Published: February 14, 2025

How can utilities ensure that the collection of depreciation expense remains accurate without the expense and rigor of a complete depreciation study?

Depreciation guidelines recommend conducting depreciation studies periodically to confirm that the depreciation rates in use remain appropriate, and to recognize the inherent variability in depreciable service lives and net salvage estimates. For these reasons, Concentric recommends that most utilities complete a full depreciation study every three to five years.

Usually, depreciation studies are performed as part of a utility’s rate case. However, there are instances when general rate applications may occur outside the three-to-five-year cycle of depreciation studies. This can create unique challenges in instances where, for example, a significant technological change requires the retirement of the majority of assets in an account or an account has been fully depreciated. The key question then becomes: How can utilities ensure that the collection of depreciation expense remains accurate without undertaking a full depreciation study?

A beneficial alternative for utilities to explore is a technical update or depreciation review. This option allows for the recalculation of depreciation expense based on the assets in service at the time of the update, without re-evaluating the underlying depreciation parameters. In practice, this means that the estimates of average service life and net salvage parameters remain unchanged, while the total depreciation expense is updated to ensure accuracy.

Since technical updates do not require a re-examination of depreciation parameters, they can be completed relatively swiftly and cost-effectively, requiring less labor from the utility. Many utilities choose to perform these updates annually to ensure that the book depreciation reserve aligns with expectations. This proactive approach empowers utilities to quickly identify any emerging issues and resolve questions about the underlying data without the pressure of an impending rate case.

With the significantly lower costs for technical updates, and the subsequent savings that are often realized in full depreciation studies, annual technical updates are highly recommended for many utilities. This strategy is particularly applicable for utilities using the Equal Life Group procedure; however, even those using the Average Life Group procedure typically benefit from annual technical updates.

Why Choose Concentric for your Depreciation Technical Update?

Our depreciation practice has nearly a century of combined technical experience.
Our lead team members are Certified Depreciation Professionals by the Society of Depreciation Professionals.
Concentric staff have successfully completed dozens of technical updates and more than 125 depreciation studies for clients across North America.

To learn more about Concentric’s proactive approach to a Depreciation Technical Update, please contact Amanda Nori.

— All views expressed by the author are solely the author’s current views and do not reflect the views of Concentric Energy Advisors, Inc., its affiliates, subsidiaries, related companies, or clients. The author’s views are based upon information the author considers reliable at the time of publication. However, neither Concentric Energy Advisors, Inc., nor its affiliates, subsidiaries, and related companies warrant the information’s completeness or accuracy, and it should not be relied upon as such.

Published: February 13, 2025

Concentric Energy Advisors and Concentric Advisors ULC are pleased to announce multiple promotions within our team.

We are proud to recognize our colleagues for their commitment to Concentric’s principles and clients as we continue to provide innovative solutions that power an evolving industry.

Mark Cattrell was promoted to Vice President

William (Bill) Davis was promoted to Vice President

Jennifer Nelson was promoted to Vice President

Bickey Rimal was promoted to Vice President

Joseph Weiss was promoted to Vice President

Alexander Cochis was promoted to Assistant Vice President

Marisa Ihara was promoted to Assistant Vice President

Amanda Nori was promoted to Assistant Vice President

Meredith Stone was promoted to Assistant Vice President

Jack Gross was promoted to Senior Consultant

Clara-Ann Joyce was promoted to Senior Consultant

Ryan Kennedy was promoted to Senior Consultant

Riley Burns was promoted to Consultant

Marcus Kim was promoted to Consultant

Sarah Quinn was promoted to Consultant

Jake Levingston was promoted to Senior Analyst

Katherine Judd was promoted to Senior Business Development and Marketing Analyst

Shaizee Vang was promoted to Staff Accountant

Published: February 10, 2025

By Concentric Staff Writer

Key takeaways

The new administration of President Donald Trump is reversing policies of President Joe Biden regarding liquified natural gas, such as a U.S. Department of Energy decision almost a year ago to halt permits for new LNG export facilities, which Trump did away with on his first day in office.
The war between Russia and Ukraine is leading Europe to seek natural gas supplies elsewhere, prodding production in the U.S., where LNG export capacity is set to double with the construction of new export facilities.
U.S. House Republicans and others had resisted the release last month of a U.S. Department of Energy Report saying that increasing U.S. export capacity would drive up domestic prices and increase greenhouse gas emissions.

