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The Texas Blackout: A Regulatory Retrospective and Future Outlook

The state of Texas, and its isolated power grid, buckled under the weight of persistent cold in February 2021, leading to a historic and widespread blackout. In the immediate aftermath, the human cost of decisions made in the Texas energy market along with potential repercussions for the energy industry were revealed. The coming months and years may beget reforms to the Texas electric sector and renew attention to guidance from a decade ago.


Extreme winter weather leads to major outages

In mid-February 2021, a strong winter storm impacted much of the central US, including Texas. During the period of February 15 through 17, the weather conditions — persistent frigid temperatures, snow, and freezing rain — overwhelmed the Texas power grid. Demand for electricity and residential heating soared as many residents hunkered down, but thermal generating sources (such as natural gas, coal, and nuclear) encountered issues in producing power and transmitting it to end-use customers. As a result, widespread rolling blackouts were scheduled throughout the Electric Reliability Council of Texas, Inc. (ERCOT) region. The ERCOT footprint comprises 90 percent of Texas ratepayers, more than 25 million customers in all.

According to research firm Wood Mackenzie, outages on February 15 exceeded any mark in ERCOT in more than nine years. Total thermal generation capacity plunged from 70 gigawatts (GW) to 45 GW in just a few hours. The extreme supply disruption was largely attributable to weather-induced equipment failures. ERCOT's forecasts typically account for both load and supply variations during such extreme weather to ensure the system remains balanced, but the unscheduled supply outages throughout this storm placed overwhelming stress on the ERCOT system. As a result, ERCOT was forced to engage in extreme load-shedding to preserve minimum grid functionality and prevent a complete blackout of the entire ERCOT grid.

In advance of the winter storm, ERCOT forecasted a peak load of 82 GW through its scenario analysis. Based on winter supplies, a lion's share of that estimate — 50 GW — would be served by natural gas. However, the same factors that caused the increase in forecasted load hindered the production and distribution of gas. In some cases, natural gas power plants could not operate due to frozen instrumentation and pipelines.

Natural gas production faltered as well, resulting in a lack of available gas supply, even if some distribution systems remained operational. On February 16, nearly 18.7 billion cubic feet per day of gas production was unavailable due to freezing conditions, representing a staggering one-fifth of output in the entire US. In the south central region of Texas, nearly 20 percent of gas wells froze over and could not produce, according to the International Energy Agency.

Natural gas is the dominant fuel source for power generation in Texas across seasons. Over half of the state's electricity supply comes from natural gas, while the national average is below 40 percent. Gas producers in Texas incurred heavy financial losses due to production freeze offs during the winter storm. Nearly every link in the supply chain was disrupted or halted completely, from the tanks that separate oil, gas, and water in the field to the midstream infrastructure that eventually sends the gas to market. According to the publication Texas Monthly, approximately one-third of natural gas production in the state froze off from February 15 through 17.

How natural gas fared in Texas energy mix from February 15-17

While output from natural gas-fueled generation fell precipitously in ERCOT, the shortfalls also extended to other generating resources. Despite the disparate fuel sources used for the generation of power, frigid temperatures and winter weather presents obstacles for them all. During this event, renewable facilities grappled with the storm and at times were unable to meet demand. Texas is a leader in onshore wind capacity in the US, with approximately 28 GW total capacity and an expected average hourly output of 6.1 GW in February. However, on February 15, average hourly wind output fell to 3 GW and a nadir of 0.65 GW in the evening. As the storm continued into the next day, wind performance improved to an average hourly output of 3.8 GW — still significantly less than the 6 GW projection. However, as wind was only expected to provide a marginal amount of generation during this scenario, the loss of approximately 2-3 GW of output was less disruptive to the power grid than the loss of approximately 20 GW of natural gas-sourced supply. Wind turbines can be adversely affected by freezing components as well as low wind speeds often characteristic of winter storms.


Texas, an island of its own making

Unlike other markets in the United States, ERCOT has situated itself as a standalone entity in domestic energy markets. The regional grid operator does not fall under the full jurisdiction of the Federal Energy Regulatory Commission (FERC) and is not interconnected with the Western or Eastern Interconnections. Instead, FERC's authority is primarily limited to jurisdiction over electric reliability on the bulk power system under section 215 of the Federal Power Act (FPA), which includes ERCOT.

