during the extreme weather event that occurred within the Electric Reliability Council of Texas (ERCOT) Interconnection service territory for five days in February 2021. It evaluates the event based on initial reports; identifies current processes and procedures in place to support system reliability; identifies vulnerabilities from initial reports and data; and examines what, if any, immediate actions may be appropriate to accelerate improvements and mitigate risk for future events.  

The narrative uses an approach similar to a typical root cause process to evaluate the response challenges and failures of the ERCOT electric system during the February 2021 weather event. The article does not constitute a formal, exhaustive, or complete root cause analysis that would encompass a more detailed evaluation of equipment and operational performance of the ERCOT system.  


In the past, the classic structure of a vertically integrated electric utility was focused mainly on reliability of service at a reasonable cost to the consumer. Simply put, electricity — like water & sewer and transportation — was either a government-owned or government-managed service. 

With de-regulation in the 1990s and 2000s, electricity, or access to it, became less of a service and more of a commodity with the expressed intention to increase competition and ultimately decrease costs to the consumer. This was a profound shift in the market concept for power and energy. 

More recently, we are in the midst of an even larger change to the electrical market globally via energy transition, i.e., the de-carbonization of energy in all of its forms. With both significant shifts comes benefits – but also unintended consequences.  

For the consumer, it is electricity at a lower cost – usually, and from a source that has societal benefits, but it comes with a challenge to maintain system resilience and associated reliability. 

Texas has reasonable electricity rates and in some cases in areas where there are competitive markets, very low rates. In normal conditions, the system works as designed. However, repeated performance reliability difficulties during extreme weather events – primarily in the winter – are still a challenge for Electric Reliability Council of Texas (ERCOT) and one that they will need to address. 

So why would the hydro industry be interested in how this winter storm event played out in Texas?  Let’s face it, Texas has only 0.2% of its capacity generated by hydro. But Texas also is the largest producer of wind power in the U.S. and if Texas were a separate country, it would rank 5th in the world for wind power production. It ranks second in photovoltaic capacity — second only to California.  

As states such as Texas move from classic forms of generation, maintaining adequate system resilience and reliability becomes more of a challenge. Energy storage becomes a much more critical component of system performance, but, as we all know, current energy storage technologies — though making great strides — are still limited at the utility-scale level to meet longer time-scale storage requirements. 

Texas is not the only state dealing with these challenges. In fact, every state is challenged with developing new ways to maintain adequate system reliability and that’s where hydro has an important part to play. What happened in Texas can happen elsewhere or from different circumstances that produce similar conditions such as large storms during hurricane season or heat waves in the summer.  

Hydro does not require imported fuel, it is emissions-free, clean, renewable, provides ancillary benefits such as recreation, irrigation, and flood control, and it can have significant operational advantages especially during an emergency like the one experienced in Texas. Most of all, hydro is a classic, historically proven form of generation that is extremely efficient. Every grid operator will tell you that hydro is a very important element in the overall generation mix. 


The Electric Reliability Council of Texas (ERCOT) operates and monitors much of the Texas electric grid—the Texas interconnection. As the independent system operator for the region, ERCOT schedules power on an electric grid that connects more than 46,500 miles of transmission lines and 710+ generation units. It manages the flow of electric power to more than 26 million Texas customers, representing about 90 percent of the state’s electric load.  

Three entities produce, distribute, and sell energy to the end user within the Texas (ERCOT) energy system: 

  • Generators produce electricity that is uploaded to the Texas grid. The generators consist of natural gas-fired power plants, coal fired plants, wind turbines, solar panels, and nuclear power plants. 
  • Transmission/Distribution Service Providers (TDSPs) own/operate the equipment and facilities used to transmit and/or distribute electricity in Texas. TDSPs are regulated by the Public Utility Commission of Texas (PUCT) and are required to provide non-discriminatory access to the grid. The three types of TDSP utility companies operating in with the ERCOT service area are: 
  • 1) private investor-owned utility companies 
  • 2) municipally owned utility companies 
  • 3) utility cooperatives 
  • Retail electric providers (REPs) purchase and sell electricity to end users but do not own the equipment by which the electricity is delivered. Depending on your location in Texas, you may or may not have a choice of REP. 

