Published: February 27, 2024
By: Concentric Staff Writer

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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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 6, 2024

Overview:

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

Figure 1: Bank of Canada Overnight Rate

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

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

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

Summary of Recent Decisions:

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

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

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

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

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

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

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

Pending Cases:

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

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

Table 1: Canadian Electric Utilities

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

U.S. Electric Utility Avg²	51.6%	9.66%

Table 2: Canadian Gas Distribution Utilities

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

U.S. Gas Utility Avg³	52.3%	9.57%

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

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

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

³ Ibid.

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Published: January 24, 2024
By: Concentric Staff Writer

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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By: Concentric Staff Writer

Published: November 9, 2023

The International Energy Agency (IEA) is exploring different scenarios to reach global targets for greenhouse-gas emission reductions, performing detailed new research on the unprecedented level of build-out and investment that would be needed.

Larger, more robust, and smarter electric grids will be needed worldwide to transition modern societies to clean energy from fossil fuels, but the pace of growth needs to accelerate substantially, according to the new IEA report. The importance of electricity grids is growing, with major transitions happening, such as renewable energy, electric vehicles (EVs), and electric heating, IEA said in the report, “Electricity Grids and Secure Energy Transitions.” The report is meant to take stock of the world’s grids as they now stand and assess any signs that grids are not keeping pace with the new global energy economy, as well as analyze scenarios to meet zero emissions. There is a danger that grids will be bottlenecks to future efforts to move to clean energy and create energy security, the researchers said.

“Clean energy transitions are now driving the transformation of our energy systems and expanding the role of electricity across economies. As a result, countries’ transitions to net zero emissions need to be underpinned by bigger, stronger and smarter grids,” IEA said in an executive summary.

To achieve the energy and climate goals of various countries to be zero-greenhouse gas emitters, electricity usage worldwide must grow at a 20-percent faster rate than now, the report says. Expanded grids will be needed to deploy more EVs, and electric heating and cooling systems to scale up new technologies such as hydrogen production using electrolysis. A total of 80 million kilometers of grid infrastructure, the equivalent of the entire existing world-wide grid, must be added or refurbished to meet climate goals.

In an “announced pledges” scenario in which countries’ national energy and climate goals are met on time and in full, wind and solar must account for 80 percent of the total increase in global power capacity over the next 20 years, compared with less than 40 percent that has been added over the last 20 years, the report says. In IEA’s Net Zero Emissions by 2050 Scenario, wind and solar account for up to 90 percent of the global power supply increase.

“The acceleration of renewable energy deployment calls for modernizing distribution grids and establishing new transmission corridors to connect renewable resources – such as solar [photovoltaic] projects in the desert and offshore wind turbines out at sea – that are far from demand centers like cities and industrial areas,” the report says.

One pressing need is interconnection reform, as about 3,000 GW of renewable power projects—about half of which are in the advanced planning stages—are waiting in grid interconnection queues. This is equivalent to five times the amount of solar photovoltaic and wind capacity that was added globally last year, IEA said. Investment in renewables has nearly doubled since 2010, but global investments in grids themselves have remained at about $300 billion per year.

Delays in grid investment and refurbishment would substantially increase carbon dioxide emissions, leading IEA to develop a “grid delay case” in its research to explore what would happen if there were more limited investment, modernization, digitization, and operational changes.

Regulation of electric grids needs to be reviewed and updated so it supports not only new grids but improving current ones, and incentives should be put in place so grids keep pace with rapidly changing supply and demand, the report says. This means removing administrative barriers, rewarding good performance and reliability, and spurring innovation. Assessments of regulatory risk also need to improve “to enable accelerated buildout and efficient use of infrastructure.”

The 130-page report is divided into four chapters: “state of play,” “regulation and policy,” “identifying the gap,” and “policy recommendations.”

The “state of play” chapter notes that electricity grids have grown steadily over the past 50 years at a rate of about 1 million kilometers (km) per year, overwhelmingly in lower-voltage distribution networks, rather than higher-voltage transmission networks. More recently, there have been challenges in integrating renewable energy resources. Advanced economies are seeing investment but also long lead times for high-voltage transmission development, which signals that there are challenges to completing needed development. Investment has also been falling off in recent years with supply chain slowdowns even as demand and population grow, creating more risks for grid build-out. Grids play a central role in energy security, but grid congestion and delays in connecting renewable projects, including the supply chain issues caused by factors such as the COVID-19 pandemic and the war in Ukraine, are also causing impacts. For example, wait times for 50-MVA power transformers grew from a typical 11 months to more than 19 months due to materials and labor shortages, the report says.

