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November 7, 2024

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Stakeholder Soapbox: PJM Markets: More ‘Jeopardy,’ Less ‘The Price Is Right’

By Vince Duane and Tony Clark

Vince-Duane-Author-Headshot.jpgVince Duane

Our July whitepaper, Stretched to the Breaking Point:  RTOs and the Clean Energy Transition, emphasized the point that if an RTO was going to clear a centralized auction to form a single marginal price payable to all megawatt hours generated, then that RTO had better “get the price right.” Everything else (and we mean that literally) flows from getting price right: reliable operations, demand response and efficient consumption decisions, generator investment and retirement, accurate transmission planning, and an efficient financial transmission rights regime to manage congestion. Textbook economics instructs that the “right” price is a function of the cost of production and supply and demand.

In the real world, prices are rarely perfectly “right.” Distortions of various types are introduced. Not to mention the perfectly competitive conditions required to form the “right price” do not always exist. In the realm of RTOs, the term conceding this reality — a description one used to encounter more frequently in FERC orders and RTO commentary — was to aspire to “workably competitive” markets.

The question of price in RTOs surfaced again recently in the commission’s split decision on PJM’s “focused” minimum offer price rule (MOPR) filing. Last week, FERC Chairman Richard Glick and Commissioner Allison Clements published a joint statement comprehensively explaining why they support the PJM MOPR proposal (the “Joint Statement”). Regardless of whether one agrees with the ultimate conclusion in the Joint Statement, the broader question about RTO market design and its durability to handle industry transformation would benefit from reaching a shared understanding on key points. (See related story, ‘Good Riddance’ to Old PJM MOPR, Glick Says.’)

Anthony-Clark-Author-Headshot.jpgTony Clark

The first such point is dismissing those that complain about state subsidies that support particular generation as wedded impractically to what the Joint Statement terms an “abstract concept of market integrity.” What the Joint Statement calls “market integrity” is what we call “getting the price right.” It’s hardly an abstraction. As we’ve pointed out, it’s the heart of the engine that drives RTO markets and it deserves thoughtful consideration.

The second and related point involves state actions that affect this engine and the nature of these actions. More specifically, it is the need to distinguish actions which are problematic “distortions” from actions that, while they affect price, create no problem for RTO markets. By noting that all manner of public and private action affect price, including actions that increase (as opposed to suppress) price, the Joint Statement essentially throws up its hands and concludes there is no “principled distinction” to be drawn and any effort to do so would result in “arbitrary and burdensome line-drawing.”

There is a point here. Toward the goal of “workably competitive” markets, throughout its history at PJM, MOPR tried to separate actionable subsidies from those that could be ignored, or had to be accepted, while conceding all subsidies created price suppression. We fear the Joint Statement gives up too quickly and justifies surrender based on a false equivalence of subsidy compared to a cost imposed by tax or regulation.

Again, price starts with cost. As noted by the Joint Statement, “Siting policies, tax rules, and labor regulations, for example” or a carbon tax all work to increase the cost of production that will be captured in the generator’s offer and ultimately inform the marketplace of the full and true cost of generating a megawatt hour. However, imposing a cost through regulation on a negative externality, be it lost workdays in the labor context or carbon in the climate context, is very different from subsidization. Different not just in approach, but in outcome.   

For example, the superior efficiency and environmental outcomes that result from putting a cost on carbon as opposed to subsidizing carbon-free activity are well accepted. Undoubtedly, however, the commission’s job is not to disfavor subsidies compared to alternatives that economists find preferable. But the commission is an economic regulator and it should be worried about the different economic consequences that a subsidy will cause to market structures it has sanctioned as compared with regulations or taxes that price the externality.  

And here is where we believe the Joint Statement falls short. The commissioners are not wrong to accept that states will prefer certain resources and will take actions to support those resources, regardless of what type of MOPR is in place. But once subsidy is accepted as a given, then the commission must ask whether the RTO market structure, predicated on a single-clearing marginal price, remains able to function as intended — and if not, what changes must occur. This gets to the very heart of the commission’s statutory duty to ensure wholesale rates remain just and reasonable.

The fact that RTO markets wholly depend on “getting price right” means offers must reflect accurate costs of production. The Joint Statement appears to contort subsidies as a kind of reduction in the cost of production to then conclude that a market riddled with subsidy “will provide accurate price signals … by allowing capacity market sellers to include state support in their offers.” In reality, what is meant by “include” here is that subsidized sellers will be able to exclude actual costs of production from their offers.

