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November 15, 2024

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Maine One Step Closer to OSW Research Lease

Initial assessment of the offshore wind energy research lease Maine is seeking shows it would cause minimal environmental impact.

The report, by the U.S. Bureau of Ocean Energy Management, is another step toward wind power development in the Gulf of Maine but does not authorize any construction or operation. It entails only surveys, monitoring and placement of meteorological buoys.

Potential negative factors resulting from this work could include air emissions, noise, lighting, seafloor disturbance, entanglements and routine vessel discharges.

Publication of the draft assessment in the Federal Register on Friday started a 30-day comment period, during which two virtual public meetings will be held as BOEM seeks further input before finalizing the assessment.

BOEM rates potential impact at four levels: negligible, minor, moderate and major. Every effect of the research lease was projected as either negligible or minor — including on commercial and recreational fishing, which has been predicted to sustain a major adverse effect in the environmental impact studies prepared for construction and operation of the other wind farms.

Maine is positioning itself to be a pioneer in floating wind and a leader in the industry expected to develop around it. One of its state university campuses has a robust research-and-development program, and it already has floated a small-scale offshore wind turbine in state waters.

A key part of this is the research array Maine is seeking permission to build within a 10,000-acre zone 20 nautical miles offshore — up to 12 turbines with a total nameplate capacity of up to 144 MW.

The offshore wind farm proposals in the pipeline so far are all on the Outer Continental Shelf off the middle and northeast Atlantic Coast, with towers on seabed foundations in relatively shallow waters. The Gulf of Maine, like most of the Pacific Coast, is too deep for fixed-bottom development and will need to rely on floating wind technology that still is being developed and has minimal worldwide operational history.

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Michigan Capital-area Utility Outlines $750M Plan to Reduce Emissions

LANSING, Mich. — One of the state’s largest municipally owned utilities, the Lansing Board of Water & Light, said last week it will invest $750 million in renewables, storage and natural gas generation over the next decade and pledged to be carbon neutral by 2040.

The utility plans to add 658 MW of renewable energy and storage and at least 110 MW of natural gas. Its current portfolio has a nameplate capacity of 581 MW. It closed its last coal-fired plant in 2022, becoming the largest coal-free utility in Michigan.

“This is the largest planned growth in BWL’s nearly 140-year history,” General Manager Dick Peffley said in a statement.

The plan will add 2.5 to 3% to customer bills.

The clean energy projects are expected to be complete between 2025 and 2027, and include 160 MW of battery storage; 65 MW of local solar; 195 MW of additional solar outside of the Lansing region; and 238 MW of wind outside of the Lansing region. The projects were selected from among 96 offers totaling 8,330 MW in response to its “all source” request for proposals.

The utility also said it will continue its energy efficiency efforts and add demand response programs.

The electric storage facility could provide as much as 16% of the 1,000-MW storage capacity called for in Michigan’s MI Healthy Climate plan, an outsize contribution for a utility that has 100,000 electric customers and serves 6% of the state’s load.

BWL received $12 million from the Michigan Public Service Commission for the construction of 10 MW of solar and 40 MW of four-hour battery storage at Delta Energy Park, the former site of the coal-fired Eckert Power Station, which was retired in 2020.

Delta also will be the site for a new 110-MW reciprocating internal combustion engine (RICE) gas plant by 2026. BWL also called for “a possible additional gas plant at a location to be determined later dependent on future load requirements and regional energy regulations.”

The projects and estimated costs “are still under negotiations with the proposed developers and are subject to change pending contract agreements,” the utility said.

When all the new generation projects are online, a company spokesperson said, BWL will generate nearly twice as much electricity as it does now.

“Once implemented, this will bring BWL’s total generational portfolio to around 58% renewable and reduce our carbon footprint by 75% compared to 2005,” Peffley said.

The utility says the additional power generation could help attract new businesses to the capital region and also could allow for sales of excess power to other utilities.