“In short, we find evidence of multiple challenges that will need to be addressed to deliver the grids of the future,” IEA said.

Most grids are alternating current (AC), which has historically been composed of rotating generators such as thermal and hydroelectric plants, while new renewable resources connect to the grid mainly through electrical inverters. AC grids are popular because they are adept at changing voltage using long-distance transmission, which minimizes losses and allows transformers to be used to shift to lower voltages for local or regional distribution grids serving residential, commercial, and industrial customers.

However, direct current (DC) grids have certain advantages, such as in occasions when undersea cables are preferable and are used to serve multiple wind farms or markets, or cross-border interconnections and long-distance transmission from large hydro facilities are needed to reach demand centers. DC also offers grid stability and black-start capabilities.

Emerging markets and developing economies have built about 1.2 million kilometers of new transmission lines due to growing demand and access to electricity. Renewable policies have also led to new generation in places far from major load centers and have led to more countries dealing with interconnection issues. China accounts for one-third of the world’s new transmission facilities over the past ten years, or about half a million kilometers of transmission lines, used for purposes such as connecting energy sources from northern and western provinces to eastern load centers using ultra-high-voltage lines. India and Brazil are also rapidly expanding their grids, adding nearly 180,000 kilometers over the past ten years, about a 60-percent increase.

The age of grids varies by country, depending on historical development and varying levels of investment. The lifespan of grids, which are kept in service much longer than most facilities they interconnect, depends on the overloading and capacity, environmental factors, and the specific component. Transformers generally have a lifespan of 30 to 40 years, as do circuit breakers and other substation switchgear. Underground and undersea cables can last up to 50 years, and overhead transmission lines can last 60 years. More than 50 percent of grid infrastructure in advanced economies has been in service for longer than 50 years, and only about 23 percent is less than ten years old. However, in emerging and developing countries, about 40 percent of infrastructure is less than ten years old, and less than 38 percent is less than 20 years old.

The U.S., Japan, and some European countries have a higher proportion of their grids that are more than 20 years old. More than 50 percent of the countries in the European Union have grids more than 20 years old, which is about half their expected lifespan. Most new transmission in these countries has been built to access renewable generation. In Africa, Ghana, Kenya, and Rwanda have made significant investments in modernizing and expanding their grids.

Digitization of the world’s grids is also becoming “paramount,” according to the report, which says investment in digital technologies rose from about 12 percent of global investment a few years ago to about 20 percent in 2022. This is because of a need to manage distributed energy resources such as EVs, small-scale renewables, and electric heat pumps, as well as new players in the industry such as aggregators and demand response companies. Grid operators need digital technology for real-time monitoring and control of energy flows, especially in distribution grids, which saw 75 percent of global investment in 2022. The rise of distributed energy resources and other new technologies on the grid is requiring more precise study of power flows, the report says.

On the regulatory side, power grids are natural monopolies that are thus heavily influenced by regulations and policy, including entities that manage transmission and distribution systems, market structures, and market restructuring. Energy transitions, including climate change efforts, are driving the evolution of many of these regulations and policies.

Regulatory structures range from “cost of service,” where rules are set for companies to recover costs along with an allowed rate of return, or price-cap renumeration where there is a yearly cap that a grid operator can charge for each service or cluster of services. There is also a “yardstick competition” model where a grid operator’s service is compared with competitors and performance-based penalties and awards are assessed, as well as “output/performance-based” regulation where renumeration is based on monitoring the performance of service in order to encourage improvement in service. These varying regulatory models have different impacts on cost recovery and minimization, performance and operational efficiency, affordability, and quality of service.

Many national energy agencies and ministries are shifting to performance-based regulation since it spurs innovation and operational efficiency, the report says. A traditional regulatory approach, such as the “cost plus” framework, incentivizes capital expenditures even when operational expenditures would be more efficient.

“This shift is mainly driven by the energy transition, which calls for a high level of investment especially in innovative and digital assets. This leads to regulators needing a scheme that promotes the implementation of new technical and market solutions,” the report says.

In the “identifying the gap” section, the report discusses the pathway to future grids, analyzing an “announced pledges scenario” in which countries implement policies to meet their 2030 and 2050 zero-emission goals. In the announced pledges scenario, the electricity sector is a driving force in the clean energy transition and “undergoes deep transitions,” and electrical energy would grow by 20 percent per year. Elements of this scenario included the heavy deployment of EVs, more electric heating and cooling, and the development of hydrogen production using electrolysis. Wind and solar account for more than 80 percent of the total increase in global electric supply capacity over the next 20 years, an increase from the 40 percent seen in the past two decades. This scenario includes demand response—paying energy users to cut consumption in times of tight supply compared to a baseline—and energy storage. These systems will be supported by increased digitization and other modernizations on the grid.