In competitive areas of ERCOT, power generators produce electricity from fuel and sell it on the wholesale market, where it is purchased by investor-owned TDSPs or REPs. Texas has five primary investor-owned TDSPs and approximately 300 REPs (see Figure 1). Within service areas that allow retail competition, customers can choose a REP, but they cannot choose the TDSP.1 

Figure 1: Map of Texas Electricity Retail Electric Providers 2

Customers living in areas without retail competition or in areas served by municipally owned utilities, electricity co-ops, and river authorities rely on a single service provider (see Figure 2).3 There is no choice of REP for customers in those areas as those utilities serve as both the TDSP and REP. According to the Legislative Budget Board, as of September 2019, six of the twenty largest cities in Texas maintained their own utilities, the largest being San Antonio.4 For example, Austin Energy produces, transmits, and distributes electricity. 

Figure 2 Map of Texas Electric Cooperatives and Municipally Owned Utilities 5

The transmission grid administered by the ERCOT independent system operator is located solely within Texas and is not synchronously interconnected to the rest of the U.S. electrical grid. This configuration means the transmission of electricity occurring wholly within ERCOT is not subject to the Federal Energy Regulatory Commission’s (FERC) jurisdiction under certain enforcement sections of the Federal Power Act (FPA).6  

Texas does have some interconnections with adjacent electrical grids; however, the connections are direct current (DC) ties. This configuration limits ERCOT’s ability to call on adjacent grid operators to support shortfalls in electrical energy during an emergency. 


On February 14, 2021, an extreme cold weather event began in the ERCOT service area. The event lasted through February 18, 2021. Total available electricity generation in the service area prior to the weather event was 107,514 megawatts (MW).  

As a result of the weather event, various power generators were either shut down or forced to produce at a lower capacity, reducing available electrical generation by 48% to 55,237 MW at the lowest point.  

At 7:06 PM on Sunday, February 14, demand for electrical power in the ECRCOT service area reached a new high of 69,222 MW, resulting in a shortfall of generation that required ERCOT to impose a forced outage of 20,000 MW of electrical demand.7 From approximately Monday, February 15, through Tuesday, February 16, little improvement in generation capacity was achieved. By Wednesday, February 17, small generation gains were made. By Friday, February 19, normal operations and generation capacity were returned as temperatures increased. As generation became available, the forced outages were reduced. 

The low temperature extremes during the weather event created significant disruptions of operational components (equipment), electrical systems (grid), fuel constraints and curtailments as with liquid natural gas (LNG) pipelines, and market (pricing). Notable disruptions included: 

  • Generation: A total of 356 generating units within the ERCOT service area—approximately 50% of the total generating assets—were unavailable or went offline during the event.8  
  • Load Shedding: Load shedding or forced outage is the operation of temporarily reducing the demand of electricity from an area, to avoid overloading the generators.9 In the event of an emergency, load shedding includes reducing “firm load” or electrical service to customers that are intended to always have electrical service available. Emergency load shedding began on February 15, 2021 and reached a peak of approximately 20,000 MW of load shed. 10 Electrical power curtailment/loss occurred throughout Texas and was directed by the ERCOT Independent System Operator through the TDSPs as part of the effort to protect the overall electrical network from a complete grid failure. System-wide, load shedding was required for more than 70 hours before full system operations within ERCOT could be restored.  
  • Frequency: Every generator of the same type in a power grid must be spinning at the same speed or the system may become unstable. As an analogy, for a car to go in a straight line, all the wheels must turn at the same speed. If one wheel suddenly starts to go faster than the others, the car might veer out of control.11 The same logic applies to power grids. In the U.S., the standard system frequency is 60 Hertz (Hz). Any deviation from that frequency can cause the spinning generators to exert more force on one another to bring the frequency back to 60 Hertz. If the deviation is relatively large—say more than one-half of one Hz—the grid will become unstable and could either significantly damage equipment or cause automatic controls to disconnect or “trip” the generators to protect them from damage.12 At one point during the February 2021 storm, electrical frequency registered below 59.4 Hz for four minutes and twenty-three seconds. According to ERCOT, if the electrical frequency had remained below 59.4 Hz for an additional four minutes and thirty-seven seconds (a total of nine minutes), additional generating units would have tripped, causing a potential loss of all generation to the grid and potentially leaving most of Texas without electrical service for weeks.13 
  • Restoration: Restoration of “normal operations” for the ERCOT electrical grid does not mean that all industrial, commercial, or retail users had their electrical service restored but rather that grid generation and transmission capabilities were restored to pre-event levels.14,15 

Several triggers are likely responsible for the number of forced power outages related to the extreme weather, but generally, they appear to fall into two primary categories: 

  • Inability of a unit to either start or maintain operational status related to weatherization, including both fuel-based facilities and renewables—primarily wind 
  • Reduction or loss of priority reassignment of natural gas for gas-fired facilities  

Significant attention has been focused on wind assets, but the facts indicate that all resources were substantially affected, with no one category necessarily affected more than others.  

