On February 20, 2025, the Federal Energy Regulatory Commission (“FERC”) issued a highly anticipated order under Section 206 of the Federal Power Act addressing concerns related to large loads co-located at generating facilities within the PJM Interconnection. The growing interest in co-location arrangements, particularly involving data centers and industrial facilities, has raised questions about how interconnected generators should serve these co-located loads when they are physically connected to an existing or planned generator on the generator side of the point of interconnection. These arrangements have introduced issues around potential cross-subsidization, cost shifting, grid reliability, resource adequacy, and jurisdictional boundaries.
In this show-cause order (“Order”), FERC found PJM’s Tariff to be potentially unjust, unreasonable, unduly discriminatory, or preferential for lacking explicit provisions on co-location arrangements. The Order highlighted several key issues:
1. Jurisdictional Debate:
Co-located arrangements introduce jurisdictional questions. Some stakeholders have argued that FERC’s jurisdiction should be limited to interstate wholesale transactions and that states should retain control over retail sales and behind-the-meter arrangements. Others argue that load served directly by a generator is analogous to behind-the-meter generation and is exempt from FERC oversight. PJM and others maintain that co-located loads still benefit from grid services and should thus fall under FERC’s oversight when those services affect wholesale rates and grid reliability.
2. Cost Allocation and Grid Services:
A significant concern is whether co-located loads can fully isolate from the electric grid and avoid paying their share of costs for transmission services and for ancillary services from PJM. PJM and its market monitor have argued that co-located loads should be treated like other grid-connected loads and should pay for network services, ancillary services, and capacity. Other stakeholders have countered that since co-located loads can fully isolate and not draw power from the grid, they should not incur transmission service charges.
3. Reliability and Resource Adequacy:
Several parties have highlighted potential risks that co-located loads might impose on grid stability, particularly when large loads bypass the traditional planning process. For example, sudden shifts in demand or the loss of a co-located generator could compromise grid stability. PJM emphasized that the rapid growth of such loads could strain existing capacity reserves and suggested that planning frameworks need adjustments to incorporate these arrangements effectively. However, proponents of co-located load arrangements have argued that such configurations can offer benefits like reducing grid congestion, easing interconnection backlogs, and energizing data centers more quickly.
In the Order, FERC directed PJM and the Transmission Owners to provide justifications for the current tariff or suggest changes within 30 days. These justifications must address concerns related to jurisdiction, cost allocation, reliability, and potential discriminatory practices. FERC requested answers to approximately 40 questions related to jurisdictional principles, the type of transmission service used under various configurations, cost allocation, and the impacts on the wholesale market and ancillary services.
Concentric Energy Advisors’ Wholesale Energy Markets practice helps utilities, independent power producers, and government entities shape and understand wholesale electric market design and operational issues. Contact Danielle Powers, Chief Executive Officer, at dpowers@ceadvisors.com or 508.263.6219 to learn more about our services.
— 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.
By: Concentric Staff Writer
Published: November 9, 2023
The International Energy Agency (IEA) is exploring different scenarios to reach global targets for greenhouse-gas emission reductions, performing detailed new research on the unprecedented level of build-out and investment that would be needed.
Larger, more robust, and smarter electric grids will be needed worldwide to transition modern societies to clean energy from fossil fuels, but the pace of growth needs to accelerate substantially, according to the new IEA report. The importance of electricity grids is growing, with major transitions happening, such as renewable energy, electric vehicles (EVs), and electric heating, IEA said in the report, “Electricity Grids and Secure Energy Transitions.” The report is meant to take stock of the world’s grids as they now stand and assess any signs that grids are not keeping pace with the new global energy economy, as well as analyze scenarios to meet zero emissions. There is a danger that grids will be bottlenecks to future efforts to move to clean energy and create energy security, the researchers said.
“Clean energy transitions are now driving the transformation of our energy systems and expanding the role of electricity across economies. As a result, countries’ transitions to net zero emissions need to be underpinned by bigger, stronger and smarter grids,” IEA said in an executive summary.
To achieve the energy and climate goals of various countries to be zero-greenhouse gas emitters, electricity usage worldwide must grow at a 20-percent faster rate than now, the report says. Expanded grids will be needed to deploy more EVs, and electric heating and cooling systems to scale up new technologies such as hydrogen production using electrolysis. A total of 80 million kilometers of grid infrastructure, the equivalent of the entire existing world-wide grid, must be added or refurbished to meet climate goals.
