Page 2 – Concentric Energy Advisors

Published: October 3, 2024

By: Concentric Staff Writer

Interconnection queue backlogs around the country are making it much more challenging to develop new generation projects, such as zero-emission resources needed to meet national decarbonization goals.

However, Independent System Operators (ISOs) and Regional Transmission Organizations (RTOs) that manage massive electrical grids around the country are responding, as is the federal government, to address the problem and make reforms. A key element of this response is Federal Energy Regulatory Commission (FERC) Order 2023, issued in July 2023, which aims to address interconnection queue backlogs, improve certainty for developers and others, and prevent undue discrimination towards new technologies.

Danielle Powers, Chief Executive Officer at Concentric Energy Advisors, is working on the front lines of the issue. Part of the solution, according to Powers, is to implement stricter requirements for demonstrating project “readiness” in order to decrease the number of speculative projects entering the interconnection queues.

“The independent system operators are taking steps to make the commitment to entering the queue more real, in terms of physical control and deposits, penalties or withdrawal fees,” Powers said.

A major concern that remains is the inability of many projects in interconnection queues to get built due to siting difficulties. This remains a challenge in ensuring that the resources needed to meet reliability and public policy goals actually get built.

Other than new zero-emission projects such as solar, solar/battery, and wind, other infrastructure such as data centers and electric vehicle charging stations are increasing demand at a time when an increasing amount of variable-output energy resources are being added.

In interconnection queue processes performed by ISOs, RTOs, and individual utilities, projects seeking interconnection must undergo a series of studies before they can be built. The studies determine which network upgrades are needed to interconnect, and the associated costs. Projects must also meet certain milestones and make payments to stay in the queue—the list of projects waiting to interconnect.

With the massive build-out of renewable generation happening on the U.S. grid, there were about 12,000 projects representing 1,570 GW of generator capacity and 1,030 GW of storage seeking interconnection at the end of 2023, according to Lawrence Berkeley National Laboratory (LBNL). Solar, storage, and wind projects make up about 95 percent of capacity in queues around the country.

Among a subset of queues for which data are available, about 19 percent of projects, or 14 percent of the capacity requesting to interconnect between 2000 and 2018, reached commercial operation by the end of 2023, LBNL said in its “Queued Up: 2024 Edition” report. Solar projects had a 14 percent completion rate, and storage projects had an 11 percent completion rate.

The average time projects spent in queues before being built has increased sharply, with the typical project built in 2023 taking about five years from the interconnection request to commercial operation, compared to three years in 2015 and two years in 2008, LBNL said.

FERC’s Order 2023 is meant to develop a new approach to interconnection as massive amounts of new resources come online.

“The growth of new resources seeking to interconnect to the transmission system and the differing characteristics of those resources have created new challenges for the generator interconnection process,” FERC said in the Order. “These new challenges are creating large interconnection queue backlogs and uncertainty regarding the cost and timing of interconnecting to the transmission system, increasing costs for consumers.”

Backlogs in interconnection queues also create reliability concerns, FERC said, as new generating facilities are unable to come online in an efficient and timely manner. More reforms are needed even after the issuance of FERC Order No. 845 , the agency said. FERC Order No. 845 adopted “reforms that are designed to improve certainty for interconnection customers, promote more informed interconnection decisions, and enhance the interconnection process.” FERC said.

Order No. 2023 implemented a “first-ready, first-served” cluster study process, which FERC said increases access to information prior to entering the queue; creates a mechanism to study interconnection requests in groups where all interconnection requests in the groups are equally queued and of equal study priority; and increases financial commitments and readiness requirements to enter and proceed through the queue.

The rule requires transmission providers to publicly post available information pertaining to generator interconnection and developers to use cluster studies as the interconnection study method.

The rule also requires transmission providers to allocate cluster study costs on a pro rata and per capita basis and to allocate network upgrade costs based on a proportional impact method. Interconnection customers must pay study and commercial readiness deposits as part of the cluster study process, as well as demonstrate site control at the time of submission of the interconnection request.

Transmission providers must also impose withdrawal penalties to interconnection customers for withdrawing from the interconnection queue, with certain exceptions. FERC also required transmission providers to adopt a transition process to move from the existing serial interconnection process to the new cluster study process.

Order no. 2023 will “increase the speed of interconnection queue processing and incorporate technological advancements into the interconnection process,” FERC said.

In the Pacific Northwest, the Bonneville Power Administration (BPA) switched to a “first-ready, first-served” interconnection queue process, a change from the “first-come, first-served” approach it previously used. Developers now must show they have site control and meet commercial-readiness requirements that include a cash deposit, an irrevocable letter of credit, or a deposit into an escrow account. BPA had 376 projects in its queue as of June, according to BPA materials.

In California, where a substantial amount of new zero-emission resources are coming online, queue reforms are underway to address the fact that only about 10 percent of projects in the queue come to fruition. Developers are faced with extremely long timelines for project development and a “stop-start” situation that makes it difficult in terms of site security, financing, and other areas.

CAISO’s normal level of about 113 interconnection requests per year grew to 373 in 2021, with more than 150 GW of projects sitting in its Cluster 14. CAISO went as far as requesting that FERC pause new interconnection requests, which FERC approved in March.

CAISO launched a series of reforms known as its Interconnection Process Enhancements, which it said were needed to avoid CAISO becoming out of compliance with Order. No. 2023 or being forced to file for a waiver. CAISO filed the tariff changes for the enhancements with FERC on Aug. 1.

“The CAISO interconnection queue now contains more than three times the capacity expected to achieve California public policy objectives for the next two decades and far exceeds the ability of available and planned transmission to deliver power from all of these projects to customers,” CAISO said in the filing.

CAISO said its reforms maintain open access in the region and that the ISO will now identify the most viable and needed projects and allow them to advance through the queue. This will be done in zones with sufficient transmission capacity, providing resource diversity and availability in the queue.

CAISO noted that clogged queues create “unsustainable strain” on planning and engineering resources and that interconnection study results lose accuracy, meaning, and utility when the level of interconnection requests far exceeds the existing or planned transmission capacity in a given area. It is impossible to allocate deliverability, or the transmission capacity needed to deliver a generator’s energy to load during various system conditions, to all of the interconnection requests currently in the CAISO queue, the grid operator said.

FERC, in November 2022, also approved an interconnection process reform filing by the PJM Interconnection, which covers 13 mid-Atlantic states and Washington D.C. The filing transitions PJM’s queue from a serial “first-come, first-served” approach to a “first-ready, first-served” approach.