BWL provides power to several major corporate customers, including several large General Motors plants, along with state government and residential customers in Ingham, Eaton and Clinton counties. Michigan State University, in East Lansing, generates its own electricity, though most of the rest of the city is serviced by BWL.

In addition to gas-fired plants, BWL also has two wind sites and four solar sites.

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PJM MRC/MC Preview: July 26, 2023

Below is a summary of the agenda items scheduled to be brought to a vote at the PJM Markets and Reliability Committee and Members Committee on Wednesday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.

RTO Insider will be covering the discussions and votes. See next week’s newsletter for a full report.

Markets and Reliability Committee

Consent Agenda (9:05-9:10)

The committee will be asked to endorse as part of its consent agenda:

B. proposed conforming revisions to a slate of manuals and PJM practices addressing the interconnection process overhaul approved by FERC last year (ER22-2110). (See “Manual Revisions for Interconnection Process Overhaul Sent to MRC,” PJM OC Briefs: July 13, 2023.)

C. proposed revisions to Manual 13: Emergency Operations resulting from its periodic review.

Endorsements (9:10-9:25)

1. NERC TPL-001-5.1 Manual 14B Revisions 

PJM’s Stanley Sliwa will present proposed revisions to Manual 14B: PJM Region Transmission Planning Process to conform to NERC’s TPL–001-5.1 standard. The proposal was endorsed by the Planning Committee earlier this month through the quick-fix process, which allows for a problem statement, issue charge and solution to be brought concurrently and voted on in the first meeting. (See “Stakeholders Endorse Quick Fix Manual Revisions to Conform to NERC Standards,” PJM PC/TEAC Briefs: July 11, 2023.)

The committee will be asked to endorse the proposed manual revisions upon first read.

Members Committee

Consent Agenda (11:35-11:40)

The committee will be asked to endorse as part of its consent agenda:

B. proposed clarifying revisions to PJM’s tariff, Operating Agreement and Reliability Assurance Agreement, which were approved by the Governing Documents Enhancements and Clarifications Subcommittee in April.

C. a proposed solution and corresponding tariff revisions related to calculating the smooth supply curves for the Base Residual Auctions. The changes are meant to clarify that PJM will publish only smooth supply curves following BRAs and not Incremental Auctions. (See “Stakeholders Approve Tariff Clarification on Smooth Supply Curves,” PJM MRC/MC Briefs: June 22, 2023.)

Issue Tracking: BRA Smooth Supply Curves

Endorsements (11:40-11:55)

1. IROL-CIP Cost Recovery (11:40-11:55)

PJM’s Darrell Frogg will present a proposal to create a cost-of-service mechanism for generators designated as critical to the derivation of an interconnected reliability operating limit under NERC’s Critical Infrastructure Protection standards. (See “MRC Endorses IROL-CIP Cost Recovery,” PJM MRC/MC Briefs: June 22, 2023.)

Issue Charge: IROL-CIP Cost Recovery

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Court Dismisses Environmental Justice Petitions Against Weymouth Compressor

The D.C. Circuit Court of Appeals dismissed a pair of challenges Friday to FERC’s authorization of the long-contested Weymouth, Mass., compressor station. The court determined that it lacks jurisdiction over the petitions, which were filed by a group of nearby residents to the compressor.

The ruling is the latest blow to the Fore River Basin residents and environmental justice organizations that have been fighting the compressor station for about nine years. The compressor became operational following FERC’s final authorization in September 2020.

One of the petitions challenged the FERC-issued Extension Order which gave Enbridge, the owner of the compressor station, additional time to build the project following delays to construction. The second petition asked the court to review FERC’s denial of rehearing of the In-Service Authorization Order (see FERC’s Handling of Environmental Justice Issues Debated in Court.)

“We lack jurisdiction to consider either petition, so we dismiss them both,” the D.C. Circuit wrote.

Opposition to the project has centered around the cumulative health consequences and acute dangers of siting the facility near residential neighborhoods and industrial facilities, including multiple fuel storage areas, the largest hazardous waste disposal site in New England, a natural gas plant and a chemical manufacturing facility.