This ambitious build-out of grids will make rapid deployment of supply chains critical, but there are significant risks to supply chains, including weather events attributed to climate change, natural disasters, a limited number of countries producing certain supplies, and surging demand for critical materials and raw materials worldwide.

In the announced pledges scenario, the total length of grids worldwide more than double between 2021 and 2050, reaching 166 million kilometers. More than 90 percent of that growth will be in the distribution grid.

The report also analyzed a net-zero emissions scenario, which it said provides a global roadmap to that goal and accelerates electricity demand growth to 3.2 percent by year by 2050, to a massive 62,000 TWh in 2050. Grid investment under the net-zero-emissions scenario passes the $1 trillion per year mark around 2035. Distribution grid investments maintain their total share of investment in both advanced economies and developing markets. Investment in emerging markets and developing economies are a majority of grid investment in both the announced pledges and net-zero emissions scenarios.

This significant investment calls for the replacement of 80 million km of transmission and distribution lines over the next two decades, which was more than the total length of all grids worldwide in 2021. More than two-thirds of the total line length by 2040 in the announced pledges scenario is yet to be built.

The report noted that failing to accelerate grid development in line with the announced pledges scenario—with “more limited investment, modernization, digitalization, and operational changes than envisioned – there would be a significant risk of stalled clean energy transitions around the world.”

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By: Concentric Staff Writer
Published: October 30, 2023

The U.S. Department of Energy (DOE) is putting billions of dollars into the development of “clean hydrogen” around the country to attract in-kind private investment, but the resource remains controversial even as state-backed regional groups prepare to launch a new era of hydrogen production with federal money.

DOE on Oct. 13 announced it awarded an unprecedented $7 billion for seven regional Clean Hydrogen Hubs to accelerate the deployment of commercial-scale hydrogen production for energy production and other uses, which the agency said is one of the largest investments in clean manufacturing and jobs in history. The initiative, funded by the 2021 Bipartisan Infrastructure Act, is meant to spur a national network of clean hydrogen production and attract a total of $50 billion in public-private partnerships.

The hubs “will kickstart a national network of clean hydrogen producers, consumers, and connective infrastructure while supporting the production, storage, delivery, and end-use of clean hydrogen,” DOE said. The new funding for the burgeoning energy resource follows the release of a hydrogen strategy and roadmap in June.

Clean hydrogen can be produced with zero or near-zero carbon dioxide emissions, and the future hubs are expected to produce 3 million metric tons of hydrogen annually, about a third of the 2030 U.S. hydrogen production target. Hydrogen is seen as a method to lower emissions from industrial sectors that are difficult to de-carbonize, which DOE said represent 30 percent of total U.S. carbon emissions.

The hubs in Appalachia, California, the Gulf Coast, the Mid-Continent, the Pacific Northwest, the Mid-Atlantic, and the Midwest (see sidebar) range in funding between $750 million and $1.2 billion apiece and target resources and industries from various regions, including renewables, natural gas, biomass and nuclear to produce hydrogen for industries such as power production, transportation and agriculture.

“Unlocking the full potential of hydrogen—a versatile fuel that can be made from almost any energy resource in virtually every part of the country—is crucial to achieving President Biden’s goal of American industry powered by American clean energy, ensuring less volatility and more affordable energy options for American families and businesses,” Secretary of Energy Jennifer Granholm said in a written statement.

One state where hydrogen production is creating controversy is California. A group known as Alliance for Renewable Clean Hydrogen Energy Systems (ARCHES) is set to develop the new hydrogen hub in that state with up to $1.2 billion in DOE funding. ARCHES is a partnership between Gov. Gavin Newsom’s Office of Business and Economic Development (GO-Biz), the University of California Office of the President, The State Building and Construction Trades Council, and Renewables 100 Policy Institute.

“These hubs will accelerate the decarbonization of hard-to-reach sectors, improve our energy security, establish good-paying green jobs, and help communities benefit from clean energy investments,” ARCHES said in comments to the Internal Revenue Service It added that renewable clean hydrogen must be part of the state’s strategy to achieve carbon neutrality by 2045. The hydrogen development partnership said it strongly supports the development of hydrogen hubs as well the 45V tax credit for clean hydrogen production included in the 2022 Inflation Reduction Act.

