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November 8, 2024

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New ERCOT Board Approves Governance Changes

ERCOT’s newly reconstituted Board of Directors met for almost 20 minutes Tuesday morning, enough time to share congratulatory messages and to approve amendments to the grid operator’s bylaws incorporating the state legislation that remade the board in the first place.

“That was painless,” an anonymous stakeholder or staff member said just before the video stream ended.

Board Chair Paul Foster and Director Chris Aguilar were only in the 10th hour of their three-year terms when the board meeting began. They are the first two of eight independent directors who will eventually comprise the 11-person board. (See 2 New ERCOT Directors Named, Replacing Current Board.)

“You’ve been much anticipated, both of you,” interim CEO Brad Jones told them. “ERCOT staff has long wanted this new board in place.”

Revamping ERCOT’s board, which previously consisted of five independent directors and eight market segment representatives, became one of the legislature’s top priorities after February’s winter storm drove the Texas Interconnection to the brink of collapse.

“I know I have a lot to learn, but I’m looking forward to working with all of you,” said Foster, who comes from an oil sector background.

“What brings us here is what we most fear: the small probability of an event that can have catastrophic consequences. That is what we have to prevent,” Aguilar said.

The board will meet later this month to consider voting items that were deferred Tuesday and to ratify the meeting minutes from the board’s previous 18 months of virtual meetings. The Finance and Audit and HR and Governance committees will meet before that while it waits for the other six members to be selected. (See Search Firm Chosen to Find New ERCOT Board Members.)

Jones, Public Utility Commission Chair Peter Lake and the Office of Public Utility Counsel’s Chris Ekoh also sit on the board, with only Ekoh allowed to vote.

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Report: CCS Needs $1 Trillion Investment over 30 Years

With 71 carbon capture and storage (CCS) projects added to the Global CCS Institute database in the first nine months of this year, the technology is experiencing an unprecedented surge. But at a total of only 135 facilities in the global pipeline, the CCS sector has a lot of room for growth, according to Jarad Daniels, CEO of the institute.

“If we are to meet our climate targets and achieve climate neutrality, we will need to scale global CCS capacity by a factor of 100 by 2050, requiring around $1 trillion of investment over the next 30 years,” Daniels said Tuesday during the launch webinar for the institute’s Global Status of CCS 2021 report.

The U.S. leads the market in installed facilities, and it will host 36 of the 71 tracked by the institute so far in 2021, according to the report. Regionally, North America leads the world with 16 installed facilities and 60 in development, followed next by Europe, which has three installed facilities and 35 in development.

Key drivers of the global growth are the adoption of ambitious climate targets and the net-zero commitments of more than 100 countries, according to Guloren Turan, general manager of advocacy and communications at the Global CCS Institute.

Those commitments have “kickstarted a cycle, whereby governments around the world are strengthening policy support for CCS, and the private sector, seeing the strengthening business case for CCS … is responding by advancing new projects, developing new business models and entering into strategic partnerships across the value chain,” Turan said during the webinar.

DOE Investment

The U.S. Department of Energy is targeting investments to grow CCS technologies that are “ready to be demonstrated,” Jennifer Wilcox, principal deputy assistant secretary at the department’s Office of Fossil Energy and Carbon Management, said during the event.

Over the last five years, she said, DOE invested $1.2 billion to develop CCS technologies, and the department’s budget request for next year asks for a 60% increase in federal investment in research and development for “carbon capture, reliable storage, and conversion of CO2 and its removal from … the atmosphere.”

The request would provide up to $368 million for fiscal year 2022, she said.

This year, DOE put $75 million into R&D on front-end engineering design studies for carbon capture in the natural gas power sector, according to Wilcox. The department last week announced that of that investment, $45 million went to 12 projects, including a GE Research project in New York to capture CO2 from natural gas combined cycle flue gas and reduce the levelized cost of electricity by 15%.

DOE also has invested $33 million this year to advance direct air capture (DAC) technologies, Wilcox said. Six R&D projects announced in June received $12 million to find ways to increase the amount of CO2 capture in the DAC process.

Capture and Removal

While avoiding CO2 emissions will always be cheaper than removing emissions from the air, Wilcox said, the world has moved beyond the time when that is enough to meet climate goals. Consequently, technologies to capture CO2 at the point of emission and CO2 removal projects are necessary to meet those goals, and DOE is focused on both.

Incentives for carbon capture are already in place in the U.S., but Wilcox says they’re not nearly enough.

The federal 45Q tax credit is currently priced at about $50/ton of CO2, “coupled to dedicated and reliable storage deep underground,” she said. “That’s not a high enough price tag for a lot of the different carbon-capture opportunities that are out there today.”

That price, she said, can work for some projects, such as bioethanol or hydrogen production that have higher concentration CO2 streams. In natural gas power plant streams, however, the concentration is diluted.

“In the U.S., we don’t have a demonstration-scale project on what the actual costs of doing that [for natural gas] would be, and it’s the same with cement … and steel,” she said.

Therefore DOE is concentrating its investments on demonstration-scale projects that can help make the costs of capturing CO2 in those sectors transparent to inform policy, according to Wilcox.

DAC technology has a long way to go to meet the needs of the global community.

“They’re estimating that we need to be able to [remove CO2 from the atmosphere] on the order of gigatons by midcentury,” Wilcox said. “We need to be able to invest in the technologies today so that they are at the scale that we need them to be in order to meet net zero.”