Other events related to icing of transmission and/or distribution systems likely may have contributed to loss of service/contingent business interruptions of power, but these are beyond the scope of this article. 


Generally, two components associated with grid architecture were affected by the severe weather event: resilience and reliability.  

  • Grid resilience is the ability to withstand grid stress events without suffering operational compromise or the ability to adapt to the strain. It is largely about what does not happen to the grid or electricity consumers.16 Simply put, resilience is the ability of the electrical system to strain or deform without a sustained outage. 
  • Reliability, on the other hand, is a measure of behavior once resilience is broken. The start of a sustained outage is the transition point from the domain of resilience to the domain of reliability.17  

During this extreme winter event, ERCOT managed the system to satisfy the parameters for reliability within the ERCOT regulatory, operational, and market constraints at the time of the event to avoid a total system failure. Emergency system measures used load shedding to avoid a complete compromise of the electrical system.  

While emergency measures may have been necessary to avoid total system failure, the more significant question is whether the reliability parameters were appropriate. The loss of electrical service to more than 4 million customers within the ERCOT service territory during very unusual, yet not necessarily unique, winter weather conditions certainly brings into question how reliability parameters were established for such an event and to what extent the impacts should have been anticipated.  

One of the primary components of grid reliability is availability of resource reserves that can be deployed to the grid during a sustained outage of generation resources. In the case of the February event, both online generation and resource reserves—including standby and backup generation resources—were affected by the extreme temperatures and were not available to meet load demand. This, in turn, necessitated load shedding to maintain the real-time balancing of supply and demand. 


Before the February 2021 weather event, the ERCOT service territory had experienced similar extreme cold weather events during the first week of February 2011, as well as in 1983, 1989, 2003, 2006, 2008, and 2010. As distilled in the Executive Summary of the 2011 Federal Energy Regulatory Commission (FERC) Staff report:18 

Going into the February 2011 storm, neither ERCOT nor the other electric entities that initiated rolling blackouts during the event expected to have a problem meeting customer demand. They all had adequate reserve margins, based on anticipated generator availability. But those reserves proved insufficient for the extraordinary amount of capacity that was lost during the event from trips, derates, and failures to start. 

The report goes on to say: 

The actions of the entities in calling for and carrying out the rolling blackouts were largely effective and timely. However, the massive amount of generator failures that were experienced raises the question whether it would have been helpful to increase reserve levels going into the event. This action would have brought more units online earlier, might have prevented some of the freezing problems the generators experienced, and could have exposed operational problems in time to implement corrections before the units were needed to meet customer demand. 

Essentially, the findings of this report appear to align with the results from the 2021 extreme winter storm event. Among the suggestions in the 2011 report were 26 recommendations to improve reliability performance during an extreme winter weather event. One specific suggestion, extracted from Recommendation 11, stated, “NERC concluded there would be a reliability benefit from amending Reliability Standards to require Generator Owner/Operators to develop, maintain, and implement plans to winterize plants and units prior to extreme cold weather, in order to maximize generator output and availability.”19  


Both the timing (February) and type of extreme weather event in 2011 and 2021 are similar. In 2021, however, a significantly greater loss of generation occurred because of both forced power outages and the total number of generation units that were unavailable as a result of those outages. Frequency deviations—resulting from demand exceeding supply—became more critical during the 2021 event.  

Given that recommendations were developed following the 2011 event, the question remains as to why similar future events would produce similar results, although the 2021 event was more extreme in terms of low temperatures. 

A status review of recommendations from an ERCOT emergency meeting on February 24, 2021, indicates that even though many actions had been taken after the 2011 event, the enforcement component—to verify that generation owners weatherized their facilities—appears to have been insufficient.  

There are approximately 710+ generating units within ERCOT. According to ERCOT, approximately 80 of these units (slightly more than 10%) can be spot-checked each year. This low rate of annual inspection suggests additional inspection/assessment would allow more frequent spot checks (with additional follow-up as needed) and better ensure proper weatherization measures are implemented in accordance with FERC/NERC 2011 recommendations. 