The dynamics around liquified natural gas (LNG), a major U.S. energy export, have been in flux. We are now observing the impact of President Donald Trump and his immediate reversal of the actions taken by President Joe Biden that froze permits for new LNG export terminals.

Biden’s focus had been on mitigating LNG exports in the name of climate change, while Trump stands in sharp opposition to that viewpoint for the U.S., the world’s number one exporter of LNG.

Trump on Jan. 20 reversed the Biden Administration’s pause on LNG exports with an executive order, part of his “Unleashing American Energy” initiative. The move drew praise from natural gas producers.

“There is the initial positive impact of putting people back to work not only with LNG transport, but with the existing ongoing LNG construction sites that are currently under contract but were paused by Biden, as well as several projects that had been permitted and will now be financed and the construction work allowed to begin,” James Flores, CEO, Sable Offshore Corp., said in an online post promoted by DOE.

Flores said the move would cause a wave of LNG exports that would help balance a trade deficit and strengthen America’s energy security.

Additionally, Trump on Feb. 1 announced a 25-percent tariff on imports from Canada and Mexico and 10-percent on Chinese imports to address what he called “an emergency situation” at U.S. borders posed by “illegal aliens and drugs, including deadly fentanyl.”

Trump then put a 30-day pause on the new tariffs a few days later after public statements from Mexican President Claudia Sheinbaum and Canadian Prime Minister Justin Trudeau that they would bolster border security.

China quickly retaliated with tariffs of its own, including a 10-percent tariff on U.S. coal and LNG, to take effect Feb. 10.

U.S. LNG exports rose since halfway through 2024, according to data from the U.S. Energy Information Administration, rising from 356,423 million cubic feet in June 2024 to 376,065 million cubic feet in November.

The LNG export price also rose during that time, from $6.57 per thousand cubic feet to $6.70 per thousand cubic feet between June 2024 and November 2024, according to EIA.

Biden’s efforts to slow U.S. exports faltered when Judge James Cain of the Western District of Louisiana, a Trump appointee, in July put a stay on the Biden LNG export ban, ruling on a request from 16 states. Cain argued that DOE had ignored the stay’s impact on national security, state revenues, employment opportunities, funding for schools and charities, and pollution allegedly caused by increased reliance on foreign energy sources.

In December, Biden’s DOE released a study saying that large amounts of LNG exports will drive up domestic energy prices and thwart greenhouse gas-reduction goals, including development of wind and solar generation.

Republicans in the U.S. House of Representatives pushed back on both Biden’s moratorium and the study. In February 2024, 150 House Republicans called for Biden to reverse his moratorium, saying it is “economically and strategically dangerous and unnecessary.” Noting that other countries are looking for supplies outside of Russia, the moratorium reduces national security and puts strategic markets at risk, the elected officials said.

“Your administration should do everything it can to encourage greater production of clean-burning and reliable natural gas, and to grant the export permits that allow access to global markets,” a Feb. 4, 2024 letter to Biden from the House Republicans says.

The debate occurs as North America’s LNG export capacity is due to more than double between 2024 and 2028, from 114 billion cubic feet per day (Bcf/d) in 2023 to 24.4 Bcf/d in 2028, based on current construction plans, according to EIA data. Over that period, export capacity is projected to grow by 0.8 Bcf/d in Mexico, 2.5 Bcf/d in Canada, and 9.7 Bcf/d in the U.S. from 10 new projects that are currently under construction in the three countries.