As a result of the decision to shun alternating current (AC) interconnections with neighboring markets, the ERCOT region within Texas is deliberately partitioned from interstate transactions on the power market. In such an emergency situation, if ERCOT had been able to import spare capacity and bolster supply from beyond its borders, perhaps some of the strain on its own grid and generating sources would have been alleviated. However, in this instance, the storm affected a large swath of the central US, which would have minimized the ability for the adjacent system operators to overcome their own generation constraints and send excess supply to ERCOT. Due to the frozen pipes and production equipment across the Midwest and South, industry observers do not believe interconnecting with other regions would have made a significant difference for this particular winter storm.

Only two direct current (DC) transmission lines are connected to the Eastern Interconnect by ERCOT. According to ERCOT, these small commercially operational ties account for 220 and 600 MW, respectively, comprising less than a percent of total net generation in ERCOT.

Pursuant to sections 210 and 211 of the Federal Power Act (FPA), the jurisdictional status of the two DC lines did not invoke any scrutiny as to ERCOT joining an Interconnect and therefore being under FERC purview.

A large high voltage transmission line project proposed in 2009, Tres Amigas,  sought to interconnect the Western, ERCOT, and Eastern interconnections, but the project has since been pared down and delayed with no expected approval or construction date.

Electric Reliability Council Texas map

As stated above, these limited instances of potential interstate electric transmission do not bring ERCOT under FERC authority. Energy transmitted within the ERCOT power grid is not considered to be "commingled" with the wider interstate grid and is generally not transmitted or consumed outside of Texas. Regarding the two DC lines, the FERC orders are limited exclusively to those projects under section 210 and 211 of the FPA.

The ERCOT framework deviates from other regional grids in the US in other ways as well. Most notably, ERCOT does not operate a capacity market or rely on any out-of-market resource adequacy directives. Rather, it relies exclusively on a competitive energy-only market to ensure resource adequacy. Capacity differs from energy in that it reflects a generating facilities' ability to deliver a quantity of electric energy when called upon. Several of the US power markets operate a capacity market as forward markets, where power plants will be compensated based on the amount of generation capacity offered in the future. Given that power plants are capital intensive and entail years of planning and construction, capacity markets are designed to secure long-term revenues and provide long-term price signals for generating sources while reducing risk and investment uncertainty.

Due to substantial production of oil and natural gas at home in Texas, ERCOT elected to forgo capacity markets and rely solely on energy markets. This market design — effectively a silo — results in generation on-site without the need to import from other states or regions. However, as the winter storm in February demonstrated, when natural gas gathering facilities and well sites (i.e., production) freeze, the lack of capacity market contributed to the lack of market incentives for Texas' energy infrastructure to adequately invest in winterizing facilities, alternative fuel sources, or on-site storage to ensure availability. ERCOT was designed with the expectation that scarcity pricing profits would incentivize private actors (generators) to internalize risks and provide reliable capacity during periods of grid stress. Although these events have been low frequency, the potential major consequences may encourage developers and utilities to incorporate such considerations in capital expenditure planning and other related processes.


History repeats itself

Ten years ago, an early February cold weather event mirrored many of the same problems as the winter storm this year. From February 1 through 5, 2011, the southwest region of the US — including Texas — endured extremely cold temperatures. Across several states, power blackouts and electricity transmission failures were responsible for a total of 4.4 million customers losing service at one point during the course of the event including up to 3.2 million Texans. Just as it is in 2021, blame was laid on the ability of the ERCOT grid to handle sustained cold weather.

In the immediate aftermath, on February 7, 2011, the North American Electric Reliability Corporation (NERC) announced it would investigate and prepare an analysis of the event. FERC followed suit on February 14 by initiating an inquiry to identify both the root cause of the service disruptions and to prevent a recurrence. By August of 2011, NERC and FERC published a report detailing their exhaustive findings.

