Published: November 8, 2024
By Concentric Staff Writer
After over-riding its membership, on November 4, the national organization responsible for the reliability of the bulk power grid filed with federal energy regulators a suite of proposed new standards for inverter-based resources (IBRs) such as solar, batteries, and wind, to address problems with these systems in recent years.
On November 4, the North American Electric Reliability Corporation (NERC) made four separate filings to the Federal Energy Regulatory Commission (FERC) related to IBRs. NERC filed a petition for approval of two standards related to IBR ride-through performance during system disturbances (PRC-024-4, PRC 029-1); another requiring analysis and mitigation of IBR performance issues (PRC 030-1); a petition for approval of the proposed definition of the new term “Inverter-Based Resource”; and another establishing requirements of disturbance monitoring requirements for IBRs (PRC-028-1 and PRC-002-5).
“The proposed reliability standards are an integral part of NERC’s proposed framework to address IBR performance issues in a comprehensive and holistic manner,” the organization said in the filing for disturbance monitoring requirements for IBRs. “[T]he proposed reliability standards are part of a set of standards that collectively respond to the Commission’s directives for requirements addressing IBR ride-through settings, ride-through performance, data recording, and analysis and mitigation of unexpected IBR performance,” NERC said.
NERC said there has been widespread loss of generating resources—solar photovoltaic, wind, synchronous generation, and battery storage—across multiple “system events.” For example, the Blue Cut Fire in August 2016 in San Bernardino County, California, and the Canyon 2 Fire in October 2017 in Orange County, California, demonstrated a risk to grid reliability as IBRs were unable to ride-through the events. In 2022, NERC analyzed more than 10 grid disturbances involving widespread loss of IBRs, it said.
FERC in its Order No. 901 [RM22-12], approved in October 2023, had required NERC to file the IBR standards by Nov. 4 of this year. After disagreement among members, the NERC Board of Trustees in October invoked the special authority in order to allow the organization to meet the deadline, it said.
That lack of consensus led a NERC committee during an earlier August meeting to recommend that the board invoke its special authority “to ensure that systemic reliability issues associated with IBRs are addressed in a timely manner,” according to NERC documents.
In the Western Interconnection — the power grid that spans several western U.S. states, Canada, and parts of Mexico —IBRs are on the upswing, but they have introduced a number of challenges to reliability. IBRs lack the physical inertia that is inherent to traditional synchronous resources such as coal, gas, and nuclear, creating problems such as fault-induced delayed voltage recovery. IBRs also have trouble with the frequency response that traditional generation provides to the grid.
NERC’s Board of Trustees at an October 8 technical conference successfully revised the IBR standard, allowing it to be approved under a reduced voting threshold compared to its normal voting procedures. At an August meeting in Vancouver, NERC membership was unable to reach consensus on how stringent the standards should be.
FERC’s Order No. 901 required NERC to file the standards on a three-year staggered time frame. The commission required NERC to file IBR disturbance-monitoring data sharing, post-event performance validation, and ride-through performance requirements by November 4, 2024; IBR data and model validation by November 4, 2025; and planning and operational studies for IBRs by November 4, 2026. The Commission also directed NERC to develop and submit a work plan to develop new and revised reliability standards to address the IBR issues in accordance with that timeframe.
According to minutes from the October 8 NERC technical conference, Board of Trustees member Kenneth DeFontes recommended that the board use the special authority in order to file the standards in compliance with FERC’s November 4 deadline.
“[DeFontes] reported that while much of the hard work of NERC’s stakeholders is paying off, with progress made on important IBR reliability standards through the usual standard development process, NERC does not have a clear path forward on the IBR grid disturbance ride through standard,” the minutes say.
DeFontes said the board must consider its options to meet its regulatory responsibilities but noted that the board “does not consider these options lightly.” He also recommended continued participation by NERC members and industry representatives on the standard.