PJM has expressed concern about having enough generation to meet demand. The interconnection queue reform process will help clear the backlog of requests and get generation online more quickly, PJM officials said. The effort includes a “Queue Scope tool” that allows resource developers to more effectively assess the engineering and financial impacts of a project at various locations on their own before they formally enter the interconnection queue.

PJM had about 62 GW of projects that completed its study process by the end of 2023 and expects that number to be about 100 GW by the end of 2025. However, in 2022, only about 2 GW of new projects came online, with only about 700 MW of that being renewables. The grid operator had about 265 GW of projects seeking to interconnect in 2023, about 95 percent of which were renewables.

Reforms are also underway in the Midcontinent Independent System Operator (MISO), which covers 15 states. FERC in February approved MISO’s filing to re-work its queue process, which includes increasing milestone payments, adopting an automatic withdrawal penalty, revising withdrawal penalty provisions, and expanding site control requirements. Historically, about 70 percent of projects in MISO’s queue have never come to fruition, resulting in the need to restudy projects with lower queue positions.

MISO increased its Milestone 2 (M2) payment from $4,000 per MW to $8,000 per MW; its Milestone 3 (M3) from the greater of 20 percent of network upgrade costs minus the M2 payment or $1,000 per MW; and its Milestone 4 payment to 30 percent of network upgrade costs minus M2 and M3 payments.

MISO increased Point of Interconnection (POI) site control requirements to 50 percent site control from generator site to POI upon application, or $80,000 per mile for the entire line mileage to POI. It also required 50 percent site control from generator site to POI and 50 percent of interconnection switchyard, if necessary, prior to Phase 2. 100 percent site control is required from generator to POI, including interconnection switchyard, if necessary, prior to the execution of a generator interconnection agreement or within 180 days of execution with an approved exception.

It also imposed a new escalating automatic penalty upon withdrawal and an adjustment to the calculation for harm imposed by a withdrawal. These range from 10 percent of the Milestone 1 payment at decision point 1 of the process to 100 percent of Milestone 2 during generator interconnection agreement negotiations.

“These reforms are needed to reduce the number of queue requests withdrawing from the process,” MISO said on its web site. “The fewer projects in studies, the quicker it takes to complete; the fewer projects that withdraw, the more certain phase 1 and 2 study results are.”

In Texas, the growth of interconnection requests was noted by Oncor CEO Allen Nye in a recent second-quarter earnings call, during which he noted that interconnection requests in Oncor territory increased by about 100, or 13 percent from the second quarter of last year. The Electric Reliability Council of Texas projects that its peak load in 2030 will nearly double to 152 GW, compared to the current record of 85.5 GW, which was set in August 2023.

As Concentric’s Chief Executive Officer, Danielle Powers, noted, it’s a bit soon to see how much of a difference the ongoing efforts at the federal level and by RTOs and ISOs to reduce interconnection queue levels will make, but it’s clear that much work is underway.

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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: 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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Published: July 2, 2024
By: Concentric Staff Writer

A proposal for a special arrangement whereby a planned Amazon data center would be directly supplied by a co-located nuclear power plant in Pennsylvania sent rapid ripples across the industry this month. Other users of the transmission system are sounding the alarm over its possible effects on other customers and the precedent it could set, supported by Concentric Energy Advisors (Concentric).

There has been a quick line-up of parties filing to intervene in reaction to the proposal filed on June 3 with the Federal Energy Regulatory Commission by the PJM Interconnection LLC (PJM), the grid operator of the mid-Atlantic region including 13 states and the District of Columbia. The deal concerns a data center campus formerly owned by Talen Energy that the company sold to Amazon Web Services for $650 million earlier this year and sits next to the 2,514-megawatt (MW) Susquehanna Steam Electric Station, which Talen Energy also owns. Amazon plans to develop a large data center at the site to be powered by the close-by nuclear plant, which would be the largest such installation in U.S. history.

The proposal filed by and for PJM as transmission provider, Susquehanna Nuclear LLC as interconnection customer, and PPL Electric Utilities Corporation would amend the existing interconnection service agreement (ISA) to raise from 300 megawatts to 480 MW the amount of co-located load from the data center and make other revisions and changes [Docket No. ER24-2172].

Concentric is among the commenters; on June 24 filing an affidavit from Chairman of the Board, John Reed and Chief Executive Officer, Danielle Powers. Concentric, drawing from its decades of experience in utility regulation, filed the affidavit in support of a protest of PJM’s filing that was submitted to FERC by Exelon Corporation (Exelon) and American Electric Power Service Corporation (AEP).

“The significance of this case lies in its potential to set far-reaching precedents for how similar situations will be handled in the future,” the Concentric filing says. “The sheer scale of the Co-Located Load presents unique challenges and complexities that have not been encountered before on such a magnitude.”

Ms. Powers, in an interview, said that the proposed amendment to the ISA provided little detail on the costs to other customers. It is this lack of detail and impact on customers that are so important to understand and why FERC must set this matter for hearing, she said.

“We need to understand what the issues are and what you are requiring of both the generator and the co-located load,” Ms. Powers said of the amended ISA. “Since the load is located behind the generator, there are many unanswered questions around how much and how the generator offers its capacity and energy into the PJM wholesale markets, and what the co-located load will or should pay under the PJM Open Access Transmission Tariff.” She also said that PJM and market participants have been involved in lengthy discussions on how to deal with co-located load and have been unable to come to a consensus. A filing places these unresolved issues in front of the FERC, she said.

The Concentric affidavit says there are substantial implications for the case as it could “fundamentally impact the regulatory landscape, influencing how regulators address cost allocation and rate design.” If the agreement results in significant avoided costs it could lead to other similar arrangements, leading to widespread cost-allocation issues and leaving unresolved questions of cost responsibility for using the electric grid, the filing says. The cost shift could be up to $140 million per year and the avoided transmission component makes up approximately 98 percent of the avoided costs, Concentric said.

In the protest filed by Exelon and AEP, the two companies said the matter must be set for hearing because of many unresolved facts and that it includes “by the filing’s own admission, an ISA that establishes novel configuration.” If FERC does not set the matter for hearing, it should reject the ISA amendment because it amounts to an “end run” around PJM’s stakeholder process and violates PJM’s tariff by creating a new type of load, the protest says.

“The Parties’ non-conforming ISA must be set for hearing because it raises more questions than it answers,” Exelon and AEP said. “Given the scant information provided in the transmittal, absent further factual development, the Commission will be unable to make an informed decision whether to accept the ISA and parties to the proceeding will be denied necessary notice and opportunity to raise informed protests before the Commission.”