In an “announced pledges” scenario in which countries’ national energy and climate goals are met on time and in full, wind and solar must account for 80 percent of the total increase in global power capacity over the next 20 years, compared with less than 40 percent that has been added over the last 20 years, the report says. In IEA’s Net Zero Emissions by 2050 Scenario, wind and solar account for up to 90 percent of the global power supply increase.
“The acceleration of renewable energy deployment calls for modernizing distribution grids and establishing new transmission corridors to connect renewable resources – such as solar [photovoltaic] projects in the desert and offshore wind turbines out at sea – that are far from demand centers like cities and industrial areas,” the report says.
One pressing need is interconnection reform, as about 3,000 GW of renewable power projects—about half of which are in the advanced planning stages—are waiting in grid interconnection queues. This is equivalent to five times the amount of solar photovoltaic and wind capacity that was added globally last year, IEA said. Investment in renewables has nearly doubled since 2010, but global investments in grids themselves have remained at about $300 billion per year.
Delays in grid investment and refurbishment would substantially increase carbon dioxide emissions, leading IEA to develop a “grid delay case” in its research to explore what would happen if there were more limited investment, modernization, digitization, and operational changes.
Regulation of electric grids needs to be reviewed and updated so it supports not only new grids but improving current ones, and incentives should be put in place so grids keep pace with rapidly changing supply and demand, the report says. This means removing administrative barriers, rewarding good performance and reliability, and spurring innovation. Assessments of regulatory risk also need to improve “to enable accelerated buildout and efficient use of infrastructure.”
The 130-page report is divided into four chapters: “state of play,” “regulation and policy,” “identifying the gap,” and “policy recommendations.”
The “state of play” chapter notes that electricity grids have grown steadily over the past 50 years at a rate of about 1 million kilometers (km) per year, overwhelmingly in lower-voltage distribution networks, rather than higher-voltage transmission networks. More recently, there have been challenges in integrating renewable energy resources. Advanced economies are seeing investment but also long lead times for high-voltage transmission development, which signals that there are challenges to completing needed development. Investment has also been falling off in recent years with supply chain slowdowns even as demand and population grow, creating more risks for grid build-out. Grids play a central role in energy security, but grid congestion and delays in connecting renewable projects, including the supply chain issues caused by factors such as the COVID-19 pandemic and the war in Ukraine, are also causing impacts. For example, wait times for 50-MVA power transformers grew from a typical 11 months to more than 19 months due to materials and labor shortages, the report says.
“In short, we find evidence of multiple challenges that will need to be addressed to deliver the grids of the future,” IEA said.
Most grids are alternating current (AC), which has historically been composed of rotating generators such as thermal and hydroelectric plants, while new renewable resources connect to the grid mainly through electrical inverters. AC grids are popular because they are adept at changing voltage using long-distance transmission, which minimizes losses and allows transformers to be used to shift to lower voltages for local or regional distribution grids serving residential, commercial, and industrial customers.
However, direct current (DC) grids have certain advantages, such as in occasions when undersea cables are preferable and are used to serve multiple wind farms or markets, or cross-border interconnections and long-distance transmission from large hydro facilities are needed to reach demand centers. DC also offers grid stability and black-start capabilities.
Emerging markets and developing economies have built about 1.2 million kilometers of new transmission lines due to growing demand and access to electricity. Renewable policies have also led to new generation in places far from major load centers and have led to more countries dealing with interconnection issues. China accounts for one-third of the world’s new transmission facilities over the past ten years, or about half a million kilometers of transmission lines, used for purposes such as connecting energy sources from northern and western provinces to eastern load centers using ultra-high-voltage lines. India and Brazil are also rapidly expanding their grids, adding nearly 180,000 kilometers over the past ten years, about a 60-percent increase.
The age of grids varies by country, depending on historical development and varying levels of investment. The lifespan of grids, which are kept in service much longer than most facilities they interconnect, depends on the overloading and capacity, environmental factors, and the specific component. Transformers generally have a lifespan of 30 to 40 years, as do circuit breakers and other substation switchgear. Underground and undersea cables can last up to 50 years, and overhead transmission lines can last 60 years. More than 50 percent of grid infrastructure in advanced economies has been in service for longer than 50 years, and only about 23 percent is less than ten years old. However, in emerging and developing countries, about 40 percent of infrastructure is less than ten years old, and less than 38 percent is less than 20 years old.