The board approved a package of Milestone 2 standards for IBR “ride-through,” which refers to the capability of solar, wind, and battery devices to continue operating during temporary disturbances or faults on the electrical grid. Inverters will ride-through the disturbance and remain connected to the grid instead of disconnecting immediately when voltage or frequency deviates from normal ranges.
The Milestone 2 standards were approved under NERC’s Project 2020-02, an initiative to develop and update standards for IBRs. NERC had identified that there was a gap in existing reliability standards, which were developed for traditional synchronous generation resources such as coal, gas, and nuclear.
The goals of Project 2020-02 are to update existing standards such as protection and controls, modeling, data, and analysis to make them more suitable for IBRs. These include requirements for more accurate modeling, performance verification, and coordination of protection systems. The initiative also has the goal of defining and enhancing ride-through requirements to establish clear and consistent requirements for IBRs to ride through system disturbances without tripping off.
NERC also has the goal of ensuring an accurate representation of IBRs in grid models, seen as critical for planning and analysis of operational reliability. This includes requirements for verifying that IBR models reflect their performance in the real world.
NERC’s Project 2020-02 included modifications to the PRC-024-4 standard and the development of the PRC-029-1 standard to initiate its development (frequency and voltage ride-through requirements for inverter-based resources), but the latter standard failed to achieve consensus through the usual standard-development process, NERC said.
The NERC board discussed issues surrounding the FERC Order No. 901 directives, including whether or not the proposed reliability standard PRC-029-1 is “just, reasonable, not unduly discriminatory or preferential, in the public interest, helpful to reliability, practical, technically sound, technically feasible, and cost-justified,” according to a NERC memorandum.
On Jan. 17, NERC also submitted its Order No. 901 work plan, which consists of key milestones to meet the FERC directives by the filing deadlines. The Milestone 2 standards, in progress, focus on the development of reliability standards to address disturbance monitoring, performance-based ride-through requirements, and post-event performance validation for registered IBRs by the Nov. 4 deadline.
While Project 2020-02, which addressed generator ride-through directives from FERC Order No. 901 had created controversy, Projects 2021-04 and 2023-02 are on track for timely completion through the usual NERC standard development process, the memorandum says.
FERC’s Order No. 901 cited multiple reports of events with IBRs as the reason NERC should have reliability standards for ride-through frequency and voltage system disturbances. The standards should permit tripping of IBRs only to protect the IBR equipment in scenarios similar to when synchronous generation resources use tripping as protection from internal faults, FERC said. Exceptions should be applied to certain IBRs, and finding consensus around those directives was a part of the main issues addressed during the technical conference, according to NERC.
FERC said NERC must require registered IBRs to continue to perform frequency support during any bulk-power system disturbance and that any new or modified reliability standard must also require registered IBR generator owners and operators to prohibit momentary cessation in the no-trip zone during disturbances.
Under FERC’s order, NERC was required to submit new or modified reliability standards that establish IBR performance requirements, including requirements addressing frequency and voltage ride-through, post-disturbance ramp rates, phase lock loop synchronization, and other known causes of IBR tripping or momentary cessation.
“Therefore, we direct NERC through its standard development process to determine whether the new or modified reliability standards should provide for a limited and documented exemption for certain registered IBRs from voltage ride-through performance requirements. Any such exemption should be only for voltage ride-through performance for those existing IBRs that are unable to modify their coordinated protection and control settings to meet the requirements without physical modification of the IBRs’ equipment,” FERC said in the order.
During deliberations among NERC members, many argued that the proposed PRC-029-1 definition was too broad and ambiguous, particularly the inclusion of phrases like “entire” and “in its entirety,” when referring to a generating plant or facility. Those parties recommended revisions to clarify the definition and ensure it aligns better with Institute of Electrical and Electronics Engineers Standard 2800, which covers interconnection and interoperability of IBRs, and interconnection with associated transmission systems.
Project 2020-02 will enhance reliability by requiring entities to perform energy reliability assessments to evaluate energy assurance and develop corrective action plans to address identified risks, NERC said. These energy reliability assessments should evaluate energy assurance across operations planning, near-term transmission planning, and long-term transmission planning or equivalent time horizons by analyzing the expected resource mix availability and flexibility and the expected availability of fuel during the study period.