There are huge financial consequences around the filing as there are likely to be many other similar situations, the protest says, and in the absence of other precedent, it is reasonable to think that other parties could take a similar approach.

“The number of expected, non-conforming ISAs that the filing anticipates could have a profound effect on the market,” the protest says. “Should large quantities of load rush to co-locate with generation on terms that bear even a resemblance to the ISA at issue here, PJM capacity markets will have steadily decreasing volume as the capacity resources flee to serve load that uses and benefits from—but does not pay for—the transmission system and the ancillary services that keep the system running.”

But Talen Energy (Talen) fired back in the public arena, on June 27 issuing a press release characterizing the proposal as a new way to deal with rising data center demand. Powering this new category will require both metered and behind-the-meter solutions, the company said.

“Exelon and AEP’s protest of the Susquehanna ISA is a misguided attempt to stifle this innovation by interfering with an ISA amendment agreed to and supported by all impacted parties – which Exelon and AEP decidedly are not,” the press release says. “The factual recitations in the protest are demonstrably false. The legal positions are demonstrably infirm.”

Nearly all of the issues raised by Exelon and AEP are not even subject to FERC oversight, Talen argued, because transmission is not implicated, and Talen has a right to contract with Amazon for long-term, committed power. It also said that PPL agrees that Talen has the right to sell power directly to Amazon, and the filing is supported by PJM, it said.

The proposal to FERC by PJM and others involved in the co-located data center/power plant project raises many new questions regarding what is being recognized as a new frontier in energy infrastructure development. As of June 29, there were 33 motions to intervene filed in the docket.

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Published: June 27, 2024

By: Concentric Staff Writer

There is a legal tumult swirling around the U.S. Securities and Exchange Commission (SEC) and its recent issuance of a suite of new climate disclosure rules for publicly traded companies, with states, energy interests, and environmental groups immediately launching a flurry of court challenges.

The agency says the importance of the climate risk disclosures required in the Enhancement and Standardization of Climate-Related Disclosures: Final Rules, approved March 28 in a 3-2 vote, has grown due to increasing risks and possible impacts on financial performance and position due to extreme weather- and climate-related challenges. Various types of environmental impact reporting have been required for more than 50 years, according to the SEC.

After multiple lawsuits were immediately filed, the SEC in April voluntarily stayed the rules, but said in a news release that does not mean the Commission is in doubt about the rules’ legality.

“In issuing a stay, the Commission is not departing from its view that the Final Rules are consistent with applicable law and within the Commission’s long-standing authority to require the disclosure of information important to investors in making investment and voting decisions,” the SEC said when announcing the stay.

The SEC said it recognized that many commenters had expressed concern over the scope of the proposed rules, saying they require too much detail, could be overly costly or burdensome, could harm companies’ competitiveness, or obscure other relevant information. The Commission said that it tried to address these concerns by modifying the definition of climate-related risk, making the rules less prescriptive and adjusting reporting time frames.

The SEC’s final rules were “watered down” from a proposed rule issued more than two years ago, according to Concentric Energy Advisors Project Manager Michael Buckley, an expert in Environmental Social and Governance (ESG) investing principles and sustainability data and information. After the more stringent proposed rule was issued, publicly traded companies pushed back, saying the disclosures would be overly burdensome and compliance would be too costly, according to Buckley.

Parties filing suit against the SEC over the final rules range from the Natural Resources Defense Council, Sierra Club, Texas Alliance of Energy Producers, The U.S. Chamber of Commerce, and states such as Louisiana, Iowa, and West Virginia.

The SEC tried to strike a middle ground by making the new requirements less intensive than the proposed rule, according to Buckley. Lawsuits from states and companies were filed on the basis that the SEC overstepped its authority, while other lawsuits were filed by parties that said the agency didn’t go far enough.

“They’re stuck in the middle, trying to balance both viewpoints,” Buckley said. He expects the fallout from the final rules and the legal challenges to swirl.

In describing the need for the disclosures, the SEC said that an increasing number of retail and institutional investors have expressed a need for more detailed information on the effects of climate-related risks. Also, investors need more information regarding how companies will meet their publicly stated climate and net-zero goals.

“The final rules are a continuation of the Commission’s efforts to respond to investor need for more consistent, comparable, and reliable information about the financial effects of climate-related risks on a registrant’s business, as well as information about how the registrant manages those risks,” the SEC said.

The new SEC rules require registered companies to disclose climate-related risks that could impact business strategy, financial condition, or the results of their operations, as well as actual and potential impacts of climate-related risks on strategy, business model, and outlook. Companies must also describe material expenditures they have incurred as part of a strategy to mitigate or adapt to a material climate-related risk, including transition plans, scenario analyses, or internal carbon prices. Also required to be disclosed is any board of directors- or management-level oversight of climate-related risks, as well as any processes for identifying, assessing, and managing climate risks.

Other requirements of the rules are reporting of expenditures, charges, and costs from severe weather events such as hurricanes, tornadoes, flooding, drought, wildfire, extreme temperatures, and sea level rise. Costs related to carbon offsets and renewable energy credits must also be disclosed if they are used by companies to achieve climate-related goals.

Central to the case is the greenhouse gas (GHG) emissions reporting requirement, a protocol that is divided into Scope 1, Scope 2, and Scope 3 emissions. In the final rules, emissions reporting is required for Scope 1 (direct emissions from sources that are owned or controlled by the company) and Scope 2 (indirect emissions from the generation of purchased energy, including electricity, heat, or steam from a utility company or other supplier). But a proposed Scope 3 reporting requirement that was included in the proposed rule was dropped from the final rules. Scope 3 emissions include indirect emissions that occur in the value chain, including both upstream and downstream such as purchased goods and services, employee commuting, business travel, transportation and distribution, and waste generated in operations.

Organizations that opposed the Scope 3 reporting requirement in the proposed rule included the Edison Electric Institute (EEI) and the American Gas Association (AGA). In joint comments, they said that Scope 3 disclosures should only be required if a company has a Scope 3 emissions goal or target, and there should be very clear boundaries on the information that needs to be included. They also argued that the SEC should exempt from the final rules any companies that are consolidated subsidiaries of a parent company when the parent company’s climate-related disclosures encompass the subsidiaries.