To make matters even more precarious, opponents argue, the compressor station was built on a flood-prone parcel of landfill that juts out into the water and is contaminated with a mix of diesel fuel, arsenic and coal ash. Opponents of the compressor expressed disappointment in the court’s ruling.

“This is a demoralizing outcome that makes it clear that health and safety play second fiddle to fossil fuels and profit,” said Braintree Town Councilor Elizabeth Maglio, a vocal opponent of the compressor.

A 2019 background health analysis conducted by the state found that communities in areas surrounding the compressor site have elevated concentrations of conditions related to air pollution, including asthma, heart attacks, COPD, heart disease and lung and bronchus cancer.

Meanwhile, a 2002 health survey of Weymouth residents found higher-than-expected levels of aplastic anemia, a bone marrow condition linked to benzene, a pollutant frequently found in uncombusted natural gas in the Greater Boston area.

Michael Hayden of Morrison Mahoney LLP, the attorney representing local residents, told RTO Insider that while the Court held that there is no jurisdiction for the appeal, “the Court’s decision does not comment upon our environmental justice concerns or arguments.”

In consideration of the first petition, regarding the Extension Order, the D.C Circuit ruling did acknowledge that the petitioners had demonstrated injuries related to the compressor station’s siting, including from air pollution and increased safety risks. However, it said FERC already reconsidered the Extension Order, and ruled “the Fore River Residents have already received all of the procedural relief they requested.”

“While we’re disappointed, we are not exactly surprised,” said Alice Arena of Fore River Residents Against the Compressor Station, one of the petitioners in the case. “This was the same court that totally ignored the fact that FERC violated its own regulations in allowing the Weymouth compressor without an [environmental impact statement].”

Hayden said he was unsure if the defendants would pursue further challenges to FERC’s approval of the compressor station.

“We need to study it and determine whether there’s any further appellate action warranted,” Hayden said, noting there’s a trial scheduled in October before the Massachusetts Department of Environmental Protection on the compressor station’s Chapter 91 waterways license.

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DC Circuit Sides with FERC on Alleviating Spiking Prices in Virginia

The D.C. Circuit Court of Appeals on Friday upheld a FERC decision suspending the application of PJM’s transmission constraint penalty factor (TCPF) after it led to spiking prices that could not be addressed on Virginia’s Northern Neck Peninsula (22-1090).

The TCPF caused prices to spike on the peninsula in the Chesapeake Bay after a transmission line was taken out of service early last year so the local grid could be upgraded. Cheaper generation or demand response were not available in the area to offset its impact, so PJM requested it suspend the rule in this case as the higher prices were incapable of eliciting any kind of market response.

FERC approved PJM’s request, with a dissent from Commissioner James Danly. Energy trading firm Citadel FNGE appealed the decision to the D.C. Circuit. Judge Justin Walker (a Trump appointee) dissented from the majority in the case, saying the court should have remanded it to the commission. (See FERC Approves Pause of PJM Tx Constraint Penalty Factor in Va.)

PJM since has changed the rule so the TCPF will be suspended automatically in similar circumstances going forward. (See FERC Approves PJM Proposal to Reduce Congestion Penalty During Grid Upgrades.)

Chief Judge Sri Srinivasan and Judge Patricia Millet (both Obama appointees) sided with FERC, saying it was reasonable to suspend the rule, which is meant to get a market response that ultimately would solve the congestion at issue.

“Because application of the penalty factor increased costs for consumers without a commensurate benefit, the commission reasonably found that its application in this context was unjust and unreasonable,” the court said.

The TCPF represents the maximum cost that PJM will incur to resolve the problem-causing congestion, with an algorithm seeking the least-cost way to relieve congestion, which if not available leads to prices of $2,000/MWh.

With the transmission line out, the peninsula’s customers could be served only by two other transmission lines and a set of combustion turbine units.