According to the report given at the ERCOT February 2021 emergency meeting, “Generation owners and operators are not required to implement any minimum weatherization standard or perform an exhaustive review of cold weather vulnerability. No entity, including the PUC[T] or ERCOT, has rules to enforce compliance with weatherization plans or enforce minimum weatherization standards.”20  

As mentioned earlier, ERCOT performs site visits to review compliance with weatherization plans. However, according to ERCOT, “The only entity that can confirm that a plant is weatherized to any particular standard is the entity that owns the plant.”21  

A review of other ISO and/or regional transmission organization systems, such as PJM Interconnection, LLC, shows that formal requirements for cold weather guidelines exist, along with a checklist of requirements.  

The PJM Manual 14D: Generator Operational Requirements, Appendix N, specifically provides a checklist, safety focus, and annual training requirements for cold weather conditions.22 The list includes personnel preparation, staffing needs, and equipment preparation. Compliance enforcement includes penalties if certain measures are not in place within specified schedules. 

According to PJM’s standards for mandatory enforcement, Section 215 of the Federal Power Act (FPA) requires the Electric Reliability Organization (ERO) to develop mandatory and enforceable reliability standards, which are subject to FERC review and approval. FERC-approved Reliability Standards become mandatory and enforceable in the United States according to the NERC Implementation Plan associated with the Reliability Standard, as approved by FERC.23  

Pursuant to the Energy Policy Act of 2005, Congress expanded FERC’s role and jurisdiction under the FPA by adding a new Section 215 pertaining to electric grid reliability. Section 215(e) of the FPA authorizes FERC or an ERO (subject to review by FERC) to impose a penalty on a user, an owner, or an operator of the bulk power system for a violation of a Reliability Standard.24 

Because the transmission grid that the ERCOT independent system operator administers is located solely within the state of Texas and is not synchronously interconnected to the rest of the U.S., the transmission of electrical energy occurring wholly within ERCOT is not subject to FERC’s jurisdiction under certain enforcement sections of the FPA.  

Bulk electric system reliability has been delegated through an agreement between NERC and Texas Reliability Entity, Inc. (Texas RE) that assigns compliance and enforcement authority to Texas RE for purposes of ensuring that NERC reliability standards are maintained for the bulk electric system. Determining whether Texas RE has compliance and enforcement authority regarding weatherization of generating facilities would require a more detailed assessment of the representations in the ERO agreement between NERC and Texas RE. 

ERCOT is an “energy only” system with no capacity market. What is the need and potential benefit of a capacity market? A good analogy is provided by PJM in its description of a capacity market:25  

Capacity represents a commitment of resources to deliver when needed, particularly in case of a grid emergency. A shopping mall, for example, builds enough parking spaces to be filled at its busiest time – Black Friday. The spaces are there when needed, but they may not be used all year round. Capacity, as it relates to electricity, means there are adequate resources on the grid to ensure that the demand for electricity can be met at all times. 

A capacity market has been suggested as potentially incentivizing additional generation assets that could serve as added backup generation during unusual circumstances such as an extreme weather event. The state of Texas has not implemented a capacity market within ERCOT; rather, it relies on market rules to incentivize the availability of additional capacity assets. 

It is beyond the scope of this article to assess the overall planning process for adding either firm generation or backup generation within the ERCOT service territory. Several guides and related documents are relevant to system expansion, including expansion of generation within the ERCOT service area. They are identified in the ERCOT Planning Guide, dated January 2021. If there is a conflict between the Planning Guide and Protocols, any Public Utility Commission of Texas (PUCT) Substantive Rules, or the NERC Reliability Standards, then such PUCT Substantive Rules, NERC Reliability Standards, and the Protocols shall control.26  

It is not clear at this time whether Texas RE, on behalf of ERCOT and in accordance with NERC requirements, can implement or has implemented compliance enforcement either related to or in anticipation of generation for this or other extreme weather events. Weatherization and associated availability of generation could be one component of resolving grid performance issues that ensure compliance with specific NERC operational guidelines. It appears that issues related to the lack of weatherization of generation assets contributed to the significant load shedding associated with the extreme winter weather event in Texas earlier in 2021. 

After the 2011 weather event, the Texas legislature passed a law requiring mandatory reporting of emergency operations and independent review by the PUCT.27 As part of the report following the 2011 extreme cold weather event, FERC Staff recommended that winterization practices for Texas be mandatory and that the legislature grant the PUCT the authority to impose penalties for noncompliance as well as hold senior management responsible for a particular generation asset to review and acknowledge that their winterization plans were appropriate.28  


Standard of care generally refers to the duty of a professional to provide services as expected to be provided by similar professionals under similar circumstances. In the case of generation assets within the ERCOT service area and, more importantly, performance of those assets during the most recent extreme weather event, there is a standard of care that a reasonable owner/operator would be expected to meet to ensure that its facilities were available.  