Five LNG export projects with a combined export capacity of 9.7 Bcf/d are under construction in the U.S., including Venture Global’s Plaquemines Phase I and Phase II in Port Sulphur, Louisiana and Cheniere Energy’s Corpus Christi Stage III on the Gulf Coast in Texas, both of which began producing LNG in December.

There are also other LNG projects in the works, including QatarEnergy and ExxonMobil’s Golden Pass, NextDecade’s Rio Grande (Phase I), and Port Arthur (Phase I), all in Texas.

Natural gas is also flowing from the U.S. via the Sur de Texas-Tuxpan pipeline to Mexican floating LNG terminals such as the Fast LNG Altamira and Energía Costa Azul LNG export terminal (0.4 Bcf/d export capacity) in Baja, California in western Mexico. Phase II of the later project is due to expand by 1.6 Bcf/d. Five other projects are proposed on the west coast of Mexico, with a combined capacity of 4.5 Bcf/d, according to the EIA.

In the North, gas from western Canada will supply three proposed projects with a combined capacity of 2.5 Bcf/d in British Columbia on Canada’s west coast. They include LNG Canada (export capacity 1.8 Bcf/d) with a plan to begin LNG exports from Train 1 in the summer of 2025; Woodfibre LNG (export capacity 0.3 Bcf/d) with exports beginning in 2027; and Cedar LNG, the nation’s first indigenous-owned project with a capacity of 0.4 Bcf/d, due to begin exports in 2028. Canada has authorized four other LNG expansion projects with a combined capacity of 4.1 Bcf/d.

The relationship between domestic production, imports, and exports have shifted as the production environment in the U.S. has changed. The shale gas boom of the late 2000s reversed trends and led to efforts to reactivate dormant import facilities, some of which were transferred to export beginning in 2016, according to S&P Global. U.S. export capacity sat at 13 bcf/d in 2024, with exports going to Europe, South America, Asia, and North Africa.

The value of LNG exports has exceeded others such as soybeans, corn, and even movies and television entertainment.

DOE’s study issued in December is intended to “provide an updated understanding of the potential effects of U.S. LNG exports on the domestic economy, U.S. households and consumers; communities that live near locations where natural gas is produced or exported; domestic and international energy security, including effects on U.S. trading partners; and the environment and climate,” the agency said.

There is “inherent uncertainty” regarding the state of U.S. LNG exports through 2050, the study says, which added the effort is not intended to be a forecast but rather explore a range of scenarios. DOE is responsible for authorizing exports of LNG under the Natural Gas Act. By 2050, projections of U.S. LNG exports exceed the export volume from LNG projects in operation or under construction, the agency said.

Globally, the market for LNG has been increasing in recent years and re-gasification and import infrastructure is being built, although future demand is uncertain and centers of demand are shifting, DOE said. Overseas countries include LNG as part of their strategies because it supports dispatchable power generation, often from existing infrastructure, which also leads to their policies driving U.S. export dynamics. Europe has been the primary destination for U.S. natural gas historically.

In Europe, policies reducing the usage of fossil fuels, including natural gas, could come into play, but demand for gas and LNG from Asia is expected to increase. By 2050, China is expected to be the largest LNG importer, according to the DOE study.

In analyzing the economic impact of new LNG projects in the U.S., DOE said, “natural gas production and the development of natural gas export infrastructure tends to increase employment in regions and communities where it occurs, but some evidence indicates that jobs often go to people who either move to the area for the jobs or commute from other areas, rather than to long-term residents.”

The U.S. has been a net exporter of LNG since 2016, when the first export terminal in the lower 48 states began operation. Average annual U.S. nameplate export capacity increased from 1.0 Bcf/d in 2016 to 11.9 Bcf/d in 2023, DOE said.

LNG demand growth in the first half of 2024 was driven by double-digit growth in China and India, but the outlook demand is “fragile,” according to the International Energy Agency. The second quarter of 2024 was marked by slacking global LNG production and price volatility. Asian demand was forecast to push up 2024 global demand by 2.5 percent, IEA said.