Policy Priorities

The investment of $1 trillion in CCS through 2050 would support the deployment of 2,000 large-scale facilities, or 100 facilities each year, according to the Global CCS’ new report. Those facilities could reduce global emissions by 15%, as defined by modeling by the International Energy Agency, the report said.

To reach that scale, stronger policies are needed to incentivize the private sector and mobilize CCS investment, Turan said.

Top among the policies the institute recommends is for governments to define the role of CCS in their emissions targets and create bankable, long-term value on storage of CO2. In addition, governments need to support the identification and appraisal of storage resources, and develop clear CO2 storage laws and regulations.

“We’re already seeing a lot of these actions being implemented across the world … and it’s starting to show results,” Turan said. “What we need now is more urgency; a lot more urgency.”

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Insurance Sector Confronts Climate Change Risks

From wildfire dangers to renewable energy supply-chain issues, the insurance industry is becoming more deeply entangled in the risks stemming from climate change.

Those risks were the theme of a virtual conference hosted last week by the Washington State Office of the Insurance Commissioner.

“We’re looking at impacts on our economy,” Washington Insurance Commissioner Mike Kreidler said Wednesday.

Climate change was responsible for $268 billion worth of economic damage worldwide in 2020, of which 64% is uninsured, said Yoon Kim, head of global client services at Moody’s ESG Solutions.

Kim said that more insurance claims are showing up due to bad weather. Meanwhile, the transition from fossil fuels to renewable energy increases litigation risks due to businesses entering uncharted territory, she said. Renewable energy companies are dealing with new markets, supply chains and energy source locations that differ from fossil fuel energy sources, creating a greater likelihood for business mistakes.

Meanwhile, 60% of new homes on the West Coast have been constructed in the wildland-urban interface, which translates into outlying towns and suburbs growing next to wildfire-prone rural lands, said Amy Snover, director of the Climate Impacts Group at the University of Washington. About 1 million Washington homes lie in this zone.

“Many of these have not adapted themselves to wildfire risks,” Snover said. “This is going to create risks to ordinary people who normally don’t pay attention to climate change.”

Anthony Leiserowitz, head of the Yale University Program on Climate Change Communications, studies how people perceive climate change.

He said a survey of U.S. residents this past spring showed 64% of respondents thought climate change is a problem, while 25% were very worried. Fifty-seven percent thought climate change is caused by humans, while 30% believe it is a purely natural phenomenon.

“For many people, they think of it as a distant problem,” Leiserowitz said.

Conference speakers said the insurance industry is well-suited to get businesses, governments and individuals to take climate change more seriously. “If insurance companies perceive big risks, they won’t want to write policies,” Kreidler said.

The National Association of Insurance Commissioners has created a Climate and Resiliency Task Force to tackle the issue. The group is looking at whether new regulations are needed to deal with insurance claims that can be linked to climate change. It is also studying whether measures should be taken to mitigate potential financial losses due to storms, wildfires and other global warming ripple effects.

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New Era for Grid Planning in North Carolina?

After barreling through both houses of the North Carolina General Assembly in a matter of days, the compromise energy bill H951 could transform the role of resource and transmission planning as the state seeks to reduce its carbon emissions by 70% over 2005 levels by 2030.

In addition to setting that ambitious goal, the bill also calls for the state’s utilities to add 2,660 MW of new solar generation, while developing a portfolio of least-cost resources that “maintain or improve upon the adequacy and reliability of the existing grid.”

In other words, thousands of megawatts of Duke Energy’s (NYSE:DUK) coal-fired generation could soon be retired, while solar, storage and offshore wind are added to a grid that, in some places, has already absorbed all the new renewable energy it can take, Duke executives told the North Carolina Utilities Commission (NCUC) at a technical conference on Oct. 6.

Installing any new solar in those “transmission constrained areas will likely incur expensive network upgrades for interconnection,” said Dewey “Sammy” Roberts, Duke’s general manager of transmission planning and operations strategy. “We’re essentially running out of places where grid capability is available that lends itself favorably to locating incremental resources such as solar and storage.”

Costs for system upgrades for the 32 projects currently in Duke’s interconnection queue are estimated at $267 million, he said.

H951 passed the House in a 90-20 vote Thursday after clearing the Senate the day before and is expected to be signed by Gov. Roy Cooper. (See NC Compromise Energy Bill Passes Senate, Heads Back to House.)

Last week’s half-day NCUC session was the third installment of the commission’s examination of Duke’s 2020 integrated resource plan (IRP) and the methodologies it used for determining coal plant retirements, replacement resources and grid planning. While Duke emphasized the need for new “firm,” dispatchable power, preferably sited at retiring coal plants, advocates and other state officials questioned the approach, calling for more holistic, transparent and proactive system planning. (See NCUC Debates Best Path for Duke Coal Retirements.)

Speaking for the Southern Alliance for Clean Energy and the Carolinas Clean Energy Business Association, Jay Caspary of industry consultants Grid Strategies cited a raft of studies that predict the U.S. transmission system will need to grow two- to threefold to decarbonize the grid by President Joe Biden’s goal of 2035.

“We can do this; we just need to kind of think a little bit outside the box,” Caspary said. “What do we expect the resource mix to be? What are the benefits of adding transmission capacity? It’s not just economic benefits. There are probably reliability benefits, security benefits and other benefits that transmission provides just because it is such a flexible resource that provides a lot of optionality for future resource plans.”