“The Commission is asking for an unprecedented level of disclosure; the liability exposure needs to be adjusted to encourage good-faith disclosures of the unique information it would require. In order to further the Commission’s intent to increase the amount of climate-related information that is disclosed, there should be no increased risk exposure for disclosure made in good faith,” EEI and AGA said in their joint comments.

However, the two groups said they do not oppose the climate reporting requirements, calling them “an important step forward on GHG disclosure.”

Meanwhile, various courts are hearing challenges to the rule.

19 Democratic Attorneys General—including Massachusetts and the District of Columbia—worked in partnership to defend the climate rule in the 8^th Circuit Court of Appeals in St. Louis, allowing them to intervene in the case, which consolidated more than nine lawsuits. Attorneys General Offices opposing the rule include Alabama, Alaska, Arkansas, Georgia, Idaho, Indiana, Iowa, Kentucky, Missouri, Montana, New Hampshire, Oklahoma, Nebraska, North Dakota, South Carolina, South Dakota, Tennessee, Utah, Virginia, West Virginia, and Wyoming. The 8^th Circuit proceeding also consolidated petitions for review filed by the U.S. Chamber of Commerce and the Ohio Bureau of Workers’ Compensation.

In a separate legal tendril, at an April 30 hearing in the 5^th Circuit Court of Appeals, where Texas, Louisiana, Utah, and West Virginia filed a petition for review of the SEC rules in February 2023, judges questioned appellant’s attorneys as to whether the rules would increase costs for states as they allege. Attorneys for the SEC argued that the parties lack standing in the 5^th Circuit case because they do not have sovereignty on the issue. The judges at times seemed skeptical that reporting requirements would be overly onerous for companies, with a judge describing them as “cut and paste.”

Legal challenges to the rules rely on several legal precedents and laws, according to a blog post from the Harvard Law School Forum on Corporate Governance. These include a requirement under the Administrative Procedure Act that courts must generally set aside agency action that is an abuse of discretion, contrary to constitutional right, out of the agency’s jurisdiction, or issued without observance of procedure required by law. There is also the major questions doctrine, which holds that courts will presume that Congress does not delegate to executive agencies any questions of major political or economic significance, as well as the Chevron doctrine, which says courts should defer to an agency’s interpretation of an ambiguous statute. However, the Chevron doctrine is under review by the U.S. Supreme Court.

There has also been political pushback on the climate disclosure issues, as Sen. Tim Scott (R-S.C.) on April 17 introduced a Congressional Review Act resolution to overturn what he called the “radical” SEC rule, that he added “would bury public companies in paperwork, raise costs for consumers, and stifle economic opportunity.” Every Republican on the Senate Committee on Banking, Housing and Urban Affairs signed on to the resolution.

An important aspect of the rules, according to Buckley, is that the SEC still provides companies leeway in their disclosures to determine their own “materiality” thresholds. The U.S. Chamber of Commerce commented, however, that the new rules erode the reasonable investor standard of materiality and micromanage how companies make key determinations about materiality.

The traditional concept of materiality covers financial risks that could arise over the next quarter or the next year, but long-term impacts, including those that could come from climate change, are on much longer timelines. Investors also have different timelines, as some investors are also looking more for long-term value, Buckley said.

One issue with the rules is that there is a lot of estimation required in compliance and currently a lack of good data, which could lead to some inconsistency, Buckley said. But the rules will give investors an idea of what kind of carbon footprint a certain company has, even if the accuracy of the data is not perfect. The disclosures will lead to more qualitative information regarding companies’ efforts to reduce emissions than has been present before, he said.

There is also more data coming in on companies’ sustainability efforts every year, with utilities leading the way. In the order, the SEC discussed the historic filing of sustainability reports by companies belonging to the Russell 1000 Index, a stock market benchmark for large-capital investing in the U.S. equity market. In calendar year 2022, a record 90 percent of companies published sustainability reports, including climate-related information, up from 60 percent that made such disclosures in 2018. The number of companies in the bottom half of the Russell 1000 Index increased their sustainability reporting percentage from 34 percent in 2018 to 82 percent in 2022. The utility sector had the highest percentage of companies that published a sustainability report in 2021, at 100 percent. They were followed by materials (95 percent); energy (94 percent); consumer staples (91 percent); real estate (90 percent); industrials (89 percent); financials (85 percent); consumer discretionary (81 percent); information technology (71 percent); and health care (69 percent).

The SEC acknowledged in the rules that Scope 1 and Scope 2 emissions might not fully reflect a company’s exposure to transition risks because some of those risks could only be captured through other metrics, such as Scope 3 emissions. Companies that face similar exposure to emissions-related climate risks could report different Scope 2 emissions depending on whether they pay directly for their utilities (Scope 2), or utilities are included in leases (Scope 3), or whether they have employees that work from home and do not directly contribute to utility expenses. To account for these differences, the rules require disclosures on methodology, significant inputs, significant assumptions, organizational and operational boundaries, and reporting standards with respect to Scope 1 and 2 emissions.

“These disclosures will provide additional context to help investors understand the disclosures and will enable investors to draw more reliable comparisons across registrants,” the SEC said in the rules. The Commission ended up exempting Smaller Reporting Companies (SRCs) and Emerging Growth Companies (EGCs) from the GHG disclosure requirements to limit costs imposed on them and to avoid deterring these companies from conducting initial public offerings.

The SEC received more than 4,500 individual comments and 18,000 form letters on its proposed rules, from entities including academics, accounting and audit firms, individuals, industry groups, investment firms, non-governmental organizations, pension funds, climate advisors, state government officials and members of the U.S. Congress. Many commenters generally support the required disclosures, while others opposed them whole or in part. The SEC’s Investor Advisory Committee offered broad support and recommended certain modifications.

The Commission said that while climate-related issues are subject to other regulatory schemes, its objective was limited to advancing its mission to protect investors, maintain fair and efficient markets, “and not to address climate-related issues more generally.”

The SEC said it is agnostic about whether and how companies consider or manage climate-related risks, but investors have expressed a need for information regarding risks in valuing securities they hold or are considering purchasing.

Many commenters on the rules said the current, largely voluntary reporting of climate-related information under differing third-party frameworks is inadequate. The current, largely voluntary regime has led to selective choosing by companies of which climate-related risks to disclose and has not provided reliable and complete information to make good investment decisions. Adoption of mandatory climate-related disclosures would improve the timeliness, quality and reliability of climate-related information and lead to more accurate valuation of securities, the SEC said.