“That lack of available resources caused the local marginal price to fluctuate drastically in times of congestion,” the court said. “For example, even when the turbine units were fully operating in the early morning hours, they were insufficient to prevent congestion, so the penalty factor kicked in.”

Local solar plus those combustion turbines were able to mitigate prices when the sun was out, but the penalty factor was unable to send consistent or reliable signs about whether an investment or response to the congestion was needed.

“Material short-term investments would not occur, PJM explained, because new resources would not come online until after the Lanexa line upgrade was completed,” the court said. “At that point, the demand for the newly placed resource would evaporate.”

Citadel challenged PJM, saying the RTO failed to prove a link between the temporary $2,000/MWh prices and what consumers in the area actually paid. It also argued that PJM failed to prove that nothing could respond to the price signals and argued suspending the rule would inject regulatory uncertainty into the market.

The court said FERC was not required to show the spiking congestion costs would impact retail rates because the Federal Power Act refers only to the unjustness and unreasonableness of rates.

“The commission concluded that increased prices on one side of the balance without any value on the other side of the scale — all pain and no gain — were unjust and unreasonable,” the court said.

While customers pay a zonal rate, the higher congestion costs would go into that calculation, leading to overall higher rates, and Citadel failed to show any offsetting impacts, it added.

The firm also argued the suspension would harm the financial transmission rights market, in which it participates.

“But the temporary suspension of the penalty factor in one geographically unique area does not stop financial firms from benefiting from congestion pricing,” the court said. “Financial firms will still receive congestion costs, albeit less in one small part of the grid, during the temporary suspension of the penalty factor.”

Walker’s Dissent

Judge Walker said the court should have remanded the order to FERC for further proceedings, with Citadel’s arguments having convinced him. Transmission expansion was sped up after FERC’s order, which Citadel argued showed the constraint was working.

“Yet when FERC was later given evidence that the penalty factor was incentivizing transmission investment, FERC moved the goalposts,” Walker said. “Instead of reasoning, as it had before, that the rate was providing no benefit, FERC instead said any benefit it provided wasn’t big enough.”

That shift in standards was arbitrary and capricious, so the order should have been remanded, he added.

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PJM Promises to Work with Ohio Legislators on Cost Allocation

PJM CEO Manu Asthana thanked a group of Ohio legislators in a letter Friday for their “constructive engagement” on the cost allocation implications of Illinois’ climate policies that will require fossil plants to start shutting down starting in 2030. (See Ohio Legislators Raise Concerns About Cost Impact of Illinois’ CEJA.)

Ohio House Public Utilities Committee Chair Dick Stein (R) and Senate Energy and Public Utilities Committee Chair Bill Reineke, along with 10 other colleagues, sent PJM a letter raising concerns about a preliminary estimate the RTO produced saying Illinois’ policy of retiring thermal power plants would lead to about $2 billion in transmission upgrades. In the letter and in meetings with RTO staff, they asked for a more formal estimate, including the assumption that Ohio is left out of that cost allocation.

“We appreciated the frank and open discussion regarding your concerns and your understanding of the limitations PJM faces in conducting exclusionary transmission studies,” Asthana wrote back. “The model that PJM uses for transmission analysis is not configured in a way that would let us exclude Ohio from the study results. The high-voltage transmission system is an interstate system, and electrons travel without consideration for state boundaries.”

Asthana said PJM is working to reform its markets and transmission planning, and in that effort, it hopes to better understand the impacts of federal and state policies on its system. “PJM pledges to work with Ohio policymakers to keep you fully informed of the transmission project development and cost allocation implications of our ongoing planning efforts related to this dynamic system.”

The Ohio legislators had written that the state has had success with PJM’s competitive markets, and Stein repeated that assertion in an interview with RTO Insider last week. But he said his constituents and others should not have to pay for the effects of another state’s policies.

“Ohio residents — and Pennsylvania and other surrounding states that are going to have to feed that power to them — shouldn’t be responsible for a policy another state makes that is that costly across the region,” Stein said.

Stein said he and his colleagues would continue to work with stakeholders in other states to ensure that reliability and affordability are maintained as the grid becomes more clean.

