Affordability, Technology Costs, and Political Will Are Primary Challenges to the Energy Transition, Concentric Experts Say

Published: April 12, 2024

By: Concentric Staff Writer

Part 1 of a 3-Article Series

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.

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.

National Reliability Officials Recommend Study of Additional Natural Gas Infrastructure to Maintain Reliability in Severe Cold

Published: February 27, 2024

By: Concentric Staff Writer

National reliability officials recommended a study of whether additional natural gas infrastructure, including new interstate pipelines and storage, is needed to maintain electric grid reliability in severe cold, among the lessons learned from Winter Storm Elliott that occurred in December 2022.

The study of additional infrastructure to support natural gas local distribution companies (LDC) was among the recommendations in the Joint Report on Winter Storm Elliott, which analyzed the severe cold weather event that took 1,700 generation units offline in the Eastern Interconnection. The report was jointly issued by the North American Electric Reliability Corporation (NERC), an industry-based group responsible for creating and enforcing national reliability standards, and the Federal Energy Regulatory Commission (FERC), an agency tasked with enabling reliable, safe, and economic energy service for U.S. consumers.

The NERC/FERC report recommends that an independent research group, such as national laboratories from the U.S. Department of Energy, should study possible infrastructure build-out as well as the associated costs.

“The purpose of the study would be to identify additional natural gas infrastructure needs, if any, needed to ensure the continued reliability of the electric and natural gas systems, and the preferred locations of such infrastructure, if applicable, including pipeline infrastructure, natural gas storage, and other supporting systems,” the report says. The study should also consider the needs in light of coincident peaks of LDC demand for natural gas for heating, as well as for demand from natural gas-fired power plants during long periods of abnormally cold weather, officials said.

“The study should analyze needs on a regional basis and consider current as well as forecast future needs, in light of our evolving and interdependent energy,” the report says. It should also look at whether there will be adequate natural gas infrastructure to accommodate the intermittence of new renewable energy resources and retirement of thermal generation resources, as well as recent patterns of natural gas production declines during severe weather events.

Other recommendations in the joint report include “prompt development and implementation” of revisions to reliability standards to strengthen generators’ performance during extreme cold weather; identification of generation units that are at the highest risk of problems in cold weather; assessments of freeze protection measure vulnerability; and engineering design reviews of units that have experienced cold weather outages. Also recommended is the identification of root causes of generation failures and a NERC/FERC study of the overall availability of “black-start” resources—units that can return to service quickly after a complete or partial shut-down.

Winter Storm Elliott, which plunged 18 percent of the Eastern Interconnection into outages, was just one of a series of major cold weather outages that struck the U.S. in recent years. While Elliott was the largest load shedding event in the Eastern Interconnection, the largest single such event was Winter Storm Uri in February 2021, which caused 20 gigawatts (GW) of load shedding by grid operators, mainly in Texas, and took out power for 4.5 million people, causing hundreds of deaths.

But the joint FERC/NERC report on Winter Storm Elliott points out that the situation in Texas during Winter Storm Uri and nearly a year later in the East during Elliott involved very different grids. What is more surprising is that the Winter Storm Elliott outages occurred in the highly connected Eastern Interconnection, unlike Texas, which has a grid almost completely isolated from both the Eastern Interconnection and Western Interconnection.1

“The quantity of firm load shed during Winter Storm Elliott was not as large as in the Winter Storm Uri event, but it is especially disconcerting that it happened in the Eastern Interconnection which normally has ample generation and transmission ties to other grid operators that allow them to import and export power,” the report says.

Winter Storm Elliott was characterized as both a bomb cyclone and an extra-tropical cyclone, moving from Upper Plains states in late December 2022, and hitting the East Coast on December 23 and 24. The cold and outages coincided with a spike in electricity usage causing many balancing areas in the East to declare energy emergencies (EEA). The 90.5 GW of unplanned outages stretched from Georgia to the Canadian border in the East and across the central U.S.