The SEC based the rules on the Task Force on Climate-Related Disclosures (TCFD) disclosure framework created by the Financial Stability Board, an international organization that monitors and makes recommendations on the global financial system. The TCFD consists of four key themes, including governance, strategy, risk management, and metrics and targets. Many investors are already familiar with the TCFD framework and are already making disclosures that are consistent with it, and using the framework should help mitigate the compliance burden.

Whatever happens with the legal challenges to the SEC rules, it is clear that the reporting of GHG emissions by companies is on the rise. This issue will likely increase in prominence in coming years as investors decide where to put their capital and see more information on assessing the risks of doing so.

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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, related companies, or clients. 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: April 29, 2024
By: Concentric Staff Writer

Affordability has become front of mind for utilities and their regulators, who are now struggling to meet emissions goals while decarbonizing the electricity grid and switching to renewables, a transition that currently poses significant affordability concerns.

Central to these goals and the regulatory targeting of affordability are retail rates. When designing retail energy rates through rate cases at the state level, there has been a shift in the discussion from how to allocate costs to how various customer classes will afford those costs, Concentric Vice President Gregg Therrien said.

Therrien focuses on the electric, gas, and water sectors, primarily in Connecticut, New Hampshire, and New Mexico. Historically, rate cases have been about how to allocate costs across the different customer bases, including residential, commercial and industrial customers, municipalities, schools, and governments, Therrien said. But over the past year, more discussion has arisen in the context of affordability and lower income discount rates, also known as LIDR, he said.

“It’s a much bigger discussion than we’ve ever seen before, and that’s significant,” Therrien said of energy affordability. “I think it’s really in recognition that everybody knows prices are increasing.”

“LIDR is an acronym that has been around for a while but has gained prominence in rate design in the past couple of years,” he said. A discount rate in Massachusetts or New Hampshire has typically been 15 percent of either the distribution portion of a customer’s bill or their total bill. But now the trend for discounts is rising significantly, up to 50 percent or 60 percent of the total bill as recommended in Connecticut ongoing regulatory proceedings, he said.

Another guideline developed in the industry is the concept that an energy bill should be no more than 6 percent of monthly household income. This was an income threshold that was mentioned several times by Concentric experts.

“Now, with the energy transition, there’s the realization that there are people who need to have significantly discounted rates for the energy transition to occur without major disruption,” Therrien said. The current debate is how to structure these programs; for instance, should it be a straight discount for specific customer categories, or should it involve more detailed calculations?

Electric heat pumps, electric vehicles, and home solar equipment are examples of products that can be difficult for lower-income customers to afford. States are responding to zero-emission policies with more subsidies for cleaner equipment. Vermont has a program to give away electric heat pumps, and Maine has discount programs for such appliances. The federal government has incentives nationwide for customers to purchase electric vehicles.

Costs for these programs are often socialized across higher income brackets, according to Therrien. In California, state legislation has mandated that retail electricity charges be based on personal income, a contentious political issue that is receiving pushback from some (new legislation has been introduced to repeal that law). Another question is whether such programs should be subsidized only for residential customers or also for commercial and industrial customers.

Affordability is front and center when designing rates, according to Bickey Rimal, an Assistant Vice President at Concentric Energy Advisors. He said that a fixed monthly charge based on the cost of service tends to have a more significant impact on low-usage customers than a volumetric charge for energy usage. This is mainly due to the fact that the current fixed charges only recover a small proportion of the fixed costs, with the remainder of the fixed cost recovered from volumetric charges.

There is pushback because there are certain parties that incorrectly assume that low-usage customers are necessarily lower-income customers. According to Rimal, low-income customers are not necessarily low users, however, and similarly, high-income customers are not necessarily high users. Mr. Rimal recently conducted statistical analysis to compare the consumption patterns of low-income and non-low-income customers of a mid-western electric utility and found that the usage between the two groups was not statistically different.

For example, higher-income customers who own home solar might have lower overall usage than middle- and lower-income customer classes. On the other hand, low-income customers may have inefficient appliances or poor home insulation leading to higher usage, comparatively. For this reason, trying to keep the fixed charges artificially lower and volumetric charges artificially higher does not necessarily help the low-income customers, Rimal said.

It’s important to consider the significant challenges that low-income customers face in affording their energy bills. Additionally, there is growing concern that some customers may be left behind in the energy transition.

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All views expressed by the article contributors are solely the contributors’ current views and do not reflect the views of Concentric Energy Advisors, Inc., its affiliates, subsidiaries, related companies, or clients. 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: April 12, 2024

By: Concentric Staff Writer

Energy affordability for American households and businesses is surging to the forefront of the conversation among energy regulators and industry, bringing the issue into sharper focus and leading to efforts to develop solutions.

Energy bills are rising for all customer classes, increasing the public profile of the energy affordability problem, with utilities and regulators responsible for mitigating costs. This is occurring as state regulators and utilities are also being expected to transition to a cleaner grid while simultaneously maintaining energy reliability.

Experts from Concentric Energy Advisors provided their perspective on the many facets of the energy affordability conversation surrounding electric and gas service. Customer choice, privacy, effects on lower-income customers, and other considerations are among the factors in play as state regulatory commissions grapple with rate cases and struggle to keep the energy transition affordable.

The consensus is that at the present time, the transition from fossil fuels to 100 percent renewable and zero-emission resources is not affordable for utilities or for customers. While affording energy bills is already a profound struggle for many, the real energy affordability crunch is perhaps 10 to 15 years away, depending on location, Concentric’s Chairman John Reed said.

Affordability is “the single most challenging issue that regulators, and therefore our clients and therefore we, face,” Reed said. The issue of affordability is also the greatest challenge to widespread decarbonization, which is a situation that has received more attention over the past five years in the Northeast, California, and some of the Upper Midwest states, he said. Increasing decarbonization mandates and policies exacerbate the technological challenges in reaching “net zero,” Reed said.

“It is quite clear that that transition will be very expensive,” Reed said. “It’s going to put substantial upward pressure on rates.”

Reed estimates that some energy customers that recently had a monthly bill of $150 could see that rise to $600-$1,000 per month in the next 10–15 years if decarbonization programs are truly implemented to reach net zero by 2050. This will create a pushback among customers, and “there’s going to be a political backlash associated with electricity bills that increase at anything like that rate.”

“How will customers feel about their electricity bills being $1,000 a month?” he said.

As more technologies and sectors electrify, electricity bills will also cover heating, lighting, refrigeration, and some transportation costs, and residential power bills could potentially rival rent costs, Reed said. Adding to these costs will be replacing older appliances with more efficient units.