"The majority of the problems experienced by many generators that tripped, suffered de-rates, or failed to start during the [2011] event were attributable, either directly or indirectly, to the cold weather itself. For the Southwest as a whole, 67 percent of the generator failures were due directly to weather-related causes, including frozen sensing lines, frozen equipment, frozen water lines, frozen valves, blade icing, low temperature cutoff limits, and the like." 1

The report stated that weather forecasts for the storm were accurate and generators and natural gas producers suffered severe losses of capacity despite the appropriate warning beforehand. "Entities in both categories report having winterization procedures in place. However, the poor performance of many of these generating units and wells suggests these procedures were either inadequate or were not adequately followed."2

Additionally, NERC and FERC found that ERCOT had not anticipated a problem in meeting customer demand during the weather event, nor did the other electric entities that were forced to institute rolling blackouts. As it did during the 2021 event, ERCOT acted to shed load in order to preserve minimum grid operational integrity and prevent "widespread, uncontrolled blackouts" throughout the ERCOT footprint. The report found that ERCOT could have coordinated and scheduled pre-planned generator outages better; these routine maintenance-based outages are typically reserved to the winter, but in advance of a major weather event, NERC and FERC recommended that those requests not be automatically approved and carefully considered in terms of geographic location and time. For instance, during the 2011 event, 11.5 GW of generation was offline due to scheduled outages that were approved prior to any knowledge of an impending weather event.

ERCOT Winter Storm Event Comparison3 2011 2021
Maximum generation capacity forced out at any given time (GW) 14.7 52.3
Cumulative generation capacity forced out throughout the event (GW) 29.7 46.2
Cumulative generators outaged throughout the event (#) 193 356
Cumulative gas generation de-rated due to supply issues (GW) 1.3 9.3
Maximum load shed requested (GW) 4.0 20.0
Duration of load shed request (hours) 7.5 70.5
Estimated peak load, without load shed (GW) 59.0 76.8

One instance in which the 2011 and 2021 events are different is with respect to upstream natural gas production. According to NERC and FERC, gas shortages were not a significant contributor to electric generator outages during the 2011 storm whereas in 2021, it has been reported that frozen well sites and pipes created a shortage and exacerbated supply deficits. In the gas-rich regions of the Permian and Fort Worth Basins, though, approximately one-quarter of the decline in available supply was attributed to natural gas shortfalls.


FERC inquiries and potential federal action

On February 16, 2021, FERC and NERC announced a new joint inquiry into the Texas blackout and factors affecting operation of the bulk power system. FERC has pursued broader rulemaking and policy statements pertaining to grid resilience in the past several years, therefore this inquiry may build on the formal record established in those proceedings and apply findings directly to Texas and nearby Midwest and Southern states.

Newly-appointed Democratic chairman of FERC, Richard Glick, indicated during the February open meeting that he would consider enacting mandatory reliability measures. Chairman Glick also stated that he did not believe ERCOT had a capacity problem during the winter storm event, but more of an energy delivery problem. FERC has oversight of NERC and reliability measures imposed on utilities and electric companies pursuant to section 215 of the FPA, although more widespread market reforms would require ERCOT to be under the FERC oversight umbrella. Although unlikely to happen, Chairman Glick did raise the nature of ERCOT as functionally an island as a structure that may warrant more scrutiny.4

Other than the joint FERC-NERC inquiry, FERC has also announced two additional proceedings investigating the February 2021 blackout:

  • A technical conference on climate change impacts relating to grid reliability and frequency of extreme weather; and
  • An enforcement proceeding on potential market manipulation or other violations in light of spiking natural gas and power prices during the event.

While much of the guidance produced by the 2011 FERC and NERC joint report failed to materialize into formal changes or reforms, it will be worth observing if FERC takes a different tack in 2021, particularly on winterization and making infrastructure more resilient in the face of extreme weather events. The NERC and FERC report in 2011 stated that winterization measures would not be "unduly expensive" and furnished some potential avenues to protect the grid, despite the relatively infrequent nature of severe winter storms in the region. According to the Board of Directors at ERCOT, no compulsory mechanisms for winterization exist and none were implemented following the issuance of the 2011 report. Site assessments and facility spot checks are performed at a rate of approximately 80 per year, but ERCOT ultimately defers to the plant owner or operator with regard to affirming winterization.

"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 ERCOT] has rules to enforce compliance with weatherization plans or enforce minimum weatherization standards."5

Notwithstanding the lack of firm winterization requirements, ERCOT has instituted some modifications in order to guard against winter storms in the decade since the 2011 event, such as, conducting an annual workshop on best practices for winterization, implementing a Seasonal Assessment of Resource Adequacy report, which includes a scenario analysis for extreme winter weather, among other personnel and protocol changes.