Similar to Uri, Elliott froze up natural gas system wellheads and other equipment, while the weather made maintenance and response impossible, leading to significant declines in natural gas production. There were reductions in gas pipeline pressure and 14 declarations of force majeure—unforeseen events that affect shippers’ ability to deliver gas on pipelines. Eight of 15 interstate pipelines queried for the report said there were 53 instances of power loss at facilities, totaling almost 467 hours. Outages averaged a few hours, although some went on for several days.

In the Northeast, pipeline operators reduced flows to other regions during Elliott and increased imports from Canada, while in the Southeast they increased outflows to the Midwest, decreased liquified natural gas (LNG) exports, and saw access to Northeast supply throttled. The Northeast in recent years has increased its production of natural gas, which normally leads to typical outflows of about 12.5 billion cubic feet per day (Bcf/d), but which were reduced to about 5.3 Bcf/d.

There were also some close calls. On the morning of December 24, Con Edison began experiencing drops in pipeline pressure and declared a gas system emergency, which included implementing specifications for curtailing users and reactivating an LNG regasification plant. Con Edison was in danger of cutting off some or all of its system users; even an outage of about 130,000 customers would have taken five to seven weeks to restore depending on the availability of mutual aid.

“Had it lost the majority of its system, over a million customers in New York City and nearby areas would have been unable to heat their apartments and houses while the outside temperature was in the single digits, for months,” the joint report says.

Outages at generation units are divided into broad categories in the report, including mechanical and electrical issues such as equipment failures, which formed 72 percent of these problems, and control system issues, which accounted for 12 percent. No other single sub-cause materially contributed to lost generation, the report says. Generators lost power as the coldness increased, including situations where generator gas or oil temperature became too low, metal components shrank, and oil viscosity in wind generators increased. The report notes that “a substantial majority” of generation units that reported freezing issues were operating at temperatures that were above the documented operating temperature requirements.

On December 24, 2022, gas production in the lower 48 states dropped to a low of 82.5 Bcf/d, a 16 percent decrease from December 21. The greatest declines in gas production were in the Marcellus and Utica shale formations. Generation outages began in the territory of the Southwest Power Pool (SPP) and MidContinent Independent System Operator (MISO). Neither regional transmission organization had to shed load, but SPP twice curtailed non-firm exports on December 23 because of lower reserves, and MISO and SPP began coordinating on regional directional transfer limits.

MISO declared an EEA 1 and EEA 2 on December 23. Tennessee Valley Authority (TVA) saw a rapid increase in generation unit outages early on December 23 and had lost 5 GW of generation by 6 a.m., causing it to declare EEA 1 and EEA 2. TVA began obtaining emergency power from Duke Energy, Southern Company, the PJM Interconnection, and MISO, but “this solution was short-lived,” the report says. These factors caused TVA to order firm load shed of 1,500 MW, about 5 percent of its system peak load.

Impacts on grid reliability due to cold weather are nothing new, and NERC has repeatedly warned of the risk. For instance, NERC and FERC in August 2011 issued a detailed joint analysis of an outage in Texas in February of that year that affected 1.3 million customer accounts, the “2011 Southwest Cold Weather Event.” 2 In an event similar to Winter Storm Uri that would occur a decade later, more than 4.4 million customer accounts were affected between February 2 and February 4, 2011, an event that also saw extreme natural gas delivery curtailments that were longer than electric customer outages because gas-fired equipment had to be relit.

More than 50,000 gas customers were affected in the 2011 outage, including more than 30,000 in New Mexico, along with customers in Arizona and Texas. That year, FERC and NERC launched a joint task force to inquire about the outages.

NERC and FERC listed capacity awareness, gas and electricity interdependency, transformer oil issues during cold weather, air duct icing, wind farm winter storm issues, rotational load shed, transmission facilities, and other factors as “lessons learned” from the 2011 Southwest Cold Weather Event.

In the joint NERC/FERC report issued in August of 2011, recommendations included that balancing authorities, reliability coordinators, transmission operators and generation owners and operators, in Texas and the Southwest view preparedness for winter as important as preparing for summer.