Caspary pushed for the use of grid-enhancing technologies (GETs), such as dynamic line ratings, to upgrade existing transmission and distribution lines to make room for some of the 755 GW of solar, wind and storage that the Lawrence Berkeley National Laboratory estimates are sitting in interconnection queues across the country.

Edward Burgess, senior director at consulting firm Strategen, presented the state attorney general’s concerns on the need for more transparency about the $17 billion in transmission investments Duke has told its investors it is planning in the coming years, especially investments related to coal plant retirements. Avoiding those costs “actually wind up delaying the retirement of certain coal plants,” he said, recommending that an independent analysis of Duke’s transmission needs be conducted before its next IRP in 2022.

17% Reserve Margin 

Duke’s North Carolina utilities have submitted IRPs anticipating that a 70% cut in emissions could require more than 16 GW of solar on the grid by 2035, along with 4.4 GW of storage. Duke has two utilities in the state, Duke Energy Carolinas (DEC) and Duke Energy Progress (DEP).

Interconnecting that much new renewable energy will increase the complexity of system planning, Roberts said.

“Storage will need to be studied both discharging energy into the system and absorbing energy from the system,” he said. “A more granular approach [will be needed] to further optimize the integrated resource and grid system. For future IRPs, we’ll likely need to continue to look at alternate pathways of resources for achieving clean energy targets, and that will just add to the modeling complexity with grid resource interaction.”

The utility pointed to its work with the North Carolina Transmission Planning Collaborative, which includes Duke, the state’s municipal utilities and electric co-ops. The group recently completed a study on offshore wind and is working on a single, collaborative transmission plan for DEC and DEP.

At the same time, Duke seemed to take a more conservative and insular approach to transmission planning to avoid too heavy a reliance on “non-firm” — that is renewable — power imports from outside its system. Duke’s IRP envisions replacing coal-fired generation with up to 9,600 MW of natural gas, possibly sited at or near the retiring coal plants to take advantage of existing interconnections and keep costs down, Roberts said.

Based on North Carolina’s winter-peaking system, Duke’s transmission analysis called for a resource adequacy reserve margin of 17%, a figure that includes imports of 2,000 MW of power procured from day-ahead or real-time power markets, said Nick Wintermantel, principal utility and energy consultant at Astrapé Energy. Given that “substantial” level of imports, any further increase in import capacity would need to be firm power, he said.

A further challenge for Duke is that the Southeast is “typically capacity constrained, not transmission constrained, meaning if we increase transmission, we’re likely still not going to be able to get more non-firm imports,” Wintermantel said. “Essentially, it’s cold and gets also cold in TVA, Southern [Company] and the Carolinas; so, it’s typically more capacity constrained.”

Nor should Duke rely on imports from neighboring systems such as the Tennessee Valley Authority or PJM’s regional grid, he said. With Duke having “no control with TVA or PJM [over] their planning processes, it is highly uncertain what [importable power] will be there on that cold morning,” he said.

Getting the Cheapest, Best Resources

While acknowledging Duke’s point on minimizing reliance on imported power, Burgess countered that the February power outages in Texas were partly due to the state’s limited connections to other power systems. “Having greater import and export capability can really be thought of as an insurance policy under this kind of extreme stress,” he said. “Looking at the import and export capability can help to potentially unlock more firm contracts, relying on cheaper resources in other regions than having to build our own.”

Roberts said, “To enable future renewable interconnections may require new regulatory structures as opposed to … upgrading in response to a filed interconnection request, with a customer signing an interconnection agreement.”

Caspary pointed to FERC’s July advanced notice of proposed rulemaking (ANOPR) on transmission planning. (See FERC Goes Back to the Drawing Board on Tx Planning, Cost Allocation.)

The final rule could have “a drastic effect on how we do generation interconnection studies, how we do planning studies, how we define benefit-to-cost analysis, how we try to get more interregional projects completed in advance of the need of the resource mix so that we can actually enable the cheapest and best resources to get into the markets and facilitate the retirement of some of these old, dirtier units that seem to be a challenge for a lot of reasons.”

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Modeling Shows Vt. Can Hit Decarbonization Targets Through 2050

Initial modeling of potential decarbonization pathways for Vermont shows that the state can meet 2025, 2030 and 2050 greenhouse gas emission reductions targets set by the 2020 Global Warming Solutions Act (GWSA).

A team of consultants developed the model to support the Vermont Climate Council as it finalizes the pathways and strategies it will include in the state’s Climate Action Plan due Dec. 1, David Hill, managing consultant at Energy Futures Group, said on Oct. 5.

The GWSA mandates GHG emission reductions of 26% below 2005 levels by 2025, and 40% and 80% below 1990 levels by 2030 and 2050, respectively. The model showed the state could exceed the 2025 target and meet the 2030 and 2050 targets, Hill said during the council’s latest meeting.

Exceeding the first target, he added, is all about pace.

“You can’t just barely meet the target in 2025 and then ramp it up to meeting 2030,” he said. “There is what we might call overachievement in 2025, but that is all in the interest of meeting the targets both in 2030 and 2050.”

Emissions would decline from 7.3 million metric tons carbon dioxide equivalent in 2025 to 5.2 million and 1.7 million in 2030 and 2050, respectively, according to the model.