According to NERC, IBRs are still being designed and installed without setting their protection and controls in accordance with their physical capabilities.
NERC had solicited comments from the industry as well as original equipment manufacturers on any information on hardware-based limitations that would prevent IBRs from meeting the proposed frequency criteria within PRC-029-1. The organization said 21 individual comments were received, including six from different original equipment manufacturers of IBRs. There were concerns that a draft of PRC 029-1 proposed frequency criteria that went beyond those established in IEEE 2800-2022 and there was a concern that IBR operators would not be able to meet those proposed frequency criteria, as IBR capability limits were hardware-based and inherent to manufacturer design.
Though the organization had failed to reach consensus among its members on some of the standards, the filing of NERC’s new standards will hopefully address the issues with IBRs that have raised their head in the Western Interconnection in recent years.
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All views expressed by the contributors are solely the contributors’ current views and do not reflect the views of Concentric Energy Advisors, Inc., its affiliates, subsidiaries, or related companies. The contributors’ views are based upon information the contributors consider reliable at the time of publication. However, neither Concentric Energy Advisors, Inc., nor its affiliates, subsidiaries, and related companies warrant the information’s completeness or accuracy, and it should not be relied upon as such.
Published: August 9, 2024
By: Concentric Staff Writer
Extreme weather has developed into the primary reliability threat to the Bulk Power System (BPS), although there were minimal severe weather threats to the grid last year, national reliability officials say.
Other than severe weather, other reliability threats pointed out by the North American Electric Reliability Corporation (NERC) are increased demand, problems with inverter-based resources (IBRs) such as solar and wind, and a rise in forced-outage rates for generation resources.
NERC recently issued a set of “actionable recommendations” from workshops held in March 2024 in conjunction with the National Academy of Engineering regarding electric reliability criteria for planning resource and transmission adequacy. Resource and transmission planning will be increasingly important as the grid transforms to cleaner, but more intermittent, renewable generation, the organization said.
NERC said there is a need for additional criteria, actionable short- and long-term recommendations, and next steps. The workshop concentrated on two broad topics: capacity vs. energy and planning the evolving transmission grid, the organization said in a report, entitled Evolving Planning Criteria for a Sustainable Power Grid.
Planning needs to evolve past the traditional loss-of-load standard of one day in ten years, which focuses on peak load, because this approach does not account for the growing risk in all hours that results from the increased variability and uncertainty caused by renewable generation, as well as increasing demand levels, NERC said.
NERC suggested that other methods, such as the Regional Energy Shortfall Threshold (REST), are being explored by the Independent System Operator New England, which reflects the region’s risk tolerance in regard to energy shortfalls during extreme weather. This is particularly relevant during extreme weather when impacted areas are highly reliant on long-distance transfers from other areas that have greater fuel diversity and sufficient resources to serve demand, NERC said.
The organization said extreme weather events are disrupting electricity supplies at “unacceptable levels,” citing the 2020 heat dome in California and Mexico, Winter Storm Uri in 2021, and Winter Storm Elliott in 2022.
“Given that electricity plays an essential role in modern society, energy adequacy is a critical complementary consideration of resource adequacy to ensure overall system reliability,” NERC said in the report.
A major factor affecting reliability is the growth of data centers and cryptocurrency mining, which NERC said can have a significant effect on demand and resource projections as well as system operation. Cryptocurrency mining refers to the way cryptocurrency coins are created and how transactions are verified. The process involves blockchain and a decentralized ledger to verify that a sender has adequate funds and is not “double-spending” coins. Cryptocurrency mining requires solving complex mathematical puzzles and is designed to require substantial computational effort, which increases as more miners join the network. Miners need to run their computers 24-7, creating massive energy demand.
The Electric Reliability Council of Texas (ERCOT), for instance, has a huge number of interconnection requests from cryptocurrency miners, with nine gigawatts (GW) worth of approved planning studies and 41 GW of studies currently requested, NERC said in its 2023 Long-Term Reliability Assessment.