Whether or not those standards were met during the 2021 extreme weather event has yet to be determined; however, substantial review will certainly be done as to whether reasonable care was appropriately applied to the weatherization of generation assets. From all current indications, one of the weak links in the overall performance within ERCOT appears to be related to a lack of sufficient weatherization of generation assets.  

What should a reasonable standard of care related to weatherization of electrical grid assets and, more specifically, generation assets take into consideration? According to previous FERC findings, a reasonable standard of care includes but is not limited to:29 

  • Consideration during plant design 
  • Equipment and material selections 
  • Maintenance and inspections of freeze-protection elements  
  • Evaluation of specific freeze-protection maintenance items  
  • Inspection and maintenance of heat-tracing equipment
  • Inspection and maintenance of thermal insulation 
  • Inspection of valves and piping 
  • Use of wind breaks/enclosures 
  • Proper training of personnel specific to extreme weather events 

In addition, any changes or modifications during the lifecycle of the facility should be considered, as well as how those changes may affect current weatherization or require additional weatherization. 

ERCOT stated in its initial findings after the 2021 event that generation owners and operators are not required to implement any minimum weatherization standard.30 However, this may not relieve owner/operators from what would be considered a reasonable standard of care, given the importance of the product provided and the potential consequences if that product is not delivered. 


A number of detailed follow-up assessments of the 2021 winter storm will be performed to determine the root cause of system failures, potential contingent business interruption, system vulnerabilities, and improvements required to mitigate risk for future events.  

Regarding system improvements, an independent, detailed audit and assessment of weatherization (in other words, what worked, what needs to be improved, and so on) at all generating facilities would be an important first step, especially from the perspective of generation owners and operators. Periodic critical review of performance is an important indicator to customers, shareholders, and regulators that reasonable standards of care are being considered and updated as needed. By self-initiating this type of detailed weatherization audit, owners/operators will also be in front of the eventual regulatory examinations that will certainly follow such an event.  

Another important consideration is the potential effects of this winter storm on environmental, social, and governance (ESG) criteria performance—perceived or actual. ESG is used to measure the sustainability and societal impact of an investment in a company or business. This is a particularly important measurement for private equity and other investors and is attracting a growing interest among customers as well.  

Questions that should be considered include those seeking to understand how the recent performance of a facility or system affected: 

  • Public image and public health and safety 
  • Reputation 
  • License to operate 
  • Regulatory scrutiny 
  • Attraction of future investment 
  • Ability to obtain insurance coverage and cost of that coverage 
  • Shareholder value 
  • Pricing impacts and effect on customer rates 

All these questions and the associated answers ultimately go directly to the bottom line of a company’s financial performance. A materiality assessment of ESG programs and attributes following this extreme weather event would provide a baseline measure of potential impact from the storm as well as a measure of improvement going forward. 

Both independent weatherization audit assessments and materiality assessments of ESG programs and attributes would have an immediate and measurable benefit to energy providers and their customers. 

Texas is not the only state dealing with these challenges. In fact, every state is challenged with developing new ways to maintain adequate system reliability and that’s where hydro has an important part to play. What happened in Texas can happen elsewhere or from different circumstances that produce similar conditions such as large storms during hurricane season or heat waves in the summer.  


1 by Selectra. Utility Companies in Texas, 

2  Map adapted from: by Selectra. Utility Companies in Texas, 

3   Go Solar Texas. Nonprofit Utilities Toolbox, 

4   Minton, L. Where Texas’ Electricity Resources: Where Power Comes From—And How it Gets to You, Fiscal Notes, August 2020. 

5   Map adapted from: Go Solar Texas. Nonprofit Utilities Toolbox, 

6   Dulude, Banks, Norris. Assessment of Energy System Reliability Failures During the Extreme Cold Weather Event in the ERCOT Region. LinkedIn, March 2021. 

7  While ERCOT directs electrical providers when to shed load and is responsible for identifying which utilities reduce load and by how much, ERCOT does not own or operate the equipment by which those electrical loads are physically connected.
Magness, B. Review of February 2021 Extreme Cold Weather Event – ERCOT Presentation, ERCOT Public, 2/24/21, Slide 19. 