The results, Hill said, are based on the policies and programs that the council’s Cross-sector Mitigation Subcommittee sees as the most feasible for attaining the largest GHG emission reductions in the most cost-effective manner. As the council compiles a draft plan over the next month, it will consider the subcommittee’s policy and program suggestions.

All subcommittee recommendations still must undergo further equity analyses based on the council’s guiding principles for a just transition adopted in August.

When the draft plan is complete, the consultants will plug the plan into the model to analyze the council’s official emission reduction pathway choices. A report on that analysis is due on Nov. 15.

Major Pathways

The cross-sector subcommittee made its preliminary decarbonization pathway recommendations to the full council in July for the transportation, buildings, non-energy and electricity sectors.

Initial modeling considered scenarios that are based on the subcommittee’s draft recommendations, including three major actions for transportation, buildings and electricity. Those actions are to adopt the Transportation and Climate Initiative Program (TCI-P) and a Clean Heat Standard (CHS), as well as increase the current Renewable Energy Standard (RES) to 100%. (See VT Climate Council Puts Clean Heat Standard on the Table.)

Transport

The model showed that the transportation sector could achieve an 88% reduction in emissions by 2050 under the subcommittee’s draft actions.

That result relies on a transition to battery electric vehicles (BEV) along with adoption of biofuel and a reduction of vehicle miles traveled.

The model phases out the sale of new internal combustion engine (ICE) vehicles in the state by 2033, Hill said, but biofuel would be needed for about 90,000 ICE vehicles still operating in 2050. By 2030, he added, Vermont would have 160,000 registered BEVs.

To support those transportation sector changes, the model considers Vermont’s possible participation in a regional cap-and-invest program. TCI-P would position the state to raise the consistent revenues necessary to fund BEV adoption and charging initiatives.

The cross-sector mitigation subcommittee will likely make TCI-P participation a priority pathway for the council’s consideration, according to Gina Campoli, subcommittee member and environmental policy manager at the Vermont Agency of Transportation. Benefits of participation would include a 30% reduction in transportation sector emissions and proceeds of $20 million/year, she said during the meeting.

Buildings

In the buildings sector, the model showed a possible 83% reduction in emissions by 2050 from the subcommittee’s draft actions.

The results cover residential, commercial and industrial subsectors, with most reductions coming from residential and commercial buildings, Hill said. Improved space heating, he added, is the primary driver of reductions.

The model anticipates reductions coming from the adoption of efficient heating systems, such as heat pumps, combined with better building performance and a phaseout of fossil fuels for cooking and water heating.

A fossil-fuel phaseout, under the model, could be accomplished through appliance standards or a CHS.

The subcommittee continues to support the CHS as a priority for the council’s consideration, according to David Farnsworth, subcommittee member and principal at the Regulatory Assistance Project.

A CHS is an equitable option that allows Vermonters to exercise choices in how they transition their heating systems, Farnsworth said during the meeting.

“We would recommend that the Vermont [Public Service Commission] administer the standard, establishing growing annual obligations to achieve thermal load and the necessary reductions to meet GWSA requirements,” he said.

Electricity

Vermont’s current RES has already pushed the state’s electricity related GHG emissions to 83% below 1990 levels, according to a recent report from the Energy Action Network. Recognizing that lowering emissions is not the primary goal for the electricity sector, Hill said, the model demonstrates generation growth and supports a 100% RES.

Generation in the model grows from 6,600 GWh in 2020 to 12.2 GWh in 2050, the bulk of which would come from offshore wind in the ISO-NE system.

With very low emissions, the electricity sector is now positioned as a backbone to decarbonizing the transportation and building sectors, according to Ed McNamara, subcommittee member and director of the Regulated Utility Planning Division at the Vermont Department of Public Service.

The subcommittee, therefore, continues to support its recommendation that the full council consider including a 100% RES after 2030 in the Climate Action Plan, McNamara said.

“We’re not actually recommending a very specific RES design,” he said. “There are a lot of different factors to consider — new versus existing requirements, regional versus in-state requirements, distributed versus large-scale [generation].”

Every choice has significant policy implications for cost-effectiveness and effects on low-income Vermonters, he said, adding that the subcommittee suggests the council “do further research and study on how [the RES] should be designed.”

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Massachusetts Considers Approval of LNG Facility in Environmental Justice Community

Clean energy advocates are pushing the Massachusetts Energy Facilities Siting Board (EFSB) to reconsider its tentative approval of a liquefied natural gas (LNG) facility within one mile of a low-income, state-designated environmental justice community.

“The siting board declares this facility an energy bridge during the state’s transition away from a fossil fuel-based economy. But this project is the fossil fuel-based economy,” Cathy Kristofferson, secretary and treasurer for the Pipeline Awareness Network for the Northeast, said during an EFSB meeting on Oct. 6.

The proposed Northeast Energy Center (EFSB 18-04/D.P.U. 18-96) would liquefy and store pipeline natural gas for loading onto tanker trucks to serve National Grid customers with some capacity marketed to other gas distribution companies in the state.

The project would be located along Route 169 or Route 20 in Charlton, a town already overburdened with methane emissions from Talen Energy’s Millennium natural gas combined-cycle power plant and a landfill operated by Casella Waste Systems that was shut down for contaminating residential water wells, resident Maureen Doyle said.

The EFSB heard public comments on the $100 million facility proposed by Liberty Energy Trust, an infrastructure and development firm, but ran out of time for deliberation and a final decision.