ARCHES, in its comments to DOE, said that the 45V clean hydrogen tax credit will help establish a level playing field for hydrogen and other technologies. But the comments added that requirements such as mandating the location of a renewable power source to be matched with hydrogen production facilities will add costs and inhibit developers from placing renewable energy production and hydrogen production in the best locations. Hydrogen producers should also be allowed to use annual matching versus hourly tracking to have similar applicability for other technologies such as batteries, pumped hydro, compressed air and others, the comments said. Hourly tracking refers to an hourly verification of hydrogen production as meeting clean-energy standards rather than on an annual basis or other timeframe.

The University of California is a participant in ARCHES, and one signatory to the letter is Scott Brandt, Associate Vice President for Research & Innovation at the University of California Office of the President.

But faculty from the university are unhappy with that endorsement. In response to the ARCHES comments, 29 faculty members from the university wrote the Office of the President, urging it to rescind the letter. ARCHES encourages too much flexibility in the way hydrogen will be produced, and it represents California ham-stringing federal climate action rather than bolstering it, the letter says.

The 45V tax credits are the largest subsidy for clean hydrogen production in the world and are expected to deliver more than $100 billion in taxpayer dollars to hydrogen production by the mid-2040s. The lower the carbon intensity of a project the more generous the credit, but accurately determining the carbon intensity of hydrogen is difficult, the faculty letter says, and producing hydrogen from electrolysis is extremely energy-intensive, requiring large amounts of electricity. When fossil fuels are used to produce hydrogen, the carbon intensity of the resulting hydrogen can also be very high, the letter says, alleging it is too high to be an effective decarbonization tool.

“Careful policy design, including rigorous carbon accounting standards, is required to ensure that power-intensive projects like electrolytic hydrogen do not directly or indirectly expand the use of fossil-fueled electricity generation,” the faculty letter says. The letter calls for “vigorously” accounting for the source, location and time of the electricity driving the hydrogen production and says that only clean resources should be used for hydrogen production. The faculty members said the recommendations would drive carbon emissions, cause cost increases and undermine climate goals.

Additionally, on Oct. 13, a coalition of public-interest groups wrote DOE, saying it is concerned about the transparency of the hydrogen hub selection process. The groups, including Communities for a Better Environment, California Environmental Justice Alliance, Asian Pacific Environmental Network and others say they represent low-income communities that would be disproportionally affected by hydrogen production facilities.

The groups say that throughout the application development process, ARCHES has disregarded environmental justice concerns and the need for an inclusive public process. The hydrogen hubs application received no vetting from environmental justice organizations or the communities they represent, according to the letter, which urged DOE to withhold any additional funding for ARCHES until it changes course in key areas, including requiring ARCHES to eliminate non-disclosure agreement requirements that were required for organizations to have access to project details.

The groups also charge that ARCHES leadership requested signatures on a memorandum of commitment that would have indicated they support the hydrogen project. The groups said they negotiated for 10 months with ARCHES leadership to come to a solution to the requirements, leading ARCHES to issue an NDA in July that removed certain clauses and allowed signatories to share information with community members. The updated requirements would still be harmful to grassroots organizations and make them legally liable, the groups say. The environmental justice groups also requested DOE require ARCHES to amend its governance structure to maximize opportunities for impacted communities to be represented and enforce community-engagement best practices.

Separately, three U.S. Senators—Sheldon Whitehouse (D-RI), Jeff Merkley (D-OR), and Martin Heinrich (D-NM) —called on the U.S. Treasury to swiftly implement rules regarding the 45V tax credits for clean hydrogen production. “Truly clean hydrogen has enormous potential to deliver emissions reductions beyond the reach of other decarbonization technologies, but today those ambitions are undercut by a market that overwhelmingly favors dirty hydrogen. The robustness of 45V can bridge these economics until our decarbonized grid can support a competitive clean hydrogen industry,” the senators said in the letter.

Many dynamics are swirling around hydrogen technology and its implementation in the U.S., along with many differing opinions. But there is no doubt this elemental technology is enjoying strong support at federal, state, and business levels.

Additional Information

The seven hubs to receive $7 billion in federal funds include:

Appalachian Hydrogen Hub (up to $925 million): Known as the Appalachian Regional Clean Hydrogen Hub, it is a joint project between West Virginia, Ohio, and Pennsylvania and is a project to use natural gas to create low-cost hydrogen and permanently store the carbon emissions through a series of hydrogen pipelines, multiple hydrogen fueling stations and CO2 storage facilities. It is expected to bring jobs to coal communities, including 18,000 construction jobs and 3,000 permanent jobs.