8 Magness, B. Review of February 2021 Extreme Cold Weather Event – ERCOT Presentation, ERCOT Public, 2/24/21, Slide 10. 

9 Power Continuity. What is load shedding? – Knowledge Base. 

10 Magness, B. Review of February 2021 Extreme Cold Weather Event – ERCOT Presentation, ERCOT Public, 2/24/21, Slide19. 

11 Penn State College of Earth and Mineral Sciences. Introduction to Electricity Markets (EBF 483), 9.1.2 Frequency Regulation. 

12Penn State College of Earth and Mineral Sciences. Introduction to Electricity Markets (EBF 483), 9.1.2 Frequency Regulation. 

13 Magness, B. Review of February 2021 Extreme Cold Weather Event – ERCOT Presentation, ERCOT Public, 2/24/21, Slide 12. 

14 Dulude, Banks, Norris. Assessment of Energy System Reliability Failures During the Extreme Cold Weather Event in the ERCOT Region. LinkedIn, March 2021. 

15 It is important to note that normal operations for ERCOT does not necessarily entail full power restoration at the delivery point or to the end user. For example, if a local transmission provider had received damage to its line or needed to perform a check of all equipment prior to energizing the equipment, there would be a delay in the end user receiving electricity. 

16 JD Taft, PhD, Electric Grid Resilience and Reliability for Grid Architecture, November 2017.p. 3.  

17 Taft, p. 3 

18 FERC Staff, Report on Outages and Curtailments During the Southwest Cold Weather Event of February 1-5, Executive Summary, August 2011. 

19 FERC Staff, Report on Outages and Curtailments During the Southwest Cold Weather Event of February 1-5. 

20 Magness, B. Review of February 2021 Extreme Cold Weather Event – ERCOT Presentation, ERCOT Public, 2/24/21, Slide 17. 

21 Magness, B. Review of February 2021 Extreme Cold Weather Event – ERCOT Presentation, ERCOT Public, 2/24/21, Slide 17.  

22 PJM Operations Planning Division, PJM Manual 14D: Generator Operational Requirements, Revision: 53, November 23, 2020, Appendix N, p. 145. 

23 North American Electric Reliability Corporation, “Mandatory Standards Subject to Enforcement,” 2011.   

24 Federal Energy Regulatory Commission, “Enforcement Reliability,” August 2020.   

25 PJM, “Capacity Market,” 2021.   

26 ERCOT, ERCOT Planning Guide, January 1, 2021, p. 1-1.  

27 FERC Staff, Report on Outages and Curtailments During the Southwest Cold Weather Event of February 1-5.  

28 FERC Staff, Report on Outages and Curtailments During the Southwest Cold Weather Event of February 1-5.  

29 FERC Staff, “Report on Outages and Curtailments During the Southwest Cold Weather Event of February 1-5.” 

30 Magness, B. Review of February 2021 Extreme Cold Weather Event – ERCOT Presentation, ERCOT Public, 2/24/21, Slide 17. 


John DuludePE, MBA, Senior Vice President at J.S. Held, leads the Energy Transition & Impact Assessment and Permitting service line within the company’s Environmental, Health & Safety Practice. With over 40 years of domestic and international industry experience, John has spent much of his career in the power sector, with expertise ranging from hydroelectric, fossil, nuclear, wind, and solar generation as well as transmission facilities, system reliability, capital investment assessment, generation mix analysis, finance, equipment selection, and load profiles. He holds a Bachelor of Science Degree in Civil Engineering from The Citadel and an MBA from Charleston Southern University. He previously served on the NHA board of directors and held the leadership position of treasurer. 

Paul BanksPG, Executive Vice President—EH&S Practice Lead at J.S. Held, has 30 years of experience in environmental services, including various leadership positions for global firms. His proven tenure within environmental service includes organizational development and leadership across all practices, compliance and management system design, risk management, complex site assessment and remediation, and litigation support. Paul has been engaged in both domestic and international projects by clients in the manufacturing, chemical, power, oil & gas, and public sector. Paul is a licensed Professional Geologist in North Carolina and South Carolina and holds a Bachelor of Science Degree in Earth Science/Geology from the University of North Carolina Charlotte. 

Chris Norris, MS, PMP, Senior Industry Advisor for Power Generation, J.S. Held, has more than 30 years of experience in plant management, program and project management and operations and maintenance of power plants. Chris has managed multiple-owner, multiple inter-connected facilities in MISO/PJM. Chris has led and directed decentralized power generation portfolios and projects totaling more than 2,000 MW with asset values of approximately $1 billion.