“The large number of generating units that failed to start, tripped offline, or had to be derated during the February event demonstrates that the generators did not adequately anticipate the full impact of the extended cold weather and high winds,” NERC and FERC said in the 2011 report. “While plant personnel and system operators, in the main, performed admirably during the event, more thorough preparation for cold weather could have prevented many of the weather-related outages.”

In a July 2013 report on previous cold weather events stretching back to 1983, NERC described six previous cold weather events in 1983, 1989, 2003, 2006, 2008, and 2010. There were also five cold weather experiences that caused operational challenges in February 1989, January 1994, January 2004, February 2006, and January 2007.

NERC and FERC said there were only three events that were comparable to the February 2011 Cold Weather Event in terms of load loss and generation outages. Those occurred in December 1983, December 1989, and January 1994.

In all the above events, however, there were two common themes observed: constraints on natural gas supply to power plants as well as generating unit trip-offs, derates, or failures to start due to cold weather due to problems like frozen sensing lines.

The first time ERCOT implemented load shedding region-wide was on December 21–24, 1989, when the grid operator shed 1.7 GW of firm customer load and curtailed natural gas supplies to generation units. The demand peak that occurred on December 22, 1989 was 12.4 percent above what was forecast. The temperatures during the 1989 cold weather event were the lowest in more than 100 years.

During those same days in December 1989, Florida also experienced extremely cold weather, which led to the curtailment of natural gas supplies. Record load of 34.7 GW due to the cold, combined with numerous generation units that were offline for maintenance, resulted in rolling blackouts of five to eight hours maximum. In both Texas and Florida, “the circumstances, size, geographic area, and impact on the bulk power system (BPS) of this event were deemed to be very similar to the February 2011 Cold Weather Event.,” NERC said.

NERC identified several familiar issues regarding the two incidents, including inadequate cold weather preparation, frozen ancillary plant equipment, fuel oil problems, and natural gas delivery curtailments. There were “numerous recommendations” for utilities in Florida and Texas, and certain corrective actions were undertaken by utilities.

NERC in the 2013 report said that common issues in the cold weather include the interdependence of the natural gas and electric systems, which continues to grow. Compressors used in the production and transportation of natural gas require electricity to operate.

Also, most generators purchase “non-firm” capacity, exposing them more to curtailments when supplies are tight, and there is competition between natural gas supply for electricity and natural gas for heating.

The cold weather outages that have struck the U.S. over the years have led to the development of cold weather reliability standards, which were issued by FERC in February 2023. The standards were developed from recommendations flowing from the joint inquiry into Winter Storm Uri to prevent such widespread outages from occurring again. NERC proposed the standards in October 2022, which include generator freeze-up protection measures, enhanced cold-weather preparedness plans, identification of freeze-sensitive equipment in generators, corrective actions for equipment freeze-ups, annual training for generator maintenance and operations personnel, and procedures to improve the coordination of load reduction measures during a grid emergency.

The FERC order implemented about half of the recommendations from the Winter Storm Uri FERC/NERC joint inquiry, and NERC is developing a second phase of the standards.

Though overall usage of natural gas for power generation might decline because of the transition to renewable energy such as solar and wind, the necessity of gas to balance the system against intermittent renewables could increase, the American Gas Association (AGA) said in a 2021 report entitled “How the Gas System Contributes to US Energy System Resilience.” But the current compensation model for gas is tied to the volume of gas delivered to power plants, which creates a disconnect between the value of the service and its compensation.

Natural gas infrastructure and replacement programs were designed to enhance reliability and safety, and have also contributed to “resilience,” defined as “as a system’s ability to prevent, withstand, adapt to, and quickly recover from system damage or operational disruption. Resilience is defined in relation to a high-impact, low-likelihood events.” The most common events that require a resilient grid are extreme weather events, the AGA report says.

The resilience needed to meet these challenges will be accomplished “through a diverse set of integrated assets,” the report says, adding that policies need to focus on optimizing the characteristics of both the electric and gas systems.