“This new category of large flexible loads is leading some areas to update load forecasting methods to capture the flexibility and price-responsiveness of cryptocurrency mining operations,” NERC said in the assessment. “In anticipation of further growth in large flexible loads, ERCOT and its stakeholders are assessing further operational issues that could emerge, such as the effect on system frequency of sudden changes in large flexible loads.”
In another report, the 2024 State of Reliability Overview, NERC noted that the Texas Interconnection has improved greatly in reliability by using battery energy storage to support system frequency. Texas can no longer meet summer and winter peak demand with only conventional generation “and has demonstrated how these challenges can be successfully managed while at the same time encountering new ones.”
California has been adding an unprecedented amount of energy storage to its grid, helping it to meet peak summer demand. The California Independent System Operator said that the amount of energy storage is approaching 10 GW, which has helped it manage the grid this summer.
Coal unit retirements and the impact of IBRs such as solar and wind continue to impact the BPS; for example, disturbances to battery energy storage in California (March and April 2022) and solar in Utah (April 2023). Disturbances in IBRs are no longer limited to solar generation, the organization said in the State of Reliability Overview.
As a result, the Federal Energy Regulatory Commission in October 2023 directed NERC to develop new reliability standards for IBRs, saying they will help the reliability of the grid by accommodating the rapid growth in solar photovoltaic, wind, fuel cell, and battery storage that is due to form a large proportion of new generation resources coming online over the next 10 years.
“Over the past several years, a handful of extreme weather events has increasingly been the largest challenge to BPS reliability, and the unprecedented magnitude of these events has dominated reliability trends,” NERC said in the State of Reliability Overview.
However, in 2023, the weather was less extreme, although there were still incidents such as flooding in California in January through March, winter storms and cold waves in the Northeast in February, Hurricane Idalia on the Gulf Coast in March, as well as tornadoes, heat storms and drought in various regions of the county. There were also record-setting wildfires in Canada that caused short-term outages on the transmission system.
Overall, Severity Risk Index days decreased in 2023, illustrating the ability of the BPS to withstand severe weather and the importance of advanced preparation, active management of the grid during extreme weather, and rapid response to events, NERC said.
Forced outages of generation units on the U.S. grid were at historic highs in 2023, exceeding rates for all years prior to 2021. Forced outages refer to unexpected events that disrupt the normal output of the unit, such as failures due to mechanical, electrical, or control systems, as well as natural events.
Despite no occurrence of major events comparable to Winter Storms Uri (February 2021) or Elliott (December 2022), the weighted equivalent of forced-outage rates for coal and cycled natural gas units remained high in 2023, NERC said. Forced-outage rates for hydroelectric units were also high, but this generation remains a much smaller portion of the fleet. NERC found that the decreasing reliability of coal generation, along with an increase in variable generation, will necessitate larger reserve margins going forward.
There is a correlation between the forced-outage rates for coal generation and the overall forced-outage rate for all types of generation, NERC said. The correlation includes the age of coal units and their outage rates, but the outage rate for coal units is affected more by an increase in needed maintenance and a reduction in service hours as these units age and face retirement. As coal units retire, they are increasingly being replaced by IBRs such as solar, NERC said.
Forced outages also continue to increase for wind generation, rising to 18.9 percent in 2023, compared with 18.1 percent in 2022, NERC said. While there is not an exact comparison to outage rates for conventional generation units, “the continued increase is of concern given the growth in wind generation over recent years,” the report says. New, expanded reporting requirements for both conventional and renewable generation went into effect in 2024, which will allow for expanded analysis of the performance of both IBRs and conventional generation in future years, NERC said.
Other emerging issues for the grid include the state of blackstart resources—specialized power plants that can start without any external electricity supply—that are critical in cases of outages. They often use auxiliary power sources such as batteries or diesel generation. Recent extreme winter weather events have exposed vulnerability to generating units and fuel sources that are not adapted to low temperatures, which raises issues regarding blackstart unit readiness, NERC said.