ERCOT oversees an energy market and operates a Balancing Authority Area, which grants oversight over electric generating facilities but not natural gas production facilities. Issues stemming from gas supply are not under purview of ERCOT and a broader response — perhaps FERC and/or NERC — would be required to necessitate policy reform or institute new reliability requirements. As a hypothetical, ERCOT could compel natural gas power plants to winterize equipment, but not natural gas pipelines. Defining the regulatory landscape going forward may be just as significant as identifying and evaluating the underlying technological and system problems.


Anomalous disasters or auguring a future pattern

This past year, another of the largest states in the US endured an extreme weather event, one that historically may have been deemed anomalous. In some ways, the winter storm that disrupted the Texas electric grid was the converse of the extreme heat and wildfires that beset California in the summer of 2020, with a similar result. As these "100-year" weather events occur more often, it will become imperative for policymakers and regulators to plan accordingly. In the past, utilities and grid operators would account for the remote possibility of such a crisis, but in an emergency context. The coming months and years may reveal a new approach focused on novel solutions or increased oversight in order to prevent major blackouts such as Texas and California in the past calendar year, respectively.

If climate change is accelerating the occurrence of such severe weather events, the specific risks endemic to each state or region may dictate how best to proceed. In Texas, for example, the winter storm in February laid bare all of the insufficient winter preparations in a hot weather state. It is intuitive that Texas designed its grid infrastructure for summer peaks and high demand associated with cooling and air conditioning needs. At the residential level, households and dwellings have been built in order to shed hot temperatures and not retain heat — the very tactic that may have exacerbated the blackout crisis and bring adversity to families trying to keep warm without power.

From a midstream perspective, delivery of natural gas in Texas from generator to end-user also falters in the cold. Pipelines are generally not insulated in the region, and if it were a common practice, it is not linear or a closed feedback loop. The winterization and insulation of pipes in Texas could affect the ability of power plants to perform optimally in the summer, when ERCOT projects highest load. Some plants were indeed winterized, insulated, and equipped with heat tracing circuits to keep components warm; the frigid temperatures in this winter storm prevailed and still froze some of these parts. Further, the natural gas supply in Texas tends to be more liquids-rich than other parts of the US, such as the Marcellus shale play where the gas is drier and less prone to freezing in cold conditions.

Any technology seeking to accrete heat may lead to unintended consequences, which is likely part of the cost-benefit analysis that Texas regulators and ERCOT will undertake. It has been unforeseen that a state will confront polar opposite scenarios. An ice storm unexpectedly hit Texas just a few months prior, in October 2020, and did not present the magnitude of cascading grid failures as the February storm. However, the ice storm revealed issues with wind turbines and other infrastructure that were hampered by ice accumulation. ERCOT, project developers, and utilities may study both events to identify how to make its renewable generation more resilient in the face of extreme cold.

Renewable Cumulative Generation Capacity, GW

Building on its existing wind and solar portfolio, Texas expects another 35 GW of wind and solar generation capacity to come online in the next few years according to ERCOT data and projections as of February 2021 (refer to figure above). Costs have plummeted in the past decade, attributable to some extent to pioneering states such as Texas that have adopted renewable resources at a large scale. In order to bolster grid resilience as more intermittent resources gain market share, investors and developers may explore the viability of winterization measures. In cold climates — including Scandinavian nations and New England states such as Maine — the average additional capital expenditure for winterization is approximately five percent. However, there is somewhat of a distinction: the winter storm of February did not halt wind production due to cold temperatures but rather ice, and winterizing to mitigate the effects of ice would not necessarily mirror winterizing practices to mitigate the effects of cold temperatures. Nonetheless, the ballpark amount of capital needed to safeguard against extreme weather may become more integrated in the investment and planning processes going forward in Texas.


1 Report on Outages and Curtailments During the Southwest Cold Weather Event of February 1-5, 2011: Causes and Recommendations. FERC and NERC, August 2011. pg. 8, available at:
2 Id. at pg. 10.
3 Review of February 2021 Extreme Cold Weather Event – ERCOT Presentation. February 24, 2021. Available at:
4 February 18, 2021 Virtual Open Meeting. FERC, February 2021. pg. 7, official transcript available at:
5 Review of February 2021 Extreme Cold Weather Event – ERCOT Presentation. February 24, 2021. Available at:

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