Illinois is not the only state shifting away from fossil fuel power plants to cleaner generation, the latter of which is exclusively being paid for by those state’s ratepayers. That new, renewable generation is going to add cheap power to the grid, which would tend to lower wholesale prices everywhere in PJM.

Those wholesale price impacts are part of the calculus going forward, but Stein said another concern is the capacity market and its continued ability to keep dispatchable generation that Ohio plans to keep using online. One option Stein said is off the table is state subsidies for those dispatchable plants, as the Ohio legislature does not want a repeat of House Bill 6, which was influenced by a bribery scheme by FirstEnergy. (See Former Ohio House Speaker Householder Sentenced to 20 Years in Prison.)

“All we’re trying to do is make sure we advocate for what we think is good policies here for Ohio; obviously, the people in Illinois are advocating [for] what they think the people in Illinois want,” Stein said. “And it really puts the most pressure on PJM because somehow they’ve got to bring all these elements together and make everybody happy. And as we well know, sometimes that’s not easy, if at all possible.”

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Ramping Shortfall Sparks CAISO’s 1st Summer Emergency

CAISO issued its first energy emergency alert (EEA) of the summer Thursday evening after coming up short on the ramping capacity needed to meet its peak net load as solar output rolled off its system during sunset.

The California grid operator declared an EEA-1 at 7:30 p.m. PT on a day marked by largely normal summer temperatures in most of the state’s population centers, as well as an elevated but relatively moderate system peak load of 42,266 MW, which occurred at 6:30 p.m. An EEA-1 represents the lowest level of grid emergency, called by the ISO when it confronts capacity shortages after all available resources either are in use or have been committed to use, prompting the need for conservation.

CAISO data shows that the ISO’s net load — total system load minus output from wind and solar — began to exceed the ISO’s day-ahead forecasts at about 6:40 p.m. By 7:50 p.m., as system load tapered to 40,989 MW, net load simultaneously rose to its daily peak of 37,038 MW, exceeding the day-ahead net load forecast of 35,533 MW for that five-minute interval.

“The market went into the hour a bit thin on the interchange while net demand was increasing,” CAISO spokesperson Anne Gonzales told RTO Insider. “The amount of energy available within the hour was not as robust during net load peak as solar ramped off the system, compared to other similar days. As a result, within the hour, the market was not moving enough resources to balance supply and demand while solar was ramping down.”

CAISO called on demand response resources beginning at the 7:50 p.m. interval, quickly reducing net load to levels closer to forecast. The EEA-1 was concluded at 8:30 p.m.

“As soon as the operators became aware of the situation, they manually dispatched additional generation, deployed some demand response programs available to them and made adjustments in the market to increase energy output and the EEA-1 was soon canceled,” Gonzales said.

The role of imports in the emergency remains an open question. While much of California saw moderate weather that day, neighboring areas in the Southwest continued to endure a record-setting heat wave accompanied by high electricity demand.

Asked whether “thin” conditions on the interchange indicated that imports into the ISO were lower than expected during the event, Gonzales said, “We’re still doing analysis on that. Demand came in slightly higher than forecast and more energy was needed for about an hour during the net peak load. We will know more after market analysis, however.”

Gonzales said the emergency would cause CAISO to make “adjustments going into the net peak hours to account for this going forward,” but added that it did not expect to issue a flex alert, EEA watch or call for restricted maintenance operations over the weekend.

Real-time prices during the event surged to around $250/MWh at nodes across the ISO, after hovering around $30/MWh and lower in the preceding intervals.

The EEA-1 occurred about a week after CAISO announced that this year it hit a 5,000-MW milestone for installed battery capacity, reaching 5,600 MW on July 1. California has moved aggressively to install additional batteries to help meet evening ramps, and the ISO expects to bring on an additional 2,000 MW in the next couple of months, CEO Elliot Mainzer said Wednesday during the joint meeting of the CAISO Board of Governors and Western Energy Imbalance Market’s Governing Body.