“The changing resource mix is cause for additional awareness of blackstart capabilities. Currently, few IBRs on the system are capable of grid forming control, one of the necessary components for blackstart resources”, NERC said in the Long-Term Reliability Assessment.
Another rising problem is that distribution transformers are in short supply nationally, with manufacturers unable to keep up with demand. Lead times for transformers are often longer than two years, and low inventories of replacement resources and lack of skilled labor have the potential to slow restoration efforts following hurricanes and other severe weather events. Access to grain-oriented electrical steel used in power transformers is another constraint, and new efficiency standards for distribution transformers proposed by the U.S. Department of Energy could worsen the challenges because they set up requirements that manufacturers are not set up to handle, NERC said.
Finally, local load growth is occurring, including industrial and commercial development, which includes data centers, smelters, manufacturing centers, hydrogen electrolyzers, and port electrification. New load being added to the system, such as data centers, require more heating and cooling than other commercial buildings, creating challenges in load forecasting and localized transmission development, NERC said.
The NERC reports provide a window into the challenges facing the grid, including weather, growing load, and other factors that ensure grid planners will have their hands full in meeting demand in coming years.
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All views expressed by the author are solely the author’s current views and do not reflect the views of Concentric Energy Advisors, Inc., its affiliates, subsidiaries, related companies, or clients. The author’s views are based upon information the author considers reliable at the time of publication. However, neither Concentric Energy Advisors, Inc., nor its affiliates, subsidiaries, and related companies warrant the information’s completeness or accuracy, and it should not be relied upon as such.
Published: February 27, 2024
By: Concentric Staff Writer
National reliability officials recommended a study of whether additional natural gas infrastructure, including new interstate pipelines and storage, is needed to maintain electric grid reliability in severe cold, among the lessons learned from Winter Storm Elliott that occurred in December 2022.
The study of additional infrastructure to support natural gas local distribution companies (LDC) was among the recommendations in the Joint Report on Winter Storm Elliott, which analyzed the severe cold weather event that took 1,700 generation units offline in the Eastern Interconnection. The report was jointly issued by the North American Electric Reliability Corporation (NERC), an industry-based group responsible for creating and enforcing national reliability standards, and the Federal Energy Regulatory Commission (FERC), an agency tasked with enabling reliable, safe, and economic energy service for U.S. consumers.
The NERC/FERC report recommends that an independent research group, such as national laboratories from the U.S. Department of Energy, should study possible infrastructure build-out as well as the associated costs.
“The purpose of the study would be to identify additional natural gas infrastructure needs, if any, needed to ensure the continued reliability of the electric and natural gas systems, and the preferred locations of such infrastructure, if applicable, including pipeline infrastructure, natural gas storage, and other supporting systems,” the report says. The study should also consider the needs in light of coincident peaks of LDC demand for natural gas for heating, as well as for demand from natural gas-fired power plants during long periods of abnormally cold weather, officials said.
“The study should analyze needs on a regional basis and consider current as well as forecast future needs, in light of our evolving and interdependent energy,” the report says. It should also look at whether there will be adequate natural gas infrastructure to accommodate the intermittence of new renewable energy resources and retirement of thermal generation resources, as well as recent patterns of natural gas production declines during severe weather events.
Other recommendations in the joint report include “prompt development and implementation” of revisions to reliability standards to strengthen generators’ performance during extreme cold weather; identification of generation units that are at the highest risk of problems in cold weather; assessments of freeze protection measure vulnerability; and engineering design reviews of units that have experienced cold weather outages. Also recommended is the identification of root causes of generation failures and a NERC/FERC study of the overall availability of “black-start” resources—units that can return to service quickly after a complete or partial shut-down.
Winter Storm Elliott, which plunged 18 percent of the Eastern Interconnection into outages, was just one of a series of major cold weather outages that struck the U.S. in recent years. While Elliott was the largest load shedding event in the Eastern Interconnection, the largest single such event was Winter Storm Uri in February 2021, which caused 20 gigawatts (GW) of load shedding by grid operators, mainly in Texas, and took out power for 4.5 million people, causing hundreds of deaths.