California Hydrogen Hub (up to $1.2 billion): A project of the Alliance for Renewable Clean Hydrogen Energy Systems (ARCHES) made from renewable energy and biomass and will provide a blueprint for decarbonizing public transportation, heavy-duty trucking and port operations, which are primary drivers of emissions and air pollution in the state. The hub has committed to requiring Project Labor Agreements– — for all projects connected to the hub and is expected to create 130,00 construction jobs and 90,000 permanent jobs.

Gulf Coast Hydrogen Hub (up to $1.2 billion) The HyVelocity hub in Texas will be near Houston and will include large-scale hydrogen production using both natural gas with carbon capture and renewables-powered electrolysis in an effort to lower the cost of hydrogen production.

Heartland Hydrogen Hub (up to $925 million) An initiative between Minnesota, North Dakota, and South Dakota, the hub aims to decarbonize fertilizer production in the agriculture industry, decrease the cost of regional hydrogen, and advance the usage of hydrogen for power production and cold climate space heating. The hub will offer equity ownership opportunities to tribal communities, local farmers, and farmer cooperatives through a private-sector partnership that will lower the prices of clean fertilizer for farmers.

Mid-Atlantic Hydrogen Hub (up to $750 million): A partnership between Pennsylvania, Delaware, and New Jersey, the hub will explore hydrogen-driven decarbonization using historic oil infrastructure and existing right-of-ways. It will develop renewable hydrogen facilities from renewables and nuclear power using both established and more innovative electrolyzer technologies. The hub plans to negotiate project labor agreements and provide close to $14 million for regional workforce development boards to develop community college training and pre-apprenticeships. It is expected to create 14,4000 construction jobs and 6,400 permanent jobs.

Midwest Hydrogen Hub (up to $1 billion): The Midwest Alliance for Clean Hydrogen is a partnership between Illinois, Indiana, and Michigan that will enable decarbonization through using hydrogen for steel and glass production, power generation, refining, heavy-duty transportation using renewable energy, natural gas, and nuclear energy.

Pacific Northwest Hydrogen Hub (up to $1 billion): The hub is a project between Washington, Oregon, and Montana and plans to use renewable resources to produce hydrogen through electrolysis, aimed at reducing the cost of electrolysis, making the technology more widespread, and reducing the cost of hydrogen production. It has committed to inking Project Labor Agreements for all projects of more than $1 million and investing in joint labor-management/state-registered apprenticeship programs. It is expected to create 8,050 construction jobs and 350 permanent jobs.

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Concentric is proud to announce a number of strategic leadership transitions effective January 1, 2024. These strategic changes position Concentric to continue to expand its industry-leading service offerings.

Danielle Powers, currently an Executive Vice President, will be promoted to the role of Chief Executive Officer. Ms. Powers has over 30 years of experience in the industry and has been a leader in Concentric’s consulting practice since 2005.

“The questions around the energy transition are now harder to solve, and the answers are becoming more nuanced,” said Ms. Powers of the new appointment, “as the energy industry changes and Concentric evolves, our commitment to providing excellent service will not change.” Ms. Powers will be responsible for Concentric’s corporate growth strategy and internal operations and will continue to serve clients as an expert in resource planning and the wholesale electricity market.

Focusing on client satisfaction, service offerings and delivery, and corporate communications, Daniel Dane, currently an Executive Vice President, will be promoted to become Concentric’s new President and Vice-Chair. Mr. Dane is entering his 20^th year at Concentric, and in addition to his role as a senior leader in Concentric, Mr. Dane plays a principal role in Concentric’s financial advisory and regulatory practices.

Mr. Dane shared, “I look forward to continuing to collaborate with our exceptional clients and employees to ensure Concentric remains the premiere North American energy industry advisory firm. Our clients are the heart of our business, and we will enhance and create new service offerings to meet their needs and expectations as the energy industry evolves.” Mr. Dane will also continue to assist clients as an expert witness on utility regulation and financial advisory matters.

John J. Reed, Concentric’s current Chairman and Chief Executive Officer, will continue as the firm’s Chairman. Mr. Reed will continue to actively advise clients and lead Concentric’s Board of Directors.

“The Board of Directors were thoughtful and deliberate in their consideration of these appointments and unanimously and enthusiastically endorse these leadership changes,” said Mr. Reed, “Dan and Danielle represent vibrant new leadership steeped in Concentric’s traditions and values. This leadership progression allows Concentric to expand, grow, and deepen the exceptional talent and services we offer the energy industry as it navigates new circumstances, energy demands, and customer preferences.”