The U.S., Japan, and some European countries have a higher proportion of their grids that are more than 20 years old. More than 50 percent of the countries in the European Union have grids more than 20 years old, which is about half their expected lifespan. Most new transmission in these countries has been built to access renewable generation. In Africa, Ghana, Kenya, and Rwanda have made significant investments in modernizing and expanding their grids.
Digitization of the world’s grids is also becoming “paramount,” according to the report, which says investment in digital technologies rose from about 12 percent of global investment a few years ago to about 20 percent in 2022. This is because of a need to manage distributed energy resources such as EVs, small-scale renewables, and electric heat pumps, as well as new players in the industry such as aggregators and demand response companies. Grid operators need digital technology for real-time monitoring and control of energy flows, especially in distribution grids, which saw 75 percent of global investment in 2022. The rise of distributed energy resources and other new technologies on the grid is requiring more precise study of power flows, the report says.
On the regulatory side, power grids are natural monopolies that are thus heavily influenced by regulations and policy, including entities that manage transmission and distribution systems, market structures, and market restructuring. Energy transitions, including climate change efforts, are driving the evolution of many of these regulations and policies.
Regulatory structures range from “cost of service,” where rules are set for companies to recover costs along with an allowed rate of return, or price-cap renumeration where there is a yearly cap that a grid operator can charge for each service or cluster of services. There is also a “yardstick competition” model where a grid operator’s service is compared with competitors and performance-based penalties and awards are assessed, as well as “output/performance-based” regulation where renumeration is based on monitoring the performance of service in order to encourage improvement in service. These varying regulatory models have different impacts on cost recovery and minimization, performance and operational efficiency, affordability, and quality of service.
Many national energy agencies and ministries are shifting to performance-based regulation since it spurs innovation and operational efficiency, the report says. A traditional regulatory approach, such as the “cost plus” framework, incentivizes capital expenditures even when operational expenditures would be more efficient.
“This shift is mainly driven by the energy transition, which calls for a high level of investment especially in innovative and digital assets. This leads to regulators needing a scheme that promotes the implementation of new technical and market solutions,” the report says.
In the “identifying the gap” section, the report discusses the pathway to future grids, analyzing an “announced pledges scenario” in which countries implement policies to meet their 2030 and 2050 zero-emission goals. In the announced pledges scenario, the electricity sector is a driving force in the clean energy transition and “undergoes deep transitions,” and electrical energy would grow by 20 percent per year. Elements of this scenario included the heavy deployment of EVs, more electric heating and cooling, and the development of hydrogen production using electrolysis. Wind and solar account for more than 80 percent of the total increase in global electric supply capacity over the next 20 years, an increase from the 40 percent seen in the past two decades. This scenario includes demand response—paying energy users to cut consumption in times of tight supply compared to a baseline—and energy storage. These systems will be supported by increased digitization and other modernizations on the grid.
This ambitious build-out of grids will make rapid deployment of supply chains critical, but there are significant risks to supply chains, including weather events attributed to climate change, natural disasters, a limited number of countries producing certain supplies, and surging demand for critical materials and raw materials worldwide.
In the announced pledges scenario, the total length of grids worldwide more than double between 2021 and 2050, reaching 166 million kilometers. More than 90 percent of that growth will be in the distribution grid.
The report also analyzed a net-zero emissions scenario, which it said provides a global roadmap to that goal and accelerates electricity demand growth to 3.2 percent by year by 2050, to a massive 62,000 TWh in 2050. Grid investment under the net-zero-emissions scenario passes the $1 trillion per year mark around 2035. Distribution grid investments maintain their total share of investment in both advanced economies and developing markets. Investment in emerging markets and developing economies are a majority of grid investment in both the announced pledges and net-zero emissions scenarios.
This significant investment calls for the replacement of 80 million km of transmission and distribution lines over the next two decades, which was more than the total length of all grids worldwide in 2021. More than two-thirds of the total line length by 2040 in the announced pledges scenario is yet to be built.
The report noted that failing to accelerate grid development in line with the announced pledges scenario—with “more limited investment, modernization, digitalization, and operational changes than envisioned – there would be a significant risk of stalled clean energy transitions around the world.”
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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.