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.
Published: July 6, 2023
By: Concentric Staff Writer
Texas Governor Greg Abbott signed new legislation reforming the state’s utilities and allocating reliability costs to intermittent generation sources in the same week a searing heat wave set in and set electricity prices skyward.
Governor Abbott on June 9 signed HB 1500, a “sunset” bill, which is a regular reauthorization of the Public Utility Commission of Texas (PUCT), and includes several provisions to shore up grid reliability. The bill drew a negative reaction from some renewable energy interests over provisions they say are aimed at hindering clean-energy resources.
Reliability has become more of a discussion topic in Texas since February 2021 when Winter Storm Uri caused widespread outages and hundreds of deaths, mostly due to freeze-ups of natural gas infrastructure. Summer reliability risks include grid impacts due to high electricity load and hot weather—the Electric Reliability Council of Texas (ERCOT) issued a voluntary conservation call on June 20 from 4 p.m. to 8 p.m. central time that followed a “weather watch” from June 15–21.
The HB 1500 legislation requires generation resources, other than battery storage facilities, to demonstrate to the PUCT that they will be available to operate when called upon during times of highest reliability risk. The owner or operator must be able to meet the requirement by January 1, 2027, by supplementing or contracting with on-site or off-site resources, including energy storage. The legislation directs the PUCT to determine the average capability based on “expected resource availability” and seasonal-related capacity on a standalone basis.
HB 1500 also requires establishing an ancillary services program to procure energy for dispatchable reliability reserve services on a day-ahead and real-time basis to account for market uncertainty. It also requires a determination of the quantity of services necessary based on historical variations in generation availability for each season, based on a targeted reliability standard or goal. This includes the intermittency of non-dispatchable generation facilities—wind and solar—and forced outage rates for dispatchable generation facilities.
Under the new law, the PUCT cannot require any retail customer or load-serving entity in the ERCOT power region to purchase credits designed to support a required reserve margin or other capacity or reliability requirement unless the PUCT ensures that the net cost of the credits to the ERCOT market does not exceed $1 billion annually, less the cost of any interim or bridge solutions. The credits are available only for dispatchable generation and the credits must be obtained centrally to prevent market manipulation. A generator also cannot receive credits that exceed the amount of its generation bid into the forward market.
Generation units can receive a credit only for being able to perform in real-time during the tightest intervals of low supply and high demand on the grid, to be defined annually by the PUCT. The bill also establishes a penalty for generators that bid into the forward market but do not meet their assumed obligation. The bill also establishes a single ERCOT-wide clearing price for the credits program that does not differentiate payments or credit values based on locational constraints.
A new Grid Reliability Legislative Oversight Committee was also created through the new law, which will oversee the PUCT’s implementation of legislation related to the regulation of the Texas electricity market enacted by the 87th and 88th Legislatures. The eight-member committee will be composed of three members from the Senate, three from the House, and the Senate and House chairs having “primary jurisdiction over matters relating to the generation of electricity.”
The legislation requires the PUCT to file a report no later than December 1 each year that includes the annual costs incurred by load-serving entities that back up dispatchable and non-dispatchable generation resources to guarantee that a firm amount of electric energy will be available to the Texas power grid.
Following a review of the report, the PUCT will determine whether specific transmission or distribution system constraints or bottlenecks in Texas give rise to market power in specific geographic markets. If there is a finding that such constraints give rise to market power, the PUCT can order reasonable mitigation by requiring utilities and others to construct additional transmission or distribution capacity or both.
Environment Texas Executive Director Luke Metzger issued a statement in opposition to the passage of HB 1500, saying it favors fossil-fuel-powered generators and will lead to higher transmission costs for renewables.
“We need, and Texans want, more clean energy, not less,” Metzger said. “There is strong support for more wind and solar energy, more battery storage, more energy efficiency, and more interconnection with the national grid. Unfortunately, the Legislature ignored these solutions to strengthen our electric grid while protecting consumers and the environment.”
However, Brent Bennett, policy director with the Texas Public Policy Foundation, lauded passage of the bill.