Published: July 20, 2023
By: Concentric Staff Writer

Officials of the Canadian province of Ontario said they are launching a new energy initiative to address growing electricity demand due to electrification using a variety of resources, reflecting electrification trends also occurring across the United States.

Energy Minister Todd Smith announced the plan on July 10, saying strong economic growth and trends such as electric vehicles create a need for new zero-emissions electricity generation, long-duration energy storage and new transmission infrastructure.

“Our government’s open for business approach has resulted in unprecedented investments and job creation, from electric vehicles and battery manufacturing to critical minerals to green steel,” Smith said in written statement. “Powering Ontario’s Growth lays out the province’s plan to build the clean electricity generation, storage, and transmission we need to power the next major international investment, the new homes we are building, and industries as they grow and electrify.”

New EV and battery manufacturing facilities from companies such as Stellantis, Volkswagen and Umicore are contributing to a rise in electricity demand in Ontario for the first time since 2005. Smith said the province is working with the steel industry to end usage of coal and to electrify operations to produce “green steel” in the cities of Hamilton and Sault Ste. Marie. The investments alone will increase electricity demand by eight terawatt hours, doubling the annual average energy use of the Ottawa region.

The province’s Independent Electricity System Operator (IESO) has recommended an early start to meet energy demands through 2030 while keeping costs low. The IESO’s Pathways to Decarbonization Report issued in December 2022 included one scenario for demand growth that could rise from 42,000 MW today to 88,000 MW by 2050.

Powering Ontario’s Growth includes a nuclear energy component, such as a plan to site 4,800 megawatts (MW) of new nuclear on the current site of the Bruce Power Nuclear Generating Station, already the largest operating nuclear plant in the world with 6,550 MW of capacity. Nuclear power currently provides about 50 percent of the province’s energy supply, and it is one of the cleanest grids in the world, officials said.

A second aspect of the new plan is competitive procurements of new clean-energy resources such as wind, solar, hydroelectric, batteries and biogas, while a third component calls for designating and prioritizing three new electric transmission lines: one to power Algoma Steel and other companies in Northeastern Ontario, one line in the Ottawa region and one across Eastern Ontario. The Energy Minister’s office said it would direct the IESO to conduct a report on transmission options to address system bottlenecks between Toronto, Northern Ontario, and into downtown Toronto, where growth is expected.

The province will also request Ontario Power Generation to optimize hydroelectric generation sites and assess proposed pumped storage projects in Marmora and Meaford to “improve grid efficiency.”

The new plan also aims to keep costs low by starting to plan for the future of energy efficiency programming to reduce demand and support the deployment of distributed energy resources such as rooftop solar and EV batteries.

“As our province moves toward an electric future with a strong end-to-end EV supply chain, there has never been a greater need for clean, affordable energy that companies can rely on. This plan brings us one step closer to being a world-leading energy powerhouse,” Ontario Minister of Economic Development Vic Fedeli said in a written statement, adding that the province has attracted billions of dollars in investment from domestic and international companies over the past 2 ½ years.

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

Published: July 6, 2023
By: Concentric Staff Writer

Texas Governor Greg Abbott signed new legislation reforming the state’s utilities and allocating reliability costs to intermittent generation sources in the same week a searing heat wave set in and set electricity prices skyward.

Governor Abbott on June 9 signed HB 1500, a “sunset” bill, which is a regular reauthorization of the Public Utility Commission of Texas (PUCT), and includes several provisions to shore up grid reliability. The bill drew a negative reaction from some renewable energy interests over provisions they say are aimed at hindering clean-energy resources.

Reliability has become more of a discussion topic in Texas since February 2021 when Winter Storm Uri caused widespread outages and hundreds of deaths, mostly due to freeze-ups of natural gas infrastructure. Summer reliability risks include grid impacts due to high electricity load and hot weather—the Electric Reliability Council of Texas (ERCOT) issued a voluntary conservation call on June 20 from 4 p.m. to 8 p.m. central time that followed a “weather watch” from June 15–21.

The HB 1500 legislation requires generation resources, other than battery storage facilities, to demonstrate to the PUCT that they will be available to operate when called upon during times of highest reliability risk. The owner or operator must be able to meet the requirement by January 1, 2027, by supplementing or contracting with on-site or off-site resources, including energy storage. The legislation directs the PUCT to determine the average capability based on “expected resource availability” and seasonal-related capacity on a standalone basis.