“Geopolitical instability represents the greatest risk to the short-term outlook. LNG trade has practically halted across the Red Sea since the start of the year, while Russia is increasingly targeting energy infrastructure in Ukraine, including underground gas storage facilities,” IEA said in its quarterly Gas Market Report.

Asia accounted for about 60 percent of the increase in global gas demand over the first half of 2024, with demand increasing by about 10 percent in both China and India.

Production-wise, global LNG supply growth was a scant 2 percent in the first half of 2024. LNG output fell in the second quarter by .5 percent or .5 billion cubic meters (bcm). This was the first quarter-over-quarter decline since Covid-19 lockdowns crippled LNG demand and caused the cancellation of cargos. Feed gas supply issues and unexpected outages drove production declines in the second quarter. But the expansion of U.S. export capability accelerated LNG supply capability in the second half of 2024.

In North America, residential and commercial demand weakened in the first quarter of 2024 because of unseasonably mild weather, but growth in natural gas-fired power generation offset this. Low gas prices in the early part of the year led U.S. upstream suppliers to cut dry gas output, damping gas production downward by 1.5 percent in the U.S. in the second quarter of 2024.

The war in Ukraine is leading European countries to push to diversify their natural gas supply, spurring interest in new projects such as a $44 billion natural gas pipeline in Alaska that would run between the North Slope and Nikiski, along the shore of Cook Inlet.

State corporation Alaska Gasline Development Corp. is leading an effort to develop the pipeline, recently announcing a contractual agreement with Glenfarne Group LLC, according to Alaska Public Media. The 800-mile project has been in the works for decades with its prospects fluctuating depending on costs and demand dynamics. Gov. Mike Dunleavey said that the Trump administration will be more accommodating to the project compared with Biden.

Background information and cited sources

This article drew on sources such as the U.S. DOE, corporate websites, S&P Global, U.S. House documents, the U.S. Energy Information Administration, the International Energy Agency, and Alaska Public Media.

President Donald Trump Jan. 20 executive order

President Donald Trump Feb. 1 executive order

EIA data: U.S. Natural Gas Exports and Re-Exports by Country

Feb. 24 letter to President Joe Biden from U.S. House of Representatives Republicans

EIA Today in Energy report

U.S. House of Representatives

S&P Global

U.S. DOE Study: Energy, Economic, and Environmental Assessment of U.S. LNG Exports

IEA Gas Market Report Q3-2024

Alaska Public Media article

Published: November 8, 2024

By Concentric Staff Writer

After over-riding its membership, on November 4, the national organization responsible for the reliability of the bulk power grid filed with federal energy regulators a suite of proposed new standards for inverter-based resources (IBRs) such as solar, batteries, and wind, to address problems with these systems in recent years.

On November 4, the North American Electric Reliability Corporation (NERC) made four separate filings to the Federal Energy Regulatory Commission (FERC) related to IBRs. NERC filed a petition for approval of two standards related to IBR ride-through performance during system disturbances (PRC-024-4, PRC 029-1); another requiring analysis and mitigation of IBR performance issues (PRC 030-1); a petition for approval of the proposed definition of the new term “Inverter-Based Resource”; and another establishing requirements of disturbance monitoring requirements for IBRs (PRC-028-1 and PRC-002-5).

“The proposed reliability standards are an integral part of NERC’s proposed framework to address IBR performance issues in a comprehensive and holistic manner,” the organization said in the filing for disturbance monitoring requirements for IBRs. “[T]he proposed reliability standards are part of a set of standards that collectively respond to the Commission’s directives for requirements addressing IBR ride-through settings, ride-through performance, data recording, and analysis and mitigation of unexpected IBR performance,” NERC said.