“We commend the legislature for passing HB 1500, which renews the Public Utility Commission on the condition that they take up needed market reforms, including Governor Abbott’s 2021 directive to ‘allocate reliability costs to generation resources that cannot guarantee their availability,’ and to ‘ensure that all power generators can provide a minimum amount of power at any given time.’ These reforms are critical in light of the federal government’s profligate spending on unreliable energy sources and onslaught of regulations on reliable energy sources,” Bennett said.
The new legislation coincided with a heat dome that hit the state in recent weeks, which will increase electricity demand for air-conditioning. Early in the week of June 25, Texas was under a hazardous heat warning, with afternoon temperatures of 104 degrees Fahrenheit recorded on June 27.
ERCOT broke its peak demand record on June 19 at 79,304 MW surpassing the previous June’s record of 76,718 MW. ERCOT set 11 peak demand records in the summer of 2022, typically in the late afternoon and evening hours. The grid operator said it was using tools such as reserve power, calling for large customers to reduce usage and bringing more generation online sooner. ERCOT said that other than extreme heat and record demand, it was experiencing outages of thermal power plants, declines in solar in the evening hours and low performance from wind during the summer peak.
The conditions on the grid led to extreme wholesale market prices in excess of $5,000 per MWh[1] on June 20.
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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, or related companies. 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.
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[1]“ERCOT: Real-Time Price – LCG Consulting.” EnergyOnline, www.energyonline.com/Data/GenericData.aspx?DataId=4. Accessed 29 June 2023.
Published: May 12, 2023
By: Danielle Powers, Chief Executive Officer
There is no question that expanding the electric transmission system is a key factor in achieving the nation’s clean energy goals. The most efficient way to ensure that this happens, however, is being strongly debated.
FERC Order 1000 established reforms in transmission planning and cost allocation, and eliminated the Right of First Refusal (ROFR) for those incumbent utilities involved in regional or inter-regional infrastructure construction, with limited exceptions.1 In Order 1000, FERC reasoned that by eliminating long-standing monopolies, competition would be created, and innovation and cost savings would result. In eliminating utilities’ monopoly over regional transmission, however, FERC expressly left it to states to enact their own ROFR laws.
Utilities in Kansas, Missouri, Oklahoma, Mississippi, and Montana have successfully persuaded lawmakers to prioritize ROFR legislation. Indiana recently passed ROFR legislation, and legislation is anticipated in other midwestern states this year. States including North and South Dakota, Nebraska, Texas, Iowa, and Michigan have ROFR laws in place.
ROFR issues are also being re-examined at the federal level. Questions around the effectiveness of competition in transmission have prompted the FERC to consider giving incumbent utilities the right to build regional transmission if they partner with one or more unaffiliated, non-incumbent partners.
Critics of the ROFR argue that it can limit competition and innovation in the industry. By granting the incumbent transmission provider the first opportunity to continue providing service, it can create a barrier to entry for other providers who may be better suited to meet the needs of the market. Additionally, the ROFR can limit consumers’ ability to access alternative sources of energy and limit the development of renewable energy sources.
These arguments have recently carried the day in Iowa, where the battle over who should be able to build and own the regional transmission projects necessary to support grid reliability and the shift toward renewable energy is currently playing out.
The Iowa Supreme Court recently halted a 2020 order giving incumbent utilities in Iowa the right of first refusal to build proposed transmission projects. Stating that the 2020 law would stifle competition and harm the business interests of out-of-state companies, the Iowa Supreme Court sent the case back to the district court to decide whether the ROFR is unconstitutional. The temporary injunction affects five transmission projects totaling about $2.64 billion that ITC Midwest, MidAmerican Energy and Cedar Falls Utilities intend to build in Iowa. The projects are part of the Midcontinent Independent System Operator’s Long Range Transmission Planning Tranche 1 projects, approved last year.
The battle over who builds the grid of the future will continue to be fiercely debated. Protracted debate, however, risks the grid transformation necessary to enable a clean energy future.
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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, or related companies. 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.