HB 1500 also requires establishing an ancillary services program to procure energy for dispatchable reliability reserve services on a day-ahead and real-time basis to account for market uncertainty. It also requires a determination of the quantity of services necessary based on historical variations in generation availability for each season, based on a targeted reliability standard or goal. This includes the intermittency of non-dispatchable generation facilities—wind and solar—and forced outage rates for dispatchable generation facilities.

Under the new law, the PUCT cannot require any retail customer or load-serving entity in the ERCOT power region to purchase credits designed to support a required reserve margin or other capacity or reliability requirement unless the PUCT ensures that the net cost of the credits to the ERCOT market does not exceed $1 billion annually, less the cost of any interim or bridge solutions. The credits are available only for dispatchable generation and the credits must be obtained centrally to prevent market manipulation. A generator also cannot receive credits that exceed the amount of its generation bid into the forward market.

Generation units can receive a credit only for being able to perform in real-time during the tightest intervals of low supply and high demand on the grid, to be defined annually by the PUCT. The bill also establishes a penalty for generators that bid into the forward market but do not meet their assumed obligation. The bill also establishes a single ERCOT-wide clearing price for the credits program that does not differentiate payments or credit values based on locational constraints.

A new Grid Reliability Legislative Oversight Committee was also created through the new law, which will oversee the PUCT’s implementation of legislation related to the regulation of the Texas electricity market enacted by the 87^th and 88^th Legislatures. The eight-member committee will be composed of three members from the Senate, three from the House, and the Senate and House chairs having “primary jurisdiction over matters relating to the generation of electricity.”

The legislation requires the PUCT to file a report no later than December 1 each year that includes the annual costs incurred by load-serving entities that back up dispatchable and non-dispatchable generation resources to guarantee that a firm amount of electric energy will be available to the Texas power grid.

Following a review of the report, the PUCT will determine whether specific transmission or distribution system constraints or bottlenecks in Texas give rise to market power in specific geographic markets. If there is a finding that such constraints give rise to market power, the PUCT can order reasonable mitigation by requiring utilities and others to construct additional transmission or distribution capacity or both.

Environment Texas Executive Director Luke Metzger issued a statement in opposition to the passage of HB 1500, saying it favors fossil-fuel-powered generators and will lead to higher transmission costs for renewables.

“We need, and Texans want, more clean energy, not less,” Metzger said. “There is strong support for more wind and solar energy, more battery storage, more energy efficiency, and more interconnection with the national grid. Unfortunately, the Legislature ignored these solutions to strengthen our electric grid while protecting consumers and the environment.”

However, Brent Bennett, policy director with the Texas Public Policy Foundation, lauded passage of the bill.

“We commend the legislature for passing HB 1500, which renews the Public Utility Commission on the condition that they take up needed market reforms, including Governor Abbott’s 2021 directive to ‘allocate reliability costs to generation resources that cannot guarantee their availability,’ and to ‘ensure that all power generators can provide a minimum amount of power at any given time.’ These reforms are critical in light of the federal government’s profligate spending on unreliable energy sources and onslaught of regulations on reliable energy sources,” Bennett said.

The new legislation coincided with a heat dome that hit the state in recent weeks, which will increase electricity demand for air-conditioning. Early in the week of June 25, Texas was under a hazardous heat warning, with afternoon temperatures of 104 degrees Fahrenheit recorded on June 27.

ERCOT broke its peak demand record on June 19 at 79,304 MW surpassing the previous June’s record of 76,718 MW. ERCOT set 11 peak demand records in the summer of 2022, typically in the late afternoon and evening hours. The grid operator said it was using tools such as reserve power, calling for large customers to reduce usage and bringing more generation online sooner. ERCOT said that other than extreme heat and record demand, it was experiencing outages of thermal power plants, declines in solar in the evening hours and low performance from wind during the summer peak.

The conditions on the grid led to extreme wholesale market prices in excess of $5,000 per MWh[1] on June 20.

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[1]“ERCOT: Real-Time Price – LCG Consulting.” EnergyOnline, www.energyonline.com/Data/GenericData.aspx?DataId=4. Accessed 29 June 2023.

Published: June 8, 2023

By Concentric Staff Writer

The U.S. Department of Energy (DOE) on June 5 issued a new framework for accelerating the production and usage of clean hydrogen over the coming decades, its latest effort to support the technology as part of the Biden-Harris administration’s efforts to combat climate change.