Massachusetts-LNG-storage-and-shipping-facility-Location-map-(Liberty-Energy-Trust)-Content.jpgThe Massachusetts Energy Facilities Siting Board tentatively approved a $100 million LNG storage and shipping facility along Route 169 in Charlton, adjacent to Talen Energy’s Millennium natural gas combined-cycle power plant. The developer also proposed an alternate site along Route 20. | Liberty Energy Trust

On Sept. 20, the EFSB tentatively approved the project’s location at the Route 169 site, adjacent to the Millennium plant. The board acknowledged the site’s location within an environmental justice community but stated, “the project did not exceed the Environmental Notification Form (ENF) thresholds for air, solid and hazardous waste, or wastewater and sewage sludge treatment and disposal.”

Projects such as the LNG facility are required to fill out an ENF. The form initiates the process for the facility to receive approval from the Massachusetts Environmental Policy Act Office to ensure the proposal aligns with state laws, including the Executive Office of Energy and Environmental Affairs’ Environmental Justice Policy.

The local production and distribution of LNG “offers greater reliability and less environmental impact than more distant LNG sources that may be available,” Andre Gibeau, an attorney for the EFSB, said during the meeting. The proposed project is also “centrally located with respect to existing LNG storage facilities in the commonwealth,” he said.

According to a 2019 report by The Oxford Institute for Energy Studies, the natural gas combusted to chill LNG to minus 162 degrees C equals 11 to 13% of the gas produced at the wellhead, “which means that LNG has significantly higher emissions than a typical pipeline gas value chain.”

The proposed facility would include a pipeline extension from the Tennessee Gas Pipeline and be capable of producing 250,000 gallons per day. The plant would be able to store about 1 million gallons of LNG in 10 tanks.

Last week’s meeting occurred as gas prices in Europe and Asia hit record highs. The U.S.’ domestic supply insulates it somewhat from global spikes, but prices in the U.S. have doubled this year, rising to the highest levels since 2008. That could greatly increase heating bills this winter after years of unusually inexpensive fuel.

The EFSB will vote on the LNG facility during its next meeting, which has not yet been scheduled.

The board has yet to replace its environmental justice representative since former representative Shalanda Baker took a position as deputy director for energy justice and secretary’s adviser on equity at the U.S. Department of Energy earlier this year.

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PG&E Shuts off Power During Wind Storm but Limits PSPS

Pacific Gas and Electric (NYSE:PCG) implemented extra-targeted public safety power shutoffs (PSPS) Monday as powerful offshore winds gusted through drought-stricken Northern and Central California, prompting a red-flag warning from the National Weather Service.

The weather conditions were like those in October 2017, when firestorms driven by high winds and dry conditions tore through Napa, Sonoma and neighboring counties, killing 44 people and leveling thousands of structures. The 22 major wine country fires, some of which PG&E equipment started, were among the most destructive fires in state history at the time.

Napa and Sonoma were two of the more than 20 counties affected by Monday’s PSPS, including Monterey and Santa Barbara counties in Central California.

“This safety shutoff is due to a dry, offshore wind event expected to start Sunday night and bring wind gusts of up to 50 mph by Monday morning,” PG&E said in a news release. “As a result of this wind event, combined with extreme to exceptional drought conditions and extremely dry vegetation, PG&E began sending advanced notifications Saturday to customers where PG&E may need to proactively turn off power for safety to reduce the risk of wildfire from energized power lines.”

The state’s largest utility said it expected to blackout 25,000 customers in “very targeted” areas starting at 4 a.m. Monday and continuing through Tuesday.

The number of customers potentially affected was a small fraction of those impacted by PG&E’s PSPS events in October 2019, which left nearly 2.4 million residents in the dark, some for up to a week, and caused an uproar among ratepayers and public officials. (See California Officials Hammer PG&E over Power Shutoffs and Calif. Regulators Bash PG&E’s Power Shutoffs.)

PG&E’s widespread use of PSPS in 2019 followed the wine country fires and the Camp Fire of November 2018, which killed at least 84 people and razed much of the town of Paradise. State fire investigators determined the cause of the Camp Fire was a broken PG&E transmission line that sparked dry vegetation. The fire exploded, driven by offshore winds like those that blew Monday.

In September 2020, PG&E blacked out 172,000 customers, or about 499,000 residents, in portions of 22 counties in the Sierra Nevada foothills, the Sacramento Valley and the northern San Francisco Bay Area. Since then, under intense pressure from the California Public Utilities Commission and the governor’s office, PG&E has made efforts to limit the scope and duration of its PSPS events. (See CPUC Orders Changes to PG&E Shutoff Rules.)

The utility set up a Wildfire Operations Center, which is staffed 24 hours a day in fire season. It is installing 1,150 weather stations, adding more than 400 high-definition fire cameras, and reserving 65 helicopters to speed line inspections and restoration work after shutoffs, it said.

The addition of 1,000 sectionalizing devices and switches have helped limit the size of PSPS outages, PG&E said.

“The scope of [Monday’s] overall event represents less than 0.5% of all PG&E customers,” the utility said, adding that “weather ‘all-clears’ will occur as early as Monday evening with restoration expected to begin Tuesday afternoon.”

“Once conditions are clear, PG&E electric crews will begin patrolling in the air, in vehicles and on foot to visually check de-energized lines for hazards or damage to make sure it is safe to restore power,” it said.