During that joint meeting, Mainzer also lauded the performance of CAISO and the wider West for managing challenging conditions in the face of widespread and persistent heat.

“Fortunately, notwithstanding a few local challenges, I think the overall grid has held up well, which I think points to certainly a lot of work within California and across the West on resource adequacy, bringing new resources onboard. Obviously outstanding hydro conditions inside California, and a tremendous amount of operational coordination and communication coordination around the region” also helped, Mainzer said.

“Of course, we have a lot of summer left. Ever vigilant, ever watchful,” he added.

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WEIM Withdraws Change to Base Schedule Deadline

CAISO’s Western Energy Imbalance Market (WEIM) last week took the unusual step of rescinding a rule change and associated functionality that it never actually implemented.

At their monthly joint meeting Thursday, the WEIM Governing Body and the CAISO Board of Governors approved an ISO staff request to withdraw a 2020 tariff revision that would have shifted the WEIM’s market deadline for submitting base schedules from 40 minutes before a delivery hour (T-40) to 30 minutes (T-30) before. The shorter timeline was intended to accommodate energy products in Bonneville Power Administration (BPA) power purchase agreements that can be scheduled after the T-40 deadline. BPA joined the WEIM in 2022. (See CAISO Floats EIM Base Schedule Rule Changes.)

CAISO’s implementation of the request always was contingent on the ISO’s ability to accommodate the change without compromising its performance in solving the real-time market, Danny Johnson, ISO market design sector manager, explained to the two governing boards.

But Johnson said testing showed CAISO “is unable to support this functionality when considered in conjunction with other real-time market enhancements,” specifically the flexible ramping product refinements that went live in the market in February.

“That initiative … increases both the reliability and the efficiency of the real-time markets through procuring flexible deliverable capacity to meet net load uncertainty, and implementing that functionality required additional computational time,” he said. “Once that was implemented, we determined we would not be also able to implement a base schedule submission deadline at T-30.”

By that time, the ISO also had determined that BPA could fully participate in the WEIM without instituting the scheduling changes.

“We largely attribute their ability to participate successfully to the tagging and scheduling practices of BPA’s WEIM neighbors,” Johnson said.

Johnson said BPA was disappointed when CAISO signaled its intent to withdraw the rule change, but also understood the technical constraints around implementing it.

In comments to CAISO, NV Energy said it had hoped to use the additional time created by the T-30 deadline to manage the variability of the net load uncertainty now included in the WEIM resource sufficiency evaluation done ahead of every delivery hour. But the utility also did not object to withdrawal of the rule change.

“Management recognizes this concern, and we’re committing to [working] with both NVE and all stakeholders to better understand the concerns on the newly implemented net load uncertainty requirements,” Johnson said.

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Biden Admin. to Auction First OSW Leases in the Gulf of Mexico

The Biden administration announced Thursday that it will auction approximately 3.7 GW worth of offshore wind energy leases in the Gulf of Mexico on Aug. 29, its first in the Gulf.

The Interior Department’s Bureau of Ocean Energy Management is responsible for selling the OSW leases, which comprise over 300,000 acres of federally owned waters, including a plot offshore Lake Charles, La., and two offshore Galveston, Texas.

The Interior Department announced in February it would make the leases available for sale. (See Interior Proposes 1st Lease for Offshore Wind in Gulf of Mexico.) A list of eligible bidders and stipulations is in the Final Sale Notice.

“The Gulf of Mexico is poised to play a key role in our nation’s transition to a clean energy future,” said BOEM Director Elizabeth Klein, adding that, “today’s announcement follows years of engagement with government agencies, states, ocean users and stakeholders in the Gulf of Mexico region.”

Map of final OSW lease areas | BOEM

Reactions

President Joe Biden on Thursday touted the administration’s OSW efforts at a shipyard in Philadelphia, while his administration released a fact sheet touting its progress on the economy and clean energy.