“Ensuring future energy system resilience will require a careful assessment and recognition of the contributions provided by the gas system,” the report says. “Utilities, system operators, regulators, and policymakers need new frameworks to consider resilience impacts to ensure that resilience is not overlooked or jeopardized in the pursuit to achieve decarbonization goals.”

Aside from the need for more natural gas system infrastructure for energy grid reliability and resilience, new pipelines are under construction to transport gas for export. There is more than 20 million Bcf/d of natural gas pipeline capacity under construction, partly completed or already approved to deliver gas to five liquefied natural gas export terminals that are under construction on the Gulf Coast, according to the U.S. Energy Information Administration.

FERC recently recognized the need to expand the natural gas system, approving in October a request by Gas Transmission Northwest LLC (GTN) to build and modify gas compressor facilities in Idaho, Washington, and Oregon (CP22-2).

“The proposed project will enable GTN to provide up to 150,000 [dekatherms per day] of firm transportation service on its existing system for delivery into Idaho and Pacific Northwest markets. We find that GTN has demonstrated a need for the GTN Xpress Project, that the project will not have adverse economic impacts on existing shippers or other pipelines and their existing customers, and that the project’s benefits will outweigh any adverse economic effects on landowners and surrounding communities,” FERC said in the order.

Another topic that has arisen in the wake of the outages is the need for reliability standards for the gas system, similar to what is in place for the electric system.

When FERC and NERC issued the final report on Winter Storm Elliott, FERC Chairman Willie Phillips in a written statement said: “I want everyone to take time during this Reliability Week to read this report and begin implementing these recommendations, particularly those addressing the interdependence of gas and electricity. The report highlights what I’ve called for before: Someone must have authority to establish and enforce gas reliability standards.”

NERC President and Chief Executive Officer Jim Robb said that the industry needs to implement the recommendations from the joint report as soon as possible.

“I echo the Chairman’s call for an authority to set and enforce winterization standards for the natural gas system upstream of power generation and local distribution,” Robb said in a written statement. “The unplanned loss of generation due to freezing and fuel issues was unprecedented, reflecting the extraordinary interconnectedness of the gas and electric systems and their combined vulnerability to extreme weather.”

 

1The three main components of the U.S. electric grid are the Eastern Interconnection, the Western Interconnection, and ERCOT.

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

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.

Trusted Expert in Wholesale Market Design Joins Concentric

Published: February 22, 2024

Concentric Energy Advisors, Inc. (“Concentric”), a recognized leader in management consulting services to the North American energy and water industries, continues to expand its executive-level expertise with the strategic hire of Mr. Mark G. Karl as an Executive Advisor. 

Mr. Karl brings over four decades of energy industry experience, with an extensive history of operations in the wholesale electric market from design to implementation, including resource adequacy. Before joining Concentric, Mr. Karl spent over 20 years at ISO New England, where he served as the Vice President of Market Development. In that role, Mr. Karl held executive-level responsibility for the design, development, and implementation of all changes to the wholesale electricity markets operated by ISO New England. He oversaw the entire process from inception to implementation, including stakeholder and regulatory processes as well as operations and settlements. Mr. Karl also held leadership positions in Resource Adequacy, Market Development and Integration, and Market Design. 

“Mark is a great addition to our team. His experience at ISO New England was instrumental in designing markets to accommodate decarbonization strategies, and how those markets will evolve in the future,” said Danielle Powers, Chief Executive Officer of Concentric. “Our clients will receive a tremendous benefit from Mark’s expertise.” 

Economic Trends Shift Canadian Utility ROEs

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.

 

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.

Concentric Energy Advisors Welcomes Clean Energy Strategy and Policy Expert

Published: February 5, 2024 

Concentric Energy Advisors is proud to announce that Mr. Stephen B. Wemple has joined Concentric as a Vice President.

Mr. Wemple comes to Concentric with over 30 years of experience in the energy industry. As a former senior energy executive, he has a wealth of knowledge in utility regulatory affairs and has successfully implemented both utility-scale and distributed clean energy strategies. Mr. Wemple’s expertise also extends to green hydrogen, battery storage, transmission scheduling, and wholesale and retail energy trading. “The Concentric team is at the forefront of the diverse challenges facing the energy industry, and I look forward to helping our clients successfully navigate the clean energy transition,” said Mr. Wemple.