A tree falling on a PG&E line is suspected of starting this summer’s Dixie Fire, the second largest in state history, and a tree falling on a PG&E line, which remained energized despite a surrounding PSPS event, started last year’s fatal Zogg Fire, the California Department of Forestry and Fire Protection (Cal Fire) concluded.

Last month, the Shasta County district attorney’s office filed four manslaughter charges against PG&E in the Zogg Fire, marking the fourth time in five years the utility has faced charges in disasters related to its gas and electric systems. (See PG&E Denies New Manslaughter Charges.)

PG&E pleaded guilty to 84 counts of involuntary manslaughter in the Camp Fire, but it has denied the most recent manslaughter charges.

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Two New ERCOT Directors Named, Replacing Current Board

The Texas Public Utility Commission on Monday announced that a new chairman and second independent director have been selected for ERCOT’s Board of Directors, replacing the eight market segment representatives sitting on the board.

The PUC said in a release that the ERCOT Board Selection Committee had chosen Paul Foster, president of Franklin Management and founder of Western Refining, as the board’s chair and Carlos Aguilar, CEO of Texas Central Partners, as the first two directors for ERCOT’s new board.

Foster and Aguilar will join PUC Chair Peter Lake, interim ERCOT CEO Brad Jones and the Office of Public Utility Counsel’s Chris Ekoh on the board. Lake is a non-voting member, as will be ERCOT’s CEO.

The PUC said the board’s composition meets the requirements of Senate Bill 2, which replaced the five independent directors and eight market segment representatives with eight independent directors chosen by a selection committee appointed by Texas’ political leadership.

The two directors will give the board a quorum and allow it to meet Tuesday morning without the previous directors to consider ERCOT’s request for an expedited approval of amended bylaws to comply with SB2.

The PUC release quotes the commission and ERCOT’s leadership with expressing “their gratitude to the outgoing board members for their service to Texas.”

SB2 requires each board member to be a Texas resident with executive-level experience in finance, business, engineering, trading, risk management, law or electric market design. When the February winter storm nearly brought the ERCOT system to total collapse in February, Texans frustrated with the ensuing long-term outages directed their ire toward the six board members who lived outside the state. (See ERCOT Chair, 4 Directors to Resign.)

The remaining six board members are expected to be named in the coming months. The selection committee is working with a search firm to find the directors. (See Search Firm Chosen to Find New ERCOT Board Members.)

Foster has previously chaired the University of Texas System Board of Regents and been a member of the Texas Higher Education Coordinating Board, the University of Texas System Lands Advisory Board and the El Paso Branch of the Dallas Federal Reserve Bank.

Aguilar has a background in global businesses and public-private development projects; his company is working to develop a high-speed train between North Texas and the Houston area. He has an undergraduate degree in mechanical engineering from Duke University and a doctorate in technological economics from the University of Stirling in Scotland.

“We welcome these highly qualified leaders, their expertise and insights into our relentless pursuit of grid reliability,” Jones said in a statement.

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NEPOOL Participants Committee Briefs: Oct. 7, 2021

BOSTON — For the first time since March 2020, following 20 months of exclusively virtual meetings because of the COVID-19 pandemic, the NEPOOL Participants Committee on Thursday met in-person, at the Colonnade Hotel in the city’s Back Bay.

There were strict safety protocols in place to attend the meeting. Everyone who attended had to be fully vaccinated and have provided verification in advance of the meeting. There is also a citywide mask mandate in Boston, which meant that all attendees wore masks or face coverings at all times except when actively eating or drinking.

ISO-NE Responds to NESCOE, Pledges Annual Open Board Meeting

In response to the New England States Committee on Electricity (NESCOE) vision statement last October and the organization’s report to the region’s governors on “Advancing the Vision,” ISO-NE’s Board of Directors issued a formal response Sept. 23, which the committee reviewed last week.

Among the initiatives and studies is a pledge to hold an annual open meeting. Beginning next year, the board will hold an open meeting focused on the electricity markets on even-numbered years; in odd-numbered years, the meeting will focus on transmission planning, with a potential link to the biennial Regional System Plan public forum, which was most recently held on Oct. 6. (See related story, Overheard at 2021 ISO-NE Regional System Plan Forum.)

The board said it has directed RTO management to prioritize transmission planning studies and analysis of market designs in support of the states’ clean energy goals.

“The board remains committed to working with the states and NEPOOL to achieve the region’s goals for a clean energy system that is reliable and efficient,” the board said.

ISO-NE has already begun its 2050 Transmission Study, the board noted, as requested by the states. The study will take a high-level look at scenarios to reliably incorporate clean energy and distributed energy resources beyond the RTO’s current 10-year planning horizon. The RTO will also work with the states to draft corresponding changes to the tariff to enable this type of transmission study on a recurring basis, the board said.

The board also noted that ISO-NE is evaluating “wholesale market frameworks that reflect states’ policies” through a series of working group sessions of the PC. The group has been considering a regional net carbon price, a Forward Clean Energy Market and a hybrid of the two concepts. Its work will be presented in the second quarter of 2022. The RTO is also developing a proposal to eliminate the minimum offer price rule from its capacity market.

Energy Market Value Falls

ISO-NE’s energy market value for September was $497 million (through Sept. 29), down $188 million from the updated August valuation and $290 million higher than the same month in 2020, according to COO Vamsi Chadalavada’s monthly report to the PC.