“We’re going to the Gulf,” President Biden said at the “steel-cutting” ceremony for the Acadia, the first U.S.-built subsea rock installation vessel for wind turbine foundations. The $246-million vessel is being built for Great Lakes Dredge & Dock Corp.

The opening of OSW auctions in the Gulf is a key moment for Biden and his “Bidenomics” agenda, which emphasizes both climate action and domestic manufacturing, since the administration wants to deploy 30 GW of OSW by 2030.

Liz Burdock, CEO of the Business Network for Offshore Wind, celebrated the event alongside Biden. “The Biden-Harris administration is helping make offshore wind a reality by bringing certainty to the permitting process, making investments in ports and transmission and incentivizing domestic manufacturing,” she said.

“It was great to be with so many offshore wind leaders today as President Biden recognized the significant milestone this vessel construction represents for the U.S. supply chain, which comes amid a flurry of actions from BOEM in recent weeks to advance projects through the permitting process,” she added.

“As President Biden made clear today during his trip to visit the Acadia vessel in the Philadelphia shipyard, America’s historic investment in clean power is bringing manufacturing home,” said Josh Kaplowitz, vice president for OSW at the American Clean Power Association.

Helen Rose Patterson, senior campaign manager for OSW at the National Wildlife Federation, also commended the lease, but added, “we look forward to working with the Interior Department, wildlife experts and companies to ensure that potential offshore wind projects avoid, minimize and mitigate impacts to migratory birds, marine mammals, sea floor habitat, and deliver benefits to coastal communities.”

The National Ocean Industries Association (NOIA), which represents both OSW and fossil fuel companies, said, “with the introduction of offshore wind in the Gulf Coast, numerous local companies will now have the opportunity to actively participate in the construction of new wind projects closer to home.”

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Dems Introduce Bill on Transmission Planning, RTO Transparency

Congressional Democrats have reintroduced legislation that would require FERC to establish interregional and interconnection-wide transmission planning processes and increase RTO transparency requirements.

Sen. Edward Markey (D-Mass.) introduced the bill to the Senate, saying the Connecting Hard-to-reach Areas with Renewably Generated Energy (CHARGE) Act would aid the development of transmission needed to bring clean energy onto the grid. Reps. Alexandria Ocasio-Cortez (D-N.Y.) and Greg Casar (D-Texas) introduced the bill in the House.

“While there has been rapid growth of renewable energy resources and skyrocketing public demand for clean energy, there is not nearly enough capacity in our power lines to bridge the gap between clean power and the cities and towns that need it. The CHARGE Act changes that,” Markey said in a statement announcing the legislation.

Interregional Transmission Planning

The legislation would require FERC to engage in interregional and interconnection-wide transmission planning at least every four years and consider the benefits of a potential project, including reduced energy and ancillary service costs, access to generation in neighboring regions, delivery of renewable energy, and improvements to grid flexibility and reliability. FERC also would be required to consider the potential of grid-enhancing technologies (GETs), such as dynamic line rating and storage-as-transmission.

Developers of interregional projects could submit costs to FERC for recovery, with cost allocation based on the project’s benefits. The bill would seek to avoid cost allocation mechanisms that might discourage energy efficiency, demand response, storage and distributed resources.

The bill also would change the cost allocation for new interconnections to prohibit utilities from requiring generation developers to bear the full — or a disproportionate — cost for network upgrades needed to connect their projects to the grid. Instead, FERC would encourage the creation of cost-sharing models that allocate costs based on the “broad set of benefits and beneficiaries for any network upgrades.”

The legislation would require RTOs to establish independent transmission monitors to oversee planning and operations and look for inefficiencies and practices that may contribute to unreasonable rates for consumers. The monitors also would review project costs, identify where non-wire or interregional project alternatives may be most cost-effective and provide guidance to transmission owners on operations, planning and cost allocation.

FERC would be required to create an Office of Transmission to review projects submitted by utilities in accordance with regional and interregional transmission planning processes. The office also would investigate ways to alleviate interconnection queue backlogs and explore opportunities to improve transmission planning and use GETs.