The U.S. National Clean Hydrogen Strategy and Roadmap will provide a “snapshot” of hydrogen production, transport, storage and usage in the U.S. today as well as a plan for large-scale clean hydrogen scenarios for 2030, 2040 and 2050, DOE said. It also identifies needs for collaboration between government agencies, industry, academia, national laboratories, tribal communities, environmental groups, labor unions, and others.

“Accelerating the deployment of hydrogen is key to achieving President Biden’s vision for an affordable, secure clean energy future,” U.S. Energy Secretary Jennifer M. Granholm said in a written statement. “That’s why DOE worked alongside our federal partners to develop the U.S. National Clean Hydrogen Strategy and Roadmap that will lay the foundation for a strong and productive partnership between the public and private sectors and will guide government and industry to realize the full potential of this incredibly versatile energy resource.”

The plan has three major strategies, including targeting strategic uses for clean hydrogen in high-impact applications where there are limited alternatives, such as in the industrial sector, heavy-duty transportation and long-duration energy storage. A second strategy is reducing the cost of clean hydrogen through innovation, scaling up, stimulating private sector investment and developing a clean-hydrogen supply chain, while a third strategy is focusing on regional networks with large-scale clean-hydrogen development.

The roadmap was released in draft form in September 2022 for comment, and the new plan includes input from industry, academia, and non-profits as well as state, local, and tribal governments, DOE said. It is a “living document” that will be updated every three years.

DOE said that clean hydrogen offers substantial economic benefits and will create thousands of new, good-paying jobs, especially in disadvantaged communities. A DOE report issued in March, Pathways to Commercial Liftoff: Clean Hydrogen, found that that new hydrogen economy could add 100,000 net new and indirect jobs by 2030.

A May 11 proposal from the U.S. Environmental Protection Agency for new source performance standards for power plants also included low-greenhouse gas hydrogen co-firing among the technologies that can be applied directly to power plants that use fossil fuels.

The plan responds to language in the Bipartisan Infrastructure Law (Public Law 117-58) signed by Biden in 2021, which included a $9.5 billion investment in clean hydrogen, and the Inflation Reduction Act that included a new production tax credit for clean hydrogen.

According to DOE, demand scenarios for 2030, 2040 and 2050 identified pathways for clean hydrogen decarbonization applications with opportunities for 10 million metric tons (MMT) of clean hydrogen annually by 2030, 20 MMT by 2040, and 50 MMT by 2050. Clean hydrogen can also reduce U.S. emissions by 10 percent by 2050 relative to 2005, consistent with the U.S. Long-Term Climate Strategy, the agency said.

While the U.S. Congress required DOE to develop the strategy and roadmap, it will be developed across many agencies, including the U.S. Departments of Agriculture, Commerce, Defense, Energy, Interior, Labor, State, Transportation, and Treasury, the EPA, the National Aeronautics and Space Administration, the National Science Foundation, the Office of Science and Technology Policy and the White House.

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Published: June 6, 2023
By: Concentric Staff Writer

“Energy insecure” households in the U.S. were billed at a higher rate for energy than other households in 2020, according to a new report from the U.S. Energy Information Administration (EIA).

Households identified as “energy insecure”—those in which there is an inability to meet basic energy needs and there are challenges in purchasing adequate energy—were billed 20 cents more per square foot than the national average of $1.04 per square foot, EIA said. Energy insecure households were also billed at 26 cents more per square foot than houses that are not energy insecure.

“Household energy expenditures are influenced by many factors, including weather, the types of energy sources used, household behavior, and the energy-consuming space (or square footage) of the home,” EIA said May 30. “Energy insecure households are more likely to report their homes are drafty, poorly or not insulated, and smaller than households that did not experience energy insecurity.”

EIA said its Residential Energy Consumption Survey (RECS) uses energy insecurity as a measure to identify households that have received a disconnection notice, have reduced or foregone basic necessities to pay bills, kept their houses at unsafe temperatures to reduce costs, or have been unable to repair cooling or heating equipment because of cost.

Data from the survey showed that in 2020, households making less than $10,000 per year were billed at a rate of $1.31 per square foot for energy while households with incomes higher than $100,000 were billed at $1.21 per square foot. Survey respondents in rented homes were billed 28 cents more across all energy sources than owners were. The EIA said that “differences greater than $0.05 per square foot are statistically significant at the 5% level, meaning that there’s a less than 5% chance that the difference is explainable by chance alone.”

The 2020 RECS collected data from about 19,000 households, the largest sample in its history, the agency said, and for the first time the data is available at the state level in all 50 states and the District of Columbia.

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