September natural gas prices were 12% higher than in August. Average real-time hub LMPs were 5% lower at $46.48/MWh. Daily uplift payments totaled $1.3 million over the period, down $2 million from the adjusted August value and $1.1 million less than September 2020.

Four new resources totaling 325 MW applied for an interconnection study: one battery and three solar-plus-solar projects, with in-service dates ranging from 2022 to 2023. The RTO is currently tracking 294 generation projects that total approximately 32,907 MW.

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PJM MIC Briefs: Oct. 6, 2021

ARR/FTR Market Task Force Proposal

Members endorsed a PJM and joint stakeholder proposal at last week’s Market Implementation Committee meeting to address the RTO’s auction revenue rights (ARRs) and financial transmission rights (FTRs).

The proposal, which was worked on at the ARR/FTR Market Task Force, was endorsed with 244 “yes” votes (84%), surpassing the necessary 50% threshold to move on for a vote at the Markets and Reliability Committee. In a separate vote asking if stakeholders prefer the proposal over the status quo, the proposal received 247 “yes” votes (93%).

Three other proposals presented for a non-sector-weighted vote at the MIC failed to reach the 50% threshold to be considered for endorsement at the MRC. An endorsement vote at the MRC will face a sector-weighted vote on the issue.

Brian Chmielewski, manager of PJM’s market simulation department, reviewed the PJM/joint stakeholder proposal, saying it was “strongly driven” by the findings of a report developed by London Economics International (LEI), a consultant hired by the RTO to conduct a “holistic review” of the ARR/FTR market.

LEI was hired on the recommendation of the “Report of the Independent Consultants on the GreenHat Default,” which called for an outside expert to review PJM’s FTR market and other PJM markets to evaluate the risks and the benefits of rule changes. (See “PJM Seeking Consultant on ARR/FTR Task Force,” PJM MIC Briefs: May 13, 2020.)

Comparison-of-FTR-auctions-(London-Economics)-Content.jpgComparison of FTR auctions across several RTOs/ISOs. | London Economics

Chmielewski said the PJM proposal aimed to consider the LEI recommendations and address concerns raised by the Independent Market Monitor and stakeholders regarding the ARR/FTR market. He said the proposal also sought to maintain the consultant’s conclusion that the existing FTR product is “reasonable and generally achieving the intended purposes” of serving as a financial equivalent to firm transmission service and “ensuring open access to firm transmission service by providing a congestion-hedging function.”

PJM’s proposal was broken into three separate areas as recommended by LEI, Chmielewski said, with an ARR track for “equity,” an FTR track for “efficiency,” and a transparency track for “simplicity.” 

<img src="//www.rtoinsider.com/wp-content/uploads/2023/06/140620231686784166.jpeg" data-first-key="caption" data-second-key="credit" data-caption="

Brian Chmielewski, PJM

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Chmielewski said the ARR section was the main part of PJM’s proposal, and “far and away” the most time was spent speaking about the equity area and the allocation of rights. He said the ARR section was designed to answer a primary concern that the ability for some load to “efficiently hedge congestion costs can be deteriorated at times” when a “misalignment” occurs between the allocation of ARRs and congestion charges paid by load.

Some of the main features of the PJM proposal include a guarantee of 60% of network service peak load for each load-serving entity (LSE), Chmielewski said, which is meant to “protect zonal native load hedging ability with additional up-front capability.” He said the proposal also expands the source/sink availability for ARRs so that they “align with any source/sink that is available for bid in the annual FTR auction.”

Market Monitor Joe Bowring reviewed the IMM proposal, which only garnered 40 votes in favor (14%). Bowring said the purpose of the ARR/FTR design is to return congestion payments to the load that pays congestion.

Congestion is an overpayment by load, Bowring said, and 100% of that overpayment should be returned to load. Bowring disagreed with the LEI recommendation that load should be satisfied with receiving 50% to 75% of what is owed to load.

Greg Poulos, executive director of the Consumer Advocates of the PJM States, said he will present the IMM proposal at the MRC on behalf of the advocates as an alternative if the PJM/joint stakeholder proposal fails to be endorsed.

Erik Heinle of the D.C. Office of the People’s Counsel reviewed the group’s proposal, which was identical to the PJM proposal except that 100% of the surplus allocation was given to ARR holders. The OPC proposal received 95 votes in favor (34%).

Jau-Jia Guo of American Electric Power reviewed the company’s proposal that called for a commitment to implement a more “granular” ARR/FTR product design, including quarterly peak and off-peak ARR products. The AEP proposal received 57 votes in favor (21%).

The PJM/joint stakeholder proposal will now go to the MRC for endorsement.

Energy Efficiency Add-back Endorsed

Stakeholders endorsed the PJM/IMM proposal addressing the energy efficiency (EE) add-back in Reliability Pricing Model (RPM) auctions.

The proposal, which called for modified language to section 2.4.5 of Manual 18 to reflect revisions to the EE add-back method, was endorsed with 208 “yes” votes (90%). Members also endorsed changes to the status quo with 207 votes in favor (90%).