But the joint FERC/NERC report on Winter Storm Elliott points out that the situation in Texas during Winter Storm Uri and nearly a year later in the East during Elliott involved very different grids. What is more surprising is that the Winter Storm Elliott outages occurred in the highly connected Eastern Interconnection, unlike Texas, which has a grid almost completely isolated from both the Eastern Interconnection and Western Interconnection.1
“The quantity of firm load shed during Winter Storm Elliott was not as large as in the Winter Storm Uri event, but it is especially disconcerting that it happened in the Eastern Interconnection which normally has ample generation and transmission ties to other grid operators that allow them to import and export power,” the report says.
Winter Storm Elliott was characterized as both a bomb cyclone and an extra-tropical cyclone, moving from Upper Plains states in late December 2022, and hitting the East Coast on December 23 and 24. The cold and outages coincided with a spike in electricity usage causing many balancing areas in the East to declare energy emergencies (EEA). The 90.5 GW of unplanned outages stretched from Georgia to the Canadian border in the East and across the central U.S.
Similar to Uri, Elliott froze up natural gas system wellheads and other equipment, while the weather made maintenance and response impossible, leading to significant declines in natural gas production. There were reductions in gas pipeline pressure and 14 declarations of force majeure—unforeseen events that affect shippers’ ability to deliver gas on pipelines. Eight of 15 interstate pipelines queried for the report said there were 53 instances of power loss at facilities, totaling almost 467 hours. Outages averaged a few hours, although some went on for several days.
In the Northeast, pipeline operators reduced flows to other regions during Elliott and increased imports from Canada, while in the Southeast they increased outflows to the Midwest, decreased liquified natural gas (LNG) exports, and saw access to Northeast supply throttled. The Northeast in recent years has increased its production of natural gas, which normally leads to typical outflows of about 12.5 billion cubic feet per day (Bcf/d), but which were reduced to about 5.3 Bcf/d.
There were also some close calls. On the morning of December 24, Con Edison began experiencing drops in pipeline pressure and declared a gas system emergency, which included implementing specifications for curtailing users and reactivating an LNG regasification plant. Con Edison was in danger of cutting off some or all of its system users; even an outage of about 130,000 customers would have taken five to seven weeks to restore depending on the availability of mutual aid.
“Had it lost the majority of its system, over a million customers in New York City and nearby areas would have been unable to heat their apartments and houses while the outside temperature was in the single digits, for months,” the joint report says.
Outages at generation units are divided into broad categories in the report, including mechanical and electrical issues such as equipment failures, which formed 72 percent of these problems, and control system issues, which accounted for 12 percent. No other single sub-cause materially contributed to lost generation, the report says. Generators lost power as the coldness increased, including situations where generator gas or oil temperature became too low, metal components shrank, and oil viscosity in wind generators increased. The report notes that “a substantial majority” of generation units that reported freezing issues were operating at temperatures that were above the documented operating temperature requirements.
On December 24, 2022, gas production in the lower 48 states dropped to a low of 82.5 Bcf/d, a 16 percent decrease from December 21. The greatest declines in gas production were in the Marcellus and Utica shale formations. Generation outages began in the territory of the Southwest Power Pool (SPP) and MidContinent Independent System Operator (MISO). Neither regional transmission organization had to shed load, but SPP twice curtailed non-firm exports on December 23 because of lower reserves, and MISO and SPP began coordinating on regional directional transfer limits.
MISO declared an EEA 1 and EEA 2 on December 23. Tennessee Valley Authority (TVA) saw a rapid increase in generation unit outages early on December 23 and had lost 5 GW of generation by 6 a.m., causing it to declare EEA 1 and EEA 2. TVA began obtaining emergency power from Duke Energy, Southern Company, the PJM Interconnection, and MISO, but “this solution was short-lived,” the report says. These factors caused TVA to order firm load shed of 1,500 MW, about 5 percent of its system peak load.