Nobel prize winning economist William Nordhaus extensively details the economic distortions that separate a subsidy from a regulatory tax or cost in his book, A Question of Balance: Weighing the Options on Global Warming Policies. The distortions from subsidy that he identifies in general markets relative to policies that impose cost by way of tax or regulation also show up, perhaps more acutely, in the designed, single-clearing price RTO markets. Though the Joint Statement’s conflation of hand outs and imposed regulatory costs weakens its argument, what we find more troubling is the risk that needed changes to RTO market design — changes we argue will be profound and foundational — may be ignored at the very moment when they most require attention.

Former FERC Commissioner Tony Clark is a senior adviser at Wilkinson Barker Knauer.  Vincent Duane is principal of Copper Monarch and the former SVP for law, compliance and external relations for PJM.

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NYISO Details Comprehensive Mitigation Review, Related Impacts

Stakeholders last week discussed NYISO’s comprehensive mitigation review proposal and presentations on related consumer and market impacts from implementing changes to the ISO’s buyer-side mitigation (BSM) rules.

The ISO is developing a proposal to help ensure that the capacity market still results in just in reasonable outcomes after an influx of thousands of megawatts of state-supported resources and will at the same time succeed with FERC and avoid any unnecessary litigation, Michael DeSocio, NYISO director of market design, told the Installed Capacity (ICAP) Market Issues Working Group.

“We’re very focused on making sure that the package of changes supports the goal here,” DeSocio said.

New York’s Climate Leadership and Community Protection Act (CLCPA) requires the state to procure large amounts of renewable energy to get to zero-emission electricity by 2040, and similar efforts around the country are challenging regulators, as well as grid and wholesale electricity market planners.

NYISO also presented on the methodology used to measure market impacts, and the Market Monitor, Potomac Economics, presented on capacity accreditation and related consumer impacts evaluation.

Marginal-accreditation-(Potomac-Economics)-Content.jpgThe NYISO MMU says that marginal accreditation allows the more efficient resource to be selected. | Potomac Economics

“The intent here is to assess the marginal accreditation of all resources … and we have about a six-week window to do that from when the [Installed Reserve Margin] studies are finalized and when we need to have these accreditation values determined,” DeSocio said.

“We are proposing to value the capacity accreditation of all resources based upon their marginal reliability contribution,” said Zachary Smith, manager of capacity market design.

NYISO wants to complete these reforms in time for the Class Year 2021 BSM evaluations and intends to address capacity accreditation in different phases, with the Phase 1 tariff changes to be discussed through year-end 2021, and Phase 2 discussion of procedures and details expected to start around January and run throughout 2022. (See NYISO Reviews Mitigation Efforts, Updates Timeline.)

Market Outcomes Analysis

NYISO in August introduced Analysis Group’s study that is modeling 10-year capacity supply and demand curves and identifying the resulting market outcomes to support BSM rule revisions, and the consultants presented the draft study results on Friday.

The purpose of the analysis is to determine whether the NYISO capacity market will support the continued achievement of resource adequacy in the state of New York through competitive capacity market auctions administered in concert with the rollout of CLCPA resources, said Paul Hibbard, Analysis Group principal.

Specifically, the study seeks to answer two questions:

a) With the proposed BSM reforms in place, will the NYISO capacity market continue to produce competitive market outcomes?

b) With the proposed BSM Reforms in place, will the NYISO capacity market continue to provide financial incentives for the retention and addition of resources needed to maintain power system reliability?

Importantly, while the results for 10 years out – 2032 – are necessarily more uncertain, the results of modeling various scenarios in 2032 are consistent with the observations based on the 2026 model year, the study said.

Analysts realized that the “load scenario in the 2021 Gold Book was closer to the progression of peak load over time in the Grid in Transition study, which is the basis of our load generation assumption, so we adapted peak load to be consistent with that,” Hibbard said.

Changes underlying the results for 2026 include significant changes to the assumed resources on the system compared to 2022. Specifically, in the four years since 2022:

  • Fossil fuel ICAP has decreased by 2,834 MW;
  • Onshore wind has increased by 244 MW;
  • Offshore wind has increased by 1,200 MW;
  • Grid-connected solar photovoltaic capacity has increased by 5,000 MW;
  • Battery storage resources (two-hour and four-hour) has increased by 1,571 MW.