NERC said there has been widespread loss of generating resources—solar photovoltaic, wind, synchronous generation, and battery storage—across multiple “system events.” For example, the Blue Cut Fire in August 2016 in San Bernardino County, California, and the Canyon 2 Fire in October 2017 in Orange County, California, demonstrated a risk to grid reliability as IBRs were unable to ride-through the events. In 2022, NERC analyzed more than 10 grid disturbances involving widespread loss of IBRs, it said.

FERC in its Order No. 901 [RM22-12], approved in October 2023, had required NERC to file the IBR standards by Nov. 4 of this year. After disagreement among members, the NERC Board of Trustees in October invoked the special authority in order to allow the organization to meet the deadline, it said.

That lack of consensus led a NERC committee during an earlier August meeting to recommend that the board invoke its special authority “to ensure that systemic reliability issues associated with IBRs are addressed in a timely manner,” according to NERC documents.

In the Western Interconnection — the power grid that spans several western U.S. states, Canada, and parts of Mexico —IBRs are on the upswing, but they have introduced a number of challenges to reliability. IBRs lack the physical inertia that is inherent to traditional synchronous resources such as coal, gas, and nuclear, creating problems such as fault-induced delayed voltage recovery. IBRs also have trouble with the frequency response that traditional generation provides to the grid.

NERC’s Board of Trustees at an October 8 technical conference successfully revised the IBR standard, allowing it to be approved under a reduced voting threshold compared to its normal voting procedures. At an August meeting in Vancouver, NERC membership was unable to reach consensus on how stringent the standards should be.

FERC’s Order No. 901 required NERC to file the standards on a three-year staggered time frame. The commission required NERC to file IBR disturbance-monitoring data sharing, post-event performance validation, and ride-through performance requirements by November 4, 2024; IBR data and model validation by November 4, 2025; and planning and operational studies for IBRs by November 4, 2026. The Commission also directed NERC to develop and submit a work plan to develop new and revised reliability standards to address the IBR issues in accordance with that timeframe.

According to minutes from the October 8 NERC technical conference, Board of Trustees member Kenneth DeFontes recommended that the board use the special authority in order to file the standards in compliance with FERC’s November 4 deadline.

“[DeFontes] reported that while much of the hard work of NERC’s stakeholders is paying off, with progress made on important IBR reliability standards through the usual standard development process, NERC does not have a clear path forward on the IBR grid disturbance ride through standard,” the minutes say.

DeFontes said the board must consider its options to meet its regulatory responsibilities but noted that the board “does not consider these options lightly.” He also recommended continued participation by NERC members and industry representatives on the standard.

The board approved a package of Milestone 2 standards for IBR “ride-through,” which refers to the capability of solar, wind, and battery devices to continue operating during temporary disturbances or faults on the electrical grid. Inverters will ride-through the disturbance and remain connected to the grid instead of disconnecting immediately when voltage or frequency deviates from normal ranges.

The Milestone 2 standards were approved under NERC’s Project 2020-02, an initiative to develop and update standards for IBRs. NERC had identified that there was a gap in existing reliability standards, which were developed for traditional synchronous generation resources such as coal, gas, and nuclear.

The goals of Project 2020-02 are to update existing standards such as protection and controls, modeling, data, and analysis to make them more suitable for IBRs. These include requirements for more accurate modeling, performance verification, and coordination of protection systems. The initiative also has the goal of defining and enhancing ride-through requirements to establish clear and consistent requirements for IBRs to ride through system disturbances without tripping off.

NERC also has the goal of ensuring an accurate representation of IBRs in grid models, seen as critical for planning and analysis of operational reliability. This includes requirements for verifying that IBR models reflect their performance in the real world.

NERC’s Project 2020-02 included modifications to the PRC-024-4 standard and the development of the PRC-029-1 standard to initiate its development (frequency and voltage ride-through requirements for inverter-based resources), but the latter standard failed to achieve consensus through the usual standard-development process, NERC said.

The NERC board discussed issues surrounding the FERC Order No. 901 directives, including whether or not the proposed reliability standard PRC-029-1 is “just, reasonable, not unduly discriminatory or preferential, in the public interest, helpful to reliability, practical, technically sound, technically feasible, and cost-justified,” according to a NERC memorandum.