Danielle Powers, Chief Executive Officer, and Daniel Dane, President & Vice-Chair, jointly expressed their excitement in welcoming Mr. Wemple. “We are very enthusiastic to have Steve join our team. As the energy industry continues to evolve, the solutions become more nuanced, requiring multi-faceted expertise. Steve’s background in regulatory affairs and clean-energy implementation strategy align with our mission of providing experienced and trusted experts to serve a changing industry.”

 

Concentric Energy Advisors and Concentric Advisors ULC Announce 2024 Team Member Promotions

January 24, 2024—Concentric Energy Advisors, Inc., and Concentric Advisors ULC (together known as “Concentric”), recognized leaders in management consulting services to the North American energy industry, congratulate their recently promoted team members.  

Melissa Bartos was promoted to Senior Vice President and has joined Concentric’s Board of Directors. Melissa leads Concentric’s natural gas planning practice and applies her quantitative, stakeholder engagement, and analytical competencies to developing long-term gas plans. She is highly regarded in the energy industry for her leadership and communication skills. 

Peter Blazunas was promoted to Assistant Vice President. Peter is an expert witness providing regulatory strategy and rate case expertise, including multiyear rate plans and future of energy initiatives.  

Briana Adams and Colin Burns were promoted to Senior Project Managers. Briana has over a decade of energy industry experience focusing on cost of capital issues, asset valuation, and grid modernization. Colin has over 20 years of experience as a depreciation expert conducting studies for clients across the U.S. and Canada.  

Kelly Porter was promoted to Project Manager. Kelly has extensive experience working with regulated utility rates and tariffs, specializing in cost-of-service studies, utility pricing, and regulatory strategy.  

Bryan Hu and Tara Mou were promoted to Senior Consultants. Bryan is skilled at developing forecast models regarding return on equity, revenue requirements, and the quantification of impacts associated with various regulatory initiatives. Tara’s experience includes regulatory engagements concentrating on energy efficiency, strategic planning, and utility rate case support.  

Jack Gross, Ryan Kennedy, and Nolan Souza were promoted to Consultants. Jack has experience in regulatory strategic planning, rate case preparation, grid modernization initiatives, and forecast model development related to electrification and default service pricing. Ryan assists in preparing depreciation studies and statistical modelling for clients across the U.S. and Canada. Nolan has assisted in developing revenue requirements and lead-lag studies for investor-owned utility multiyear rate plans.  

Riley Burns, Declan McCarthy, Sarah Quinn, and Somann Rauf were promoted to Senior Analysts. Riley has contributed her analytical skills and educational background in mathematics to engagements related to resource planning and ratemaking proceedings. Declan has been involved with engagements related to utility rate strategy, future of energy initiatives, and financial due diligence. Sarah has worked closely on regulatory engagements covering strategic decarbonization planning and future of energy proceedings. Somann is a member of the depreciation practice and specializes in research and data analysis to support utility depreciation studies.  

Tess Arsenault and Jillian Barrile were promoted to Senior Project Assistants. Tess is a member of Concentric’s depreciation practice and assists with depreciation reports. Jillian is respected for her detailed work product, organizational skills, and streamlined workflows.  

Nick Duquette, Anna Martinez, and Kelly Moore have all been promoted to various senior positions. Nick is now a Senior IT Support Technician responsible for procuring, maintaining, and troubleshooting IT systems, applications, and hardware. Anna was promoted to Senior Accountant II and manages many of Concentric’s billing processes and assists with various tax and compliance requirements. Kelly was promoted to Senior Accountant and manages Concentric’s payroll processes and employee expense approvals.  

“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,” said Danielle Powers, Chief Executive Officer, and Daniel Dane, President & Vice-Chair, in a combined statement. 