Ocasio-Cortez and Casar highlighted the importance of new transmission for developing renewable energy and addressing climate change.

“Our patchwork transmission system is blocking billions of dollars in new renewable deployment,” Ocasio-Cortez said. “This same transmission system is also increasingly vulnerable to widespread power outages in nearly every part of the country. The CHARGE Act is the key to updating this transmission network so we can plan for and meet the growing demand for grid resilience and renewable energy across the U.S.”

“As the climate crisis worsens, we must do everything we can to increase grid reliability across the country. That’s why we must pass the CHARGE Act,” Casar said. “Every single family should be able to rely on their utilities.”

Increased RTO Transparency Requirements

The bill would introduce several transparency requirements for RTOs and the commission, including stakeholder meetings being recorded and transcribed, records of votes being public and RTOs being subject to the Freedom of Information Act.

A 30-member advisory committee would be established by FERC to provide recommendations on the governance and oversight of RTOs and their stakeholder processes, with the goals of promoting competition, reliability and affordability in transmission planning. The committee also would consider improvements that could be made to transparency and decision-making in non-RTO regions.

Consumer organizations would be granted full voting and participation rights in stakeholder meetings, and RTOs would be required to provide intervenor compensation for public interest participation in RTO processes.

A handful of the transparency provisions mirror state initiatives relating to RTO governance. A bill introduced in the Maryland House of Delegates this year would have required utilities participating in stakeholder meetings to report their votes to the state each year. (See Maryland Bill Would Require Utilities to Report Votes at PJM.)

Additionally, the West Virginia Public Service Commission in March filed a complaint with FERC seeking access to PJM’s Member Liaison Committee, which is open only to voting members. (See W. Va. PSC Files Complaint over PJM Meeting Policy.)

Under the Markey bill, FERC and utilities would be required to coordinate with EPA and the Energy Information Administration to create a public database with hourly operating data for generators including fuel type, marginal greenhouse gas emissions per megawatt-hour and other attributes updated as close to real time as possible.

The legislation would direct the National Academies of Sciences, Engineering and Medicine to work with EPA, DOE and FERC to draft a public report identifying the effects on consumers of procuring energy competitively outside of utilities in markets administered by RTOs or other independent organizations compared with noncompetitive models. The study would account for factors such as cost savings, improved grid reliability and GHG emissions.

Public Interest and Climate Organizations Endorse Bill

Several climate and consumer advocacy groups endorsed the bill, including the American Council on Renewable Energy (ACORE), Americans for a Clean Energy Grid (ACEG), the Natural Resources Defense Council and Public Citizen.

“Our clean energy transition depends on building new high-capacity transmission lines. We need legislation that will accelerate this development, unlocking new domestic energy resources and making sure the lights stay on during severe weather episodes like the intense heat waves we’ve experienced across America this summer,” said ACEG Executive Director Christina Hayes.

Tyson Slocum, director of Public Citizen’s Energy Program, said the bill’s transparency and transmission monitor requirements would ensure that transmission development proceeds with consumer protections built in.

“Among many other accomplishments, the legislation would impose needed transparency standards, public accountability and governance reform for America’s private RTO grid operators, including subjecting them to the federal Freedom of Information Act; empower the public and energy justice communities with access to resources to participate in FERC and RTO proceedings by requiring FERC’s Office of Public Participation to provide intervenor funding, and; ensure the electric transmission buildout maximizes consumer protections through a new independent transmission monitor,” he said in a statement.

ACORE President Gregory Wetstone said the bill would establish critical provisions around interregional planning and would promote reliability by establishing minimum transfer requirements between transmission planning regions during severe weather.

“This legislation lays the groundwork for the construction of critical interstate transmission lines. The bill also reforms participant funding, a crucial step to help bring more clean energy resources onto the grid, and establishes a sorely needed mandate for a minimum transfer capacity between grid planning regions that will bolster reliability and better enable our electric power system to withstand increasingly frequent extreme weather events,” he said.