Impacts on grid reliability due to cold weather are nothing new, and NERC has repeatedly warned of the risk. For instance, NERC and FERC in August 2011 issued a detailed joint analysis of an outage in Texas in February of that year that affected 1.3 million customer accounts, the “2011 Southwest Cold Weather Event.” 2 In an event similar to Winter Storm Uri that would occur a decade later, more than 4.4 million customer accounts were affected between February 2 and February 4, 2011, an event that also saw extreme natural gas delivery curtailments that were longer than electric customer outages because gas-fired equipment had to be relit.
More than 50,000 gas customers were affected in the 2011 outage, including more than 30,000 in New Mexico, along with customers in Arizona and Texas. That year, FERC and NERC launched a joint task force to inquire about the outages.
NERC and FERC listed capacity awareness, gas and electricity interdependency, transformer oil issues during cold weather, air duct icing, wind farm winter storm issues, rotational load shed, transmission facilities, and other factors as “lessons learned” from the 2011 Southwest Cold Weather Event.
In the joint NERC/FERC report issued in August of 2011, recommendations included that balancing authorities, reliability coordinators, transmission operators and generation owners and operators, in Texas and the Southwest view preparedness for winter as important as preparing for summer.
“The large number of generating units that failed to start, tripped offline, or had to be derated during the February event demonstrates that the generators did not adequately anticipate the full impact of the extended cold weather and high winds,” NERC and FERC said in the 2011 report. “While plant personnel and system operators, in the main, performed admirably during the event, more thorough preparation for cold weather could have prevented many of the weather-related outages.”
In a July 2013 report on previous cold weather events stretching back to 1983, NERC described six previous cold weather events in 1983, 1989, 2003, 2006, 2008, and 2010. There were also five cold weather experiences that caused operational challenges in February 1989, January 1994, January 2004, February 2006, and January 2007.
NERC and FERC said there were only three events that were comparable to the February 2011 Cold Weather Event in terms of load loss and generation outages. Those occurred in December 1983, December 1989, and January 1994.
In all the above events, however, there were two common themes observed: constraints on natural gas supply to power plants as well as generating unit trip-offs, derates, or failures to start due to cold weather due to problems like frozen sensing lines.
The first time ERCOT implemented load shedding region-wide was on December 21–24, 1989, when the grid operator shed 1.7 GW of firm customer load and curtailed natural gas supplies to generation units. The demand peak that occurred on December 22, 1989 was 12.4 percent above what was forecast. The temperatures during the 1989 cold weather event were the lowest in more than 100 years.
During those same days in December 1989, Florida also experienced extremely cold weather, which led to the curtailment of natural gas supplies. Record load of 34.7 GW due to the cold, combined with numerous generation units that were offline for maintenance, resulted in rolling blackouts of five to eight hours maximum. In both Texas and Florida, “the circumstances, size, geographic area, and impact on the bulk power system (BPS) of this event were deemed to be very similar to the February 2011 Cold Weather Event.,” NERC said.
NERC identified several familiar issues regarding the two incidents, including inadequate cold weather preparation, frozen ancillary plant equipment, fuel oil problems, and natural gas delivery curtailments. There were “numerous recommendations” for utilities in Florida and Texas, and certain corrective actions were undertaken by utilities.
NERC in the 2013 report said that common issues in the cold weather include the interdependence of the natural gas and electric systems, which continues to grow. Compressors used in the production and transportation of natural gas require electricity to operate.
Also, most generators purchase “non-firm” capacity, exposing them more to curtailments when supplies are tight, and there is competition between natural gas supply for electricity and natural gas for heating.
The cold weather outages that have struck the U.S. over the years have led to the development of cold weather reliability standards, which were issued by FERC in February 2023. The standards were developed from recommendations flowing from the joint inquiry into Winter Storm Uri to prevent such widespread outages from occurring again. NERC proposed the standards in October 2022, which include generator freeze-up protection measures, enhanced cold-weather preparedness plans, identification of freeze-sensitive equipment in generators, corrective actions for equipment freeze-ups, annual training for generator maintenance and operations personnel, and procedures to improve the coordination of load reduction measures during a grid emergency.