First Enhanced Geothermal System in the U.S. Showcases an Ancient Technology with Modern Potential, But Obstacles Persist

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 (GWe) 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 GWe 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 (GWth), 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.

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.

NERC Report Points to Challenging Conditions Across U.S. This Winter

By: Concentric Staff Writer

Published: November 28, 2023

This winter could be a difficult season for the bulk electric system across large portions of the United States, according to national reliability officials.

Memories and lessons from extreme weather events such as winter storms Uri and Elliott—in 2021 and 2022 respectively—linger for industry and regulators due to electric grid failures and all that followed. And there is much evidence that the U.S. grid is not adequately equipped for the upcoming frigid conditions of winter.

A new report from the North American Electric Reliability Corporation (NERC) says that a large swath of the grid across the country is at risk of short electricity supplies this winter, particularly power plants fueled by natural gas. Natural gas freeze-ups have plagued systems from the Northeast to Texas in recent years, as was the case during polar vortexes and other events such as Winter Storm Uri in February 2021.

NERC’s Winter Reliability Assessment noted that in recent years more than 20 percent of U.S. generating capacity has been forced offline during winter reliability events when severe cold hits areas that don’t usually have it.

The natural gas production, transportation, and storage system, along with a large part of the electric grid, are a “single interconnected energy delivery system” extending from the natural gas wellhead to the end-use electricity customer. Natural gas supplies are key to the operation of this system, while electricity likewise has an impact on the compressors and other critical equipment. Meanwhile, disruptions to these systems can have “devastating” effects on the public, as demonstrated in the winter storms Elliot and Uri, when freeze-ups paralyzed mechanical and electric systems, the report says.

The areas at greatest risk encompass a large part of the U.S. including the Midcontinent Independent System Operator region covering 15 states; the 14-state PJM Interconnection region in the Mid-Atlantic; New England; the SERC region in the Southeast covering 16 south and southeastern states; the Southwest Power Pool region covering all or portions of 11 states in the central part of the country; The Electric Reliability Council of Texas; the Canadian provinces of New Brunswick, Nova Scotia, Manitoba, Saskatchewan, Quebec; and parts of Maine.

The crux of the matter is that reliability is threatened, and conditions are most challenging when the temperatures are low, demand is high, and people head inside to use electricity and heat. Natural gas is a necessary element to keep the electric system operating due to its critical role in power plant operation and heating, but the flow of gas is subject to many complications.

“Fuel assurance is vitally important to meeting winter electricity demand across North America. Natural-gas-fired generator availability and output can be threatened when natural gas supplies are insufficient or when the flow of fuel cannot be maintained,” NERC said in the report. “During Winter Storm Elliott, natural gas production rapidly declined with the onset of extreme cold temperatures, contributing to wide-area electricity and natural gas shortages.”

The blizzards, winds, snow, and low temperatures during Winter Storm Elliott hit the majority of the U.S. and portions of Canada, plunging millions into outages and causing dozens of deaths. The event was marked by widespread outages of natural gas-fired generation. Outages also affected wind, coal, solar, nuclear, and other resources such as hydroelectric and biomass.

Regarding this winter, in New England, there is concern as to whether there will be sufficient resources for extreme cold, given the existing generation mix, fuel delivery infrastructure, and expected fuel arrangements, NERC said. This is despite considerable effort to replenish stored fuels such as fuel oil and liquified natural gas.

ISO-New England is offering fuel security incentives such as “The Inventoried Energy Program,” which is voluntary and is designed to pay parties that maintain energy for their assets during periods of extreme cold when winter energy security is most stressed.

A cold-weather event leading from the Mid-Atlantic (PJM) to southern areas (SERC-East and SERC-Central) could lead to energy emergencies, the report says. This is due to forced outages of generators and spiking demand, which has risen in recent years while there has been little change in resources since Winter Storm Elliott. There are adequate resources for normal conditions but less so for extreme conditions, NERC said.

The U.S. West, stretching from the Rocky Mountains to the Pacific Ocean, is seen as having adequate supply when winter temperatures hit, but there could be a shortage of 10 GW during peak demand in the Northwest under certain conditions, such as high demand paired with generator outages and low hydroelectric output.