On Jan. 17, NERC also submitted its Order No. 901 work plan, which consists of key milestones to meet the FERC directives by the filing deadlines. The Milestone 2 standards, in progress, focus on the development of reliability standards to address disturbance monitoring, performance-based ride-through requirements, and post-event performance validation for registered IBRs by the Nov. 4 deadline.

While Project 2020-02, which addressed generator ride-through directives from FERC Order No. 901 had created controversy, Projects 2021-04 and 2023-02 are on track for timely completion through the usual NERC standard development process, the memorandum says.

FERC’s Order No. 901 cited multiple reports of events with IBRs as the reason NERC should have reliability standards for ride-through frequency and voltage system disturbances. The standards should permit tripping of IBRs only to protect the IBR equipment in scenarios similar to when synchronous generation resources use tripping as protection from internal faults, FERC said. Exceptions should be applied to certain IBRs, and finding consensus around those directives was a part of the main issues addressed during the technical conference, according to NERC.

FERC said NERC must require registered IBRs to continue to perform frequency support during any bulk-power system disturbance and that any new or modified reliability standard must also require registered IBR generator owners and operators to prohibit momentary cessation in the no-trip zone during disturbances.

Under FERC’s order, NERC was required to submit new or modified reliability standards that establish IBR performance requirements, including requirements addressing frequency and voltage ride-through, post-disturbance ramp rates, phase lock loop synchronization, and other known causes of IBR tripping or momentary cessation.

“Therefore, we direct NERC through its standard development process to determine whether the new or modified reliability standards should provide for a limited and documented exemption for certain registered IBRs from voltage ride-through performance requirements. Any such exemption should be only for voltage ride-through performance for those existing IBRs that are unable to modify their coordinated protection and control settings to meet the requirements without physical modification of the IBRs’ equipment,” FERC said in the order.

During deliberations among NERC members, many argued that the proposed PRC-029-1 definition was too broad and ambiguous, particularly the inclusion of phrases like “entire” and “in its entirety,” when referring to a generating plant or facility. Those parties recommended revisions to clarify the definition and ensure it aligns better with Institute of Electrical and Electronics Engineers Standard 2800, which covers interconnection and interoperability of IBRs, and interconnection with associated transmission systems.

Project 2020-02 will enhance reliability by requiring entities to perform energy reliability assessments to evaluate energy assurance and develop corrective action plans to address identified risks, NERC said. These energy reliability assessments should evaluate energy assurance across operations planning, near-term transmission planning, and long-term transmission planning or equivalent time horizons by analyzing the expected resource mix availability and flexibility and the expected availability of fuel during the study period.

According to NERC, IBRs are still being designed and installed without setting their protection and controls in accordance with their physical capabilities.

NERC had solicited comments from the industry as well as original equipment manufacturers on any information on hardware-based limitations that would prevent IBRs from meeting the proposed frequency criteria within PRC-029-1. The organization said 21 individual comments were received, including six from different original equipment manufacturers of IBRs. There were concerns that a draft of PRC 029-1 proposed frequency criteria that went beyond those established in IEEE 2800-2022 and there was a concern that IBR operators would not be able to meet those proposed frequency criteria, as IBR capability limits were hardware-based and inherent to manufacturer design.

Though the organization had failed to reach consensus among its members on some of the standards, the filing of NERC’s new standards will hopefully address the issues with IBRs that have raised their head in the Western Interconnection in recent years.

—

All views expressed by the contributors are solely the contributors’ current views and do not reflect the views of Concentric Energy Advisors, Inc., its affiliates, subsidiaries, or related companies. The contributors’ views are based upon information the contributors consider reliable at the time of publication. However, neither Concentric Energy Advisors, Inc., nor its affiliates, subsidiaries, and related companies warrant the information’s completeness or accuracy, and it should not be relied upon as such.

Published: 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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