Some areas in the U.S. will need cold-weather heat pumps, but exclusive reliance on heat pumps means that when people lose electricity, they also lose heating ability. This might lead them to opt for backup fuel sources like natural gas or even wood, which have a higher carbon dioxide footprint.

“The place where the rubber will hit the road first is customer choice,” Reed said, adding that this will be true regarding gas appliances, heating equipment, and electric vehicles. On the power generation side, adjusting the price of new renewables such as wind and solar for the energy transition can involve shifting costs from electricity ratepayers to the general public through tax subsidies, he noted.

However, on an unsubsidized basis, some renewable generation is still about twice the cost of conventional generation resources, and renewables also require backup resources such as fossil peaking units. Energy storage is still “very expensive,” Reed said, bringing the cost even higher.

Of the quadrupling of electric bills: “I think that’s a realistic expectation before we hit net zero,” Reed said. This is true in the Northeast U.S., in states like New York and New Jersey, and other states with aggressive energy policy goals such as Minnesota, California, Oregon, and Washington, and some Canadian provinces. Reed noted that these are all areas with different energy systems and resource mixes.

“Understanding the regional difference is really important right now to understanding affordability,” he said. Rates can vary widely in different regions, creating different economic and political pressures depending on the region or area. Many areas with the most aggressive clean-energy policies, such as California, New York, and Massachusetts, have generally higher costs of living, increasing cost pressure on customers.

There are also questions about whether 100 percent net zero policies are worth the investment, depending on political attitudes, as closing the last gap to net zero can cause costs to dramatically increase.

“I think it is time to ask the realistic question of whether net zero is the right answer for 2050,” Reed said, adding that in addition to decarbonization, the conversation should include carbon capture and sequestration for power plants.

Electrification needs to be affordable and beneficial, Reed said. For example, banning all capital expenditures on natural gas infrastructure would remove customer choice. Another example is shifting natural gas usage in homes to natural gas power plants that generate power for the homes as they electrify, which could result in higher carbon emissions. This means it might be premature to replace appliances and vehicles with electric models before the grid and wholesale markets are more fully decarbonized.

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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.” ²In 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.

²Also referred to as the “February 2011 Cold Weather Event.”

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Published: February 6, 2024

Overview:

Authorized returns on equity (ROE) have increased for many Canadian electric and gas utilities, as regulators recognize that the cost of capital has risen for all companies, including regulated utilities. The most prevalent signs of shifting financial fundamentals are found in bond markets. Over the past two years, the Bank of Canada ratcheted short-term interest rates to 5.0% (the highest level in 22 years) to combat inflation well above the targeted 1-3% range.

Figure 1: Bank of Canada Overnight Rate

In response, Canadian government and utility bond yields increased by 150 to 200 basis points since 2022 as restrictive monetary policy contributed to tighter conditions in credit markets. While moderating in recent months, 10-year Canadian government bond yields remain between 3.25% and 3.50%, heralding an end to the ultra-low interest rate environment that followed the financial crisis of 2008–2009.

Figure 2: 10-year Canadian Government Bond Yield and Utility Bond Yield¹

Deemed equity ratios have also increased for several Canadian gas and electric utilities as regulators acknowledge that public policy mandates related to the energy transition equate to higher business risk for these companies. Despite recent increases to equity ratios for several Canadian utilities, the deemed equity thickness in Canada remains well below the U.S. average, as shown in Tables 1 and 2 below. The following section summarizes recent cost of capital decisions across Canada.

Summary of Recent Decisions:

Alberta – The Alberta Utilities Commission (AUC) concluded a generic cost of capital (GCOC) proceeding in which the AUC implemented an ROE formula tied to changes in government bond yields and utility credit spreads. The base ROE was set at 9.0%, and the formula return for 2024 will be 9.28%. This is the highest authorized ROE in Alberta in over a decade and represents a substantial increase over the previous return of 8.50%. The AUC also heard arguments regarding the deemed equity ratio but did not make any changes in that regard. (Decision 27084-D02-2023, released October 9, 2023)

British Columbia – The British Columbia Utilities Commission (BCUC) also concluded a GCOC proceeding for FortisBC Energy Inc. (a gas distribution utility—FEI) and FortisBC Inc. (an electric utility—FBC). The BCUC increased the authorized ROE for both companies to 9.65% based on the average results for a North American proxy group, as compared to the previous return of 8.75% for FEI and 9.15% for FBC. The BCUC also recognized that the energy transition had caused an increase in FEI’s business risk, and the deemed equity ratio was increased from 38.5% to 45.0% to account for the higher risk. FBC’s deemed equity ratio was also increased from 40.0% to 41.0%. The BCUC has initiated Stage 2 of the GCOC proceeding to review the authorized cost of capital for smaller utilities, including Pacific Northern Gas, and to determine which utility, if any, will serve as the benchmark in British Columbia. (Decision G-236-23, issued September 5, 2023)

New Brunswick – The New Brunswick Energy and Utilities Board, in a Rehearing Decision based on an appeal by Liberty Utilities (formerly Enbridge Gas New Brunswick), approved an ROE of 9.8% on a 45% common equity ratio. The ROE was down from the 10.9% last set for the Company in 2010, while the equity ratio remained unchanged. (Rehearing Decision Matter No. 491, issued November 18, 2022)

Nova Scotia – The Utilities and Review Board (UARB) maintained the authorized ROE for Nova Scotia Power (NS Power) at 9.0% in the first general rate case for the Company since 2012. The UARB recognized that energy transition issues in Nova Scotia (specifically the requirement to retire coal generation facilities and replace the power with renewable resources) increased the business risk for NS Power. Consequently, the deemed equity ratio for NS Power was increased from 37.5% to 40.0%. NS Power’s request for a storm cost deferral account to recover extraordinary storm costs above the level in base rates was also approved. (Decision 2023 NSUARB 12, M10431, issued February 2, 2023)

The UARB also approved a settlement agreement for Eastward Energy (formerly Heritage Gas), which included an authorized ROE of 10.65%, a decrease from the 10.8% last approved for the Company in 2011, and a deemed equity ratio of 45.0%, unchanged from its prior level. (Decision 2023 NSUARB 166, M10960, issued September 20, 2023)