In the Western Electricity Coordinating Council (WECC), resources are expected to be adequate, but this region is among those that have peak electricity demand in summer, when air conditioning surges. WECC’s region includes all or portions of 14 western U.S. states stretching from the Canadian border to Mexico, including California.

In the Northwest, there is some risk this winter under certain scenarios in a region that has been “mixed-season peaking” according to NERC. Power is expected to be adequate in peak demand hours under all conditions other than an “extreme combined scenario,” which would require 5.3 GW of imports in certain peak load scenarios. The level of imports is expected to be adequate, depending on conditions in surrounding areas.

In Texas, the threat of continued cold weather continues in areas where infrastructure has not been retrofitted for extreme cold. There has also been robust load growth in Texas that is not being met with the expansion of dispatchable resources. ERCOT is taking steps, including a new fuel supply service that is intended to supplement natural gas capacity during energy emergencies.

In MISO’s territory, new wind and natural-gas generation has been installed, and the lives of older fossil-fuel plants extended. MISO implemented a seasonal resource adequacy construct to more effectively evaluate risks and resources according to variances at different times of the year.

The Southwest Power Pool has an anticipated reserve margin of 38.8 percent, about 30 percentage points lower than last winter, driven by higher peak demand and fewer resources. Normal forecast peak demand and expected outages are expected to be covered, but extreme weather could cause energy emergencies.

The NERC report includes a series of recommendations—reliability coordinators, balancing areas, and gas system transmission operators should review seasonal operations plans and protocols for communicating potential supply shortfalls in anticipation of generator outages and extreme demand. These same entities should implement “essential actions” identified by NERC in its Level 3 alert, dubbed “Colder Weather Preparations for Extreme Weather Events-III” and undertake recommended weatherization steps prior to the winter season.

Balancing areas should also be aware of the potential for short-term forecasts to underestimate the electrical load that could occur during cold-weather events and be prepared to take early action to manage deficiencies in electric supply reserves. Reliability coordinators and balancing areas should also implement generator fuel surveys to monitor fuel supplies and should prepare for potential supply shortfalls that could affect the readiness of power plants and other generation sources, the availability of fuel, load curtailment, and the ability for sustained operations during extreme cold.

State and provincial regulators should also assist grid operators before and during extreme cold, such as supporting environmental and transportation waivers and issuing appeals to the public to reduce gas and electricity usage.

There have been five cold-weather events that jeopardized electric grid reliability, triggering generation outages in the cold, sometimes requiring the shedding of load—cutting off electricity grid customers. During both winter storms Elliott and Uri, large swaths of the thermal generation fleet went offline.

“What has become clear is that the natural-gas-electric system has now become fully interconnected, each requiring the other to remain reliable (i.e., impacts on one system can impact the other),” NERC said. “These considerations should drive higher levels of coordination to ensure sustained reliable operation of this interconnected system.”

Complicating the picture for natural gas is the fact that infrastructure problems can affect the flow of fuel and production declines can occur even in areas where cold weather happens often. These problems are made more severe when cold occurs across large areas, spurring demand from local distribution companies and gas-fired generators.

Another factor is coal supplies for coal-fired power plants. Issues with rail transportation of coal have subsided as of the 2022-2023 winter season, but other complications could surface this winter. Drought conditions that affected the Missouri River and other waterways could restrict the transport of coal, and low water levels could impact generators that rely on water for once-through-cooling methods.

Extreme temperatures can also affect demand forecasting, which is essential for the reliable operation of the electric system, NERC said. Load forecasts are key inputs for resource-adequacy planning, coordination of seasonal outages, and day-ahead and real-time operational plans. The interaction of cold-weather patterns and the effect on end users are some of the most challenging issues, adding to winter reliability risk.

There can also be a wide range of demand in peaking areas from one year to the next, NERC said, adding that load forecasts for normal peak demand reflect the highest expected system load for an average winter.