The FERC order implemented about half of the recommendations from the Winter Storm Uri FERC/NERC joint inquiry, and NERC is developing a second phase of the standards.
Though overall usage of natural gas for power generation might decline because of the transition to renewable energy such as solar and wind, the necessity of gas to balance the system against intermittent renewables could increase, the American Gas Association (AGA) said in a 2021 report entitled “How the Gas System Contributes to US Energy System Resilience.” But the current compensation model for gas is tied to the volume of gas delivered to power plants, which creates a disconnect between the value of the service and its compensation.
Natural gas infrastructure and replacement programs were designed to enhance reliability and safety, and have also contributed to “resilience,” defined as “as a system’s ability to prevent, withstand, adapt to, and quickly recover from system damage or operational disruption. Resilience is defined in relation to a high-impact, low-likelihood events.” The most common events that require a resilient grid are extreme weather events, the AGA report says.
The resilience needed to meet these challenges will be accomplished “through a diverse set of integrated assets,” the report says, adding that policies need to focus on optimizing the characteristics of both the electric and gas systems.
“Ensuring future energy system resilience will require a careful assessment and recognition of the contributions provided by the gas system,” the report says. “Utilities, system operators, regulators, and policymakers need new frameworks to consider resilience impacts to ensure that resilience is not overlooked or jeopardized in the pursuit to achieve decarbonization goals.”
Aside from the need for more natural gas system infrastructure for energy grid reliability and resilience, new pipelines are under construction to transport gas for export. There is more than 20 million Bcf/d of natural gas pipeline capacity under construction, partly completed or already approved to deliver gas to five liquefied natural gas export terminals that are under construction on the Gulf Coast, according to the U.S. Energy Information Administration.
FERC recently recognized the need to expand the natural gas system, approving in October a request by Gas Transmission Northwest LLC (GTN) to build and modify gas compressor facilities in Idaho, Washington, and Oregon (CP22-2).
“The proposed project will enable GTN to provide up to 150,000 [dekatherms per day] of firm transportation service on its existing system for delivery into Idaho and Pacific Northwest markets. We find that GTN has demonstrated a need for the GTN Xpress Project, that the project will not have adverse economic impacts on existing shippers or other pipelines and their existing customers, and that the project’s benefits will outweigh any adverse economic effects on landowners and surrounding communities,” FERC said in the order.
Another topic that has arisen in the wake of the outages is the need for reliability standards for the gas system, similar to what is in place for the electric system.
When FERC and NERC issued the final report on Winter Storm Elliott, FERC Chairman Willie Phillips in a written statement said: “I want everyone to take time during this Reliability Week to read this report and begin implementing these recommendations, particularly those addressing the interdependence of gas and electricity. The report highlights what I’ve called for before: Someone must have authority to establish and enforce gas reliability standards.”
NERC President and Chief Executive Officer Jim Robb said that the industry needs to implement the recommendations from the joint report as soon as possible.
“I echo the Chairman’s call for an authority to set and enforce winterization standards for the natural gas system upstream of power generation and local distribution,” Robb said in a written statement. “The unplanned loss of generation due to freezing and fuel issues was unprecedented, reflecting the extraordinary interconnectedness of the gas and electric systems and their combined vulnerability to extreme weather.”
1The three main components of the U.S. electric grid are the Eastern Interconnection, the Western Interconnection, and ERCOT.
2 Also referred to as the “February 2011 Cold Weather Event.”
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All views expressed by the author are solely the author’s current views and do not reflect the views of Concentric Energy Advisors, Inc., its affiliates, subsidiaries, related companies, or clients. The author’s views are based upon information the author considers reliable at the time of publication. However, neither Concentric Energy Advisors, Inc., nor its affiliates, subsidiaries, and related companies warrant the information’s completeness or accuracy, and it should not be relied upon as such.