Ontario – The Ontario Energy Board (OEB) recently issued a decision on Enbridge Gas’ request for a higher common equity ratio. The OEB found that Enbridge Gas’ business risk had increased due to the energy transition, although the OEB determined that it was partially offset by the amalgamation of Enbridge Gas Distribution and Union Gas. Consequently, the OEB increased the deemed equity ratio for Enbridge Gas from 36.0% to 38.0%. The OEB sets the authorized ROE for electric and gas utilities under a formula mechanism that adjusts the return each year based on changes in government bond yields and utility credit spreads. The formula return in 2024 will be 9.21%, down from 9.36% in 2023. The OEB has also indicated that it plans to review the formula and the deemed equity ratios for Ontario’s regulated electric and gas utilities in 2024. (Decision and Order EB-2022-0200, issued December 21, 2023; OEB letter, Chief Commissioner Mid-Year Update 2023–24, October 19, 2023)

Prince Edward Island – The Island Regulatory and Appeals Commission (IRAC) approved a settlement agreement for Maritime Electric Company that maintains the authorized ROE of 9.35% on 40.0% common equity. The settlement also included a provision that removed the hard cap on Maritime Electric’s earnings, such that the Company is now allowed to retain up to 35 basis points of actual earnings above the authorized level. (Order UE23-04, released April 24, 2023)

Pending Cases:

Newfoundland and Labrador – Newfoundland Power filed a general rate application in November 2023 that included a request to increase the authorized ROE from 8.50% to 9.85% while maintaining the deemed equity ratio of 45.0%. The application is currently pending, and a decision is expected later in 2024.

British Columbia – A Stage 2 proceeding is underway in British Columbia, where the BCUC will set the authorized ROE and equity ratio for smaller utilities, including Pacific Northern Gas, as well as determine what company will serve as the benchmark utility.

Table 1: Canadian Electric Utilities

Operating Utility	Deemed Equity Ratio	Authorized ROE	Recent Changes
Alberta Electric Utilities	37.0%	9.28%	ROE increased from 8.50%; new base ROE is 9.00%; new formula implemented
FortisBC Electric	41.0%	9.65%	ROE increased from 9.10%; equity ratio increased from 40%
Ontario Electric Utilities	40.0%	9.21%	ROE decreased from 9.36% under formula
Maritime Electric	40.0%	9.35%	Raised cap on earnings to 9.70%
Newfoundland Power	45.0%	8.50%	Pending
Nova Scotia Power	40.0%	9.00%	Equity ratio increased from 37.5% due to energy transition risk
Canadian Electric Avg	40.5%	9.17%

U.S. Electric Utility Avg²	51.6%	9.66%

Table 2: Canadian Gas Distribution Utilities

Operating Utility	Deemed Equity Ratio	Authorized ROE	Recent Changes
ATCO Gas Distribution	37.0%	9.28%	ROE increased from 8.50%; new base ROE is 9.00%; new formula implemented
Apex Utilities	39.0%	9.28%	ROE increased from 8.50%; new base ROE is 9.00%; new formula implemented
Eastward Energy	45.0%	10.65%	ROE decreased from 11.0%
Enbridge Gas	38.0%	9.21%	Equity ratio increased from 36.0% due to energy transition risk
FortisBC Energy Inc.	45.0%	9.65%	ROE increased from 8.75%; equity ratio increased from 38.5% due to energy transition risk
Gaz Métro LP	38.5%	8.90%
Gazifère	40.0%	9.05%
Liberty Gas New Brunswick	45.0%	9.80%
Pacific Northern Gas – West	46.5%	9.50%	Stage 2 Pending
Canadian Gas Avg	41.6%	9.48%

U.S. Gas Utility Avg³	52.3%	9.57%

For more information, please contact John Trogonoski, Jim Coyne, or Dan Dane.

¹Source: Bloomberg Professional; data through December 29, 2023.

² S&P Global Market Intelligence, based on electric rate case decisions from January 1, 2023 through December 19, 2023.

³ Ibid.

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Published: January 24, 2024
By: Concentric Staff Writer

The vast amount of geothermal energy surging under the surface of the Earth is one of the most ancient resources in existence, but it has yet to be significantly harnessed for public consumption in the United States, including the western part of the country where its potential is the greatest.

There are regulatory and economic hurdles to traverse for geothermal, which Indigenous people have used for more than 10,000 years for heat and healing rituals at sites such as the present-day location of Calpine’s The Geysers facility in northern California. But geothermal has been tepidly pursued on a commercial level in the U.S.—a situation that begs for more analysis of how this plentiful, zero-emission resource can be better harnessed.

The recent activation of the first major enhanced geothermal system (EGS) in the U.S. is a milestone for an energy resource that has long been recognized as both plentiful and clean. Fervo Energy, in partnership with Google, said on November 28 that it began operating a new 3.5-MW EGS geothermal plant in Nevada to power data centers in Las Vegas and other locations in the state. EGS technology employs vertical and horizontal drilling, pumped water, and rock fracturing to extract steam from underground heat to power above-ground turbines. This technique is in contrast to regular geothermal development that relies on naturally occurring permeable rock to extract heat and steam.

Geothermal energy is virtually limitless, “always on,” and a “50-state solution,” according to the U.S. Department of Energy (DOE), which in 2019 launched its GeoVision program to explore new potential for the resource. Improvements in technology and tools could reduce costs and increase geothermal development, according to DOE, which says there is potential for 60 gigawatts electric (GW_e) of geothermal energy capacity to be developed by 2050. EGS can also be developed in more locations since it is not limited by rock permeability and other factors that affect traditional geothermal development.

Optimizing and streamlining permitting timelines are other ways to increase EGS, as well as addressing regulatory and land-access barriers, DOE said. This would reduce development timelines as well as financing costs during construction, as has happened with oil and gas development over time. A “business-as-usual” DOE scenario predicts about 60 GW_e of potential development by 2050, a target DOE said could be met “without significant impacts on the nation’s water resources.”

DOE’s Geothermal Technologies Office analyzed development scenarios through 2050, aimed at five key activities, including defining and evaluating geothermal growth scenarios using data and modeling and addressing “all major geothermal resource and markets segments.” This would include hydrothermal and EGS resources, as well as electric and non-electric applications. DOE said it is using a transparent process supported by peer-reviewed data to produce a vision for geothermal growth and articulate strategies to achieve it.

Geothermal, which had the first few gigawatts of capacity installed in the U.S. in the 1980s, is also an under-recognized resource for the heating and cooling of homes and businesses using geothermal heat pumps (GHP). GHP deployment currently is at about 16.8 GW thermal (GW_th), equivalent to about 2 million households, according to DOE. Water usage can be conserved by using non-freshwater resources for this equipment.

The 2022 Inflation Reduction Act increased the federal tax credit for GHP from 26 percent to 30 percent and extended the credit until 2034. Homeowners must have installed and begun running systems that meet certain efficiency requirements to use the credit.