In the MISO region, a list of measures, including load-modifying resources, non-firm energy transfers, energy-only resources, and certain internal transfers, are expected to maintain reliability. Extremely cold weather shows how critical resource adequacy and proper planning are necessary for all seasons, not just the summer, NERC said.

Generator fuel supplies are at risk during extended cold-weather periods, NERC said, a vitally important issue across the entire country.

Attempts to forecast load are getting more complex, and underestimating demand causes risks to reliability. Meanwhile, more irregular weather patterns such as strong winds, cold fronts, and precipitation can cause electricity demand to deviate significantly from forecasts. There may also be curtailment of energy transfers in periods of high energy demand. Reliability coordinators and balancing areas might curtail transfers for various reasons, but curtailments might alleviate an issue in one area while causing supply shortages or system issues in other areas.

The NERC Board of Trustees in June 2021 implemented new reliability standards that will be in place this winter, designed to increase coordination between system generators and operators. Other standards have been put in place flowing from the “FERC-NERC-Regional Entity staff report—The February 2021 Cold Weather Outages in Texas and Southcentral United States.” Approval by the NERC board will lead to filing with regulatory authorities and then industry implementation.

NERC surveyed the industry and found that winter preparations are on a “positive trend”, but freezing weather still causes concern. NERC has issued alerts to enhance readiness and reduce risk for the upcoming winter. Generation owners have taken steps to prepare their facilities to operate at extreme temperatures, but failures from past weather events are a concern. These include “improper heat tracing, frozen instrumentation and control equipment, generator circuit breaker tripping in low temperatures or low air pressures, and wind turbine blade icing,” NERC said.

NERC’s new assessment is ringing the alarm bells on electric grid reliability this winter but also offers solutions to what is expected to be another grueling test for the U.S. electricity grid.

NERC’s report offers reliability evaluations for each portion of the country: MISO: MRO-Manitoba Hydro; MRO-SaskPower; NPCC-Maritimes; NPCC-New England; NPCC-New York; NPCC-Ontario; NPCC-Québec; PJM; SERC-East; SERC-Central; SERC-Southeast; SERC-Florida Peninsula; SPP; Texas RE-ERCOT; WECC-Alberta; WECC-British Columbia; WECC-California/Mexico; WECC-Northwest; WECC-Southwest.

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

Global Zero-Emission Goals Require New Levels of Investment, Build-Out, IEA Says

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.”

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.

 

Concentric Energy Advisors Welcomes Leading Utility Economist  

Concentric is pleased to welcome Mr. Steven Wishart to the team as an Assistant Vice President. 

Steve joins Concentric after spending two decades with Xcel Energy in Minneapolis and Denver, serving as Director of Resource Planning and Bidding for Northern States Power and as Director of Pricing and Regulatory Analytics for Public Service Company of Colorado. In these roles, Steve led decarbonization efforts in the upper Midwest and innovated retail rate design in Colorado.  

“I am very impressed with the leadership, knowledge, and professionalism of the Concentric team,” he stated regarding his new position. “Their expertise, collaboration, and insight provided to clients is unparalleled in the energy industry. I am privileged to join this respected team and contribute to their excellent standard of client service.” 

Steve is a leading utility economist and experienced testifying expert who has appeared in over thirty-five regulatory proceedings. His diverse experience includes demand side management, nuclear relicensing, renewable energy development, pipeline safety investments, innovative class cost allocation, time of use and dynamic rate design, economic development programs, performance-based rate making, transportation electrification, and decarbonization of natural gas utilities.  

“We are pleased to welcome Steve to Concentric,” said John J. Reed, Chairman and Chief Executive Officer of Concentric, “he brings extensive experience in decarbonization, regulatory strategy, and rate design, leveraged with industry-leading data analytics. We are excited to offer his expertise to our clients.”  

In 2023, Steve was the Chairperson of the Edison Electric Institute’s Rates & Regulatory Affairs Committee. He is a graduate of the University of Arizona with a bachelor’s degree in finance and a master’s degree in economics. He has completed the coursework for a doctoral degree in applied economics from the University of Minnesota. 

 

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