Jeff Bastian, senior consultant with PJM’s market operations, reviewed the joint PJM/IMM proposal addressing the calculation of the EE add-back mechanism. Members unanimously endorsed an issue charge presented by the Monitor at the August MIC meeting. (See “Energy Efficiency Add-back Issue Charge Endorsed,” PJM MIC Briefs: Aug. 11, 2021.)<img src="//www.rtoinsider.com/wp-content/uploads/2023/06/140620231686784167.jpeg" data-first-key="caption" data-second-key="credit" data-caption="

Jeff Bastian, PJM

” data-credit=”© RTO Insider LLC” style=”display: block; float: none; vertical-align: top; margin: 5px auto; text-align: right; width: 200px;” alt=”Bastian-Jeff-2019-03-06-RTO-Insider-FI” align=”right”>Jeff Bastian, PJM | © RTO Insider LLC

Bastian said the EE add-back mechanism is applied to capacity auctions to prevent the “adverse reliability impact” associated with double-counting EE as both a capacity resource and a reduction in the forecasted peak load. Bastian said the current method of determining the add-back megawatt quantity applied to a Base Residual Auction does not require it to match the megawatt quantity of EE resources that clear in that auction.

The add-back quantity in a BRA will normally exceed the cleared quantity, Bastian said, resulting in an artificial increase in the clearing price. The proposal rewrote language in Manual 18 to permit PJM to calculate the EE add-back in the capacity market clearing so that the total EE add-back megawatts offset the total cleared EE megawatts in the BRA.

Bastian said the solution “introduces an iterative approach into the auction clearing process” so that the EE add-back megawatt quantity applied to an RPM auction matches the megawatt quantity of EE resources cleared in the auction.

Bastian said PJM is seeking final endorsement at the Oct. 20 MRC to have the manual language in place for the 2023/24 BRA. PJM is currently asking FERC for a delay of the BRA, pushing the date from Dec. 1 to Jan. 25. (See PJM Proposing 2-Month Capacity Auction Delay.)

Start-up Cost Offer Development

Nicole Scott and Tom Hauske of PJM provided a first read of two proposals addressing start-up cost offer development worked on in the Cost Development Subcommittee, while some stakeholders questioned the scope of the changes coming from the subcommittee.

Scott said the issue charge for start-up costs was developed in the CDS for review and possible modifications to Manual 15. Scott said some of the key work activities included the calculation of start-up cost-based offers for steam units, combustion turbine units, combined cycle units and diesel units and a discussion on the consistency of start-up cost parameters with the start-up and notification times.

The CDS developed two proposals for consideration, Scott said, the first a joint PJM/IMM proposal and the second a clarification proposal from stakeholders. Scott said the two proposals agree on most of the start-up cost changes to Manual 15, but they differ around the issues of start-up costs, start fuels, station service and additional labor costs for combined cycle units.

Hauske said the PJM/IMM proposal calls for providing an equation to calculate start-up cost, addressing station service for non-combined cycle units, more clarification around the start maintenance adder and a definition for equivalent service hours.

Hauske said the main issue the PJM/IMM package attempted to address is the discrepancy in Manual 15 on how start-up costs are calculated. He said the manual currently allows combined cycle units to include fuel cost after a generator breaker closure and the synchronization to the grid in their calculation of start-up costs that other unit types like steam and nuclear cannot utilize.

The PJM/IMM proposal revises Manual 15 calculations for start-up cost, start fuel and station service to be consistent for all unit types, Hauske said, and it only includes costs prior to first breaker closure and after the last breaker opens.

<img src="//www.rtoinsider.com/wp-content/uploads/2023/06/140620231686784168.jpeg" data-first-key="caption" data-second-key="credit" data-caption="

Tom Hyzinski, GT Power Group

” data-credit=”© RTO Insider LLC” style=”display: block; float: none; vertical-align: top; margin: 5px auto; text-align: left; width: 200px;” alt=”Hyzinski-Tom-2017-08-22-RTO-Insider-FI.jpg” align=”left”>Tom Hyzinski, GT Power Group | © RTO Insider LLC

Tom Hyzinski of GT Power Group provided additional information of the clarification proposal. Hyzinski said the proposal was meant to offer an alternative to the PJM/IMM proposal that tries to maintain the status quo but contains some clarifications to the manual language to highlight current practices.

Hyzinski said the PJM/IMM proposal does more than just clarify language by “making a substantive change” to the way start-up costs are recovered for combined cycle units. He said the clarification proposal attempts to explain the current actual practice with combined cycle units without making significant manual updates.

Calpine’s David “Scarp” Scarpignato said he was under the impression the CDS was mainly focused on minor clarifications like the Manual 15 revisions regarding the incremental and no-load energy offers endorsed at the September MIC meeting. (See “Manual 15 Revisions Endorsed,” PJM MIC Briefs: Sept. 9, 2021.)

Scarpignato said the manual changes presented in the PJM/IMM proposal are “extremely substantive.”

Dave Anders, PJM’s director of stakeholder affairs, said the CDS has a charter approved by the MIC and can take on work within the scope of the charter. Anders said the subcommittee simply needs to let the committee to which it reports know what is being discussed.

Scarpignato said he would still like to see the issue come through the MIC where there is more stakeholder participation. He requested that a second first read be conducted at the November MIC to go over the issues more thoroughly with the committee.

“I know you guys understand it, but it’s pretty detailed for the rest of us,” Scarpignato said.

Bowring said he wanted to see the issue proceed for a vote at the November MIC since it has been “thoroughly reviewed” at the CDS, but he said he wouldn’t be opposed to having more discussion.

“I think people understand it; some just don’t like it,” Bowring said. “It is complicated, but lots of stuff at PJM is complicated.”