In 2022, geothermal made up 1.6 percent of U.S. primary energy consumption, a metric that includes transportation, industrial, residential, and commercial energy usage in U.S. Energy Information Administration (EIA) analysis. Geothermal is classified as a renewable energy source along with solar, wind, hydroelectric, and biomass, while primary energy sources as defined by EIA include natural gas, petroleum, nuclear electric power, and coal.

Despite the interest in new EGS, geothermal development has remained relatively flat in the U.S. over the past two decades, according to EIA data. U.S. geothermal net generation for all sectors monthly was about 1.2 million megawatt hours in January 2004, compared with 1.4 million MWh in September of this year, nearly two decades later. One of the reasons is the significant barriers in terms of cost and risk associated with the subsurface exploration that occurs in geothermal development.

There are other particular economic reasons why geothermal development has remained flat, according to a March report by the Lawrence Berkeley National Laboratory (LBNL). The study looked at empirical data from power purchase agreements (PPA) and examined geothermal’s role in wholesale electricity markets, where enthusiasm for the resource is affected by its lower net value relative to its PPA price.

“In the face of this challenging market outlook, policy intervention, and continued R&D investments may be warranted to sustain a vibrant geothermal industry that stands ready to contribute to the late stages of decarbonization,” LBNL said in the report. The underground heat source can also work in tandem with other low-emission technologies, such as hydrogen production and direct-air carbon capture, as well as for heating and cooling purposes.

Less than .5 GW of geothermal has come online in the U.S. in six western states where it holds major potential—California, Idaho, Nevada, New Mexico, and Oregon—and a minuscule 1 GW has been added in the past century nationwide.

When assessing geothermal resources, “identified” resources refer to those that have been located, assessed, and proven to exist, while “undiscovered” resources refer to potential reservoirs that are believed to exist based on exploratory techniques, but not directly confirmed to be accessible. Of the identified 39 GW of undiscovered geothermal capacity in the six western states, only 3.7 GW of capacity has been deployed thus far, not counting the new Google facility. Geothermal was boosted by a June 2021 “mid-term reliability procurement” order from California state regulators for 1 GW of zero-emission, high-capacity factor, non-weather dependent resources, namely geothermal. This will spur geothermal’s competitiveness through 2026, according to LBNL, along with regulatory drivers such as California’s SB 100 legislation and integrated resource planning in other Western states. This will result in new geothermal capacity sold to utilities and other procurement heavyweights in California like community choice aggregators (CCA).

LBNL analyzed historical PPA prices to judge the value of geothermal energy against competing resources such as solar, wind, and solar plus storage. Geothermal power plants do not require ongoing fuel procurement but are capital-intensive in the development phase, and capital costs make up the bulk of the required investment. Longer-term PPA structures of 15 to 30 years reduce project risks and attract financing, according to the LBNL report.

Geothermal also provides round-the-clock energy compared to variable energy resources such as solar and wind, which depend on weather and provide different energy and capacity benefits. Due to structures such as the wholesale power market in California, four hours of standard lithium-ion storage is rated similarly to geothermal in terms of capacity value. (Capacity value reflects contributions to local or regional resource adequacy requirements, in contrast to “energy value,” which refers to a resource’s specific hourly generation output.)

Solar and storage projects are also dominating interconnection queues around the country, particularly in the West. Solar and wind plus storage represent geothermal’s primary competition with an outsized presence in interconnection queues.

Geothermal appeared in CCA Silicon Valley Power’s (SVP) 2023 Integrated Resource Plan, which is aimed at compliance with state greenhouse gas emission-reduction standards and other policies. SVP sees geothermal becoming available for its resource mix in 2028. Geothermal enjoys a high load factor, and SVP plans the addition of 290 MW of new geothermal, along with 590 MW of wind, 150 MW of solar, and 110 MW of storage capacity by 2035.

“SVP faces a common challenge of deeply decarbonized systems, which is the ability to provide power reliably without firm dispatchable (emitting) thermal plants,” the CCA said. “Clean firm resources not only provide clean energy, but also firm capacity to help ensure system reliability. The clean, firm, and baseload characteristics of geothermal align well with SVP’s forecasted load growth and load shape and could provide a key clean firm option.”

But SVP says that there might only be 3.4 GW of geothermal available to California, and the California Public Utilities Commission’s mid-term reliability order requires procurement of a long lead-time resource—geothermal—which could provide competition and reduce the amount of geothermal available to SVP.

SVP will deliver energy to the City of Santa Clara through a long-term PPA with Calpine geothermal facilities in Sonoma and Lake Counties beginning in 2025. This contract will deliver up to 50 MW in 2025-2026 and increase to 100 MW in 2027-2036.

According to the International Energy Agency, EGS has many benefits including zero emissions and that it is reliable baseload power that can supplement the intermittent output of renewables. It also has a smaller physical footprint compared to resources such as wind and solar and requires a skill set similar to oil and natural gas workers, providing possible new jobs as those industries transition to a more zero-emissions-based economy.

To advance EGS, IEA recommends increasing funding for EGS research and demonstration projects, providing tax incentives and other financing tools to support geothermal projects, and demonstrating the potential of large-scale geothermal development to the public.

An “enhanced geothermal earthshot analysis” published by the National Renewable Energy Laboratory (NREL) shines more light on EGS, including a 20-percent reduction in drilling costs from GeoVision projections and productivity increases. Regional studies and other sources were used to augment the EGS potential in the western U.S. by NREL. The study projected a total installed geothermal resource of 38.3 GW in 2035 and 90.5 GW in 2050 under the updated assumptions. Geothermal accounts for a little under 2 percent of national generating capacity in 2035 and a little under 4 percent in 2050 due to a high-capacity factor compared to other renewable resources and increased EGS deployment.

The slow pace of geothermal development is in sharp contrast to other zero-emission resources like solar, wind, and battery storage, and a cost gap remains. NREL said the cost of geothermal deployments is affected by which market they are deployed in and varies with time and location due to “variations in demand and the cost and availability of competing technologies.” EGS deployment costs are higher in the eastern U.S. because of fewer and lower-quality resources, thus making EGS deployment in the West easier. The cost of EGS resources varies by location, demand, and the cost of competing decarbonization policies.

Geothermal is poised to play a larger role in U.S. energy production as transitions to zero-emission technologies continue, bolstered by strong regulatory and policy support at the federal level. Perhaps the future will see this resource become more competitive as its potential is continually explored.

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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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