Despite the significant addition of zero-offer CLCPA resources by 2026, the market retains 31,485 ICAP MW (29,309 UCAP MW) of thermal, hydro and nuclear capacity, and 5,772 ICAP MW (5,650 UCAP MW) of other resources (e.g., biogen, pumped storage, imports, Special Case Resources). In total, the market supply curve includes 42,939 ICAP MW (37,985 UCAP MW) in 2022, and 48,021 MW ICAP (37,034 MW UCAP) in 2026.

NYCA-Results-(Analysis-Group)-Content.jpgThe tables contain the results of the analysis for the New York Control Area (NYCA) as a whole, and for each of the NYISO capacity market localities, providing expected prices in dollars per kilowatt-month ($/kW-mo) and clearing quantities in unforced capacity megawatts (UCAP MW) by year, season, and locality. | Analysis Group

Several stakeholder expressed concern that all fossil fuel resources would be treated comparably for capacity accreditation going forward.

“The intent is to evaluate all fossil fuel resources when we move forward with the accreditation approach,” DeSocio said. “We expect to run some sensitivities with more rigor in the next phase of the process.”

ICAP-UCAP-Reference-Price-Translation-(NYISO)-Content.jpgNYISO is proposing to adopt the MMU…s recommendation to translate the ICAP Reference Price to a UCAP Reference Price using the derating factor of the peaking unit underlying each ICAP Demand Curve. | NYISO

The ISO’s  intent is to try to perform that analysis and lay out some of those comparisons in the next phase, but at the moment “we don’t have the tools with the ability to run that type of analysis, so we need to work with GE to help develop those tools,” DeSocio said.

NYISO will address any stakeholder feedback at the October 29 ICAP meeting, including updates to tariff language if necessary, and at the November 2 meeting Potomac Economics and NYISO will present the consumer impact analysis of the capacity accreditation proposal.

The ISO plans to bring tariff updates before the Business Issues Committee and Management Committee in November.

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ISO-NE Planning Advisory Committee Briefs: Oct. 20, 2021

Regional System Plan Updates

The ISO-NE Planning Advisory Committee on Wednesday received a project list update for the Regional System Plan (RSP) from Rudi Vega, the RTO’s principal engineer for transmission planning, that included 12 new projects to resolve thermal overloads and voltage violations in New Hampshire and Maine.

Eight of the projects are for Maine and involve rebuilding 21.7 miles of an existing 115-kV line with additional work on MVAR synchronous condensers, capacitors and reactors. The total cost across all projects is $158.6 million.

The other four projects, in New Hampshire, will cost a total of $134.9 million. They also involve the installation of MVAR synchronous condensers and capacitors, in addition to 115-kV and 345-kV breakers.

ISO-NE also informed the PAC that it had changed the cost estimates for two projects since the previous list in June: an increase of  $7.1 million for the Southeast Massachusetts/Rhode Island Reliability Project (SEMA/RI), based on a transmission cost allocation application submitted in August; and a reduction of $8 million for the Greater Boston Project.

Three projects have been canceled since the June update, as they are no longer needed because of the New Hampshire and Maine solutions:

  • a new, $62.7 million 115-kV line section and upgraded section between Coopers Mills and Highland substations at the Maine Mid-Coast Spur;
  • adding a second 115/345-kV autotransformer at the existing 115-kV Kimball Road substation in Maine, along with moving one of the 115-kV/30-MVAR capacitor banks, which would have cost $3.3 million; and
  • installing a transfer trip at Kimball Road to disconnect the town of Lovell, Maine, from 115 kV for an estimated $0.5 million.

Eversource Details Phase II of Wood Structure Replacement Program

Eversource Energy (NYSE:ES) will replace 241 laminated wood structures across five 115-kV transmission lines in New Hampshire and one 345-kV line in Connecticut with weathering steel monopoles, installation of lightning arrestors and counterpoise grounding, according to a presentation from the utility.

According to Eversource’s Dave Burnham, the new monopoles would allow the utility to comply with current clearance and strength code requirements, improve reliability and storm resilience, and support larger conductor sizes if needed in the future.

Burnham also said recent cross-sectional inspections of removed wood structures uncovered significant damage not detected in previous, visual inspections, such as:

  • rot present throughout the length;
  • open joints at the top, allowing free entry of water;
  • damp wood at the center, soft with rot;
  • voids between layers of varying size and location, but present on each cross-sectional cut; and
  • additional splitting behind surface cracks.

Replacements performed since March have continued to uncover structural damage. (See “Eversource Replacing Wood Structures in NH,” ISO-NE Planning Advisory Committee Meeting Briefs: March 17, 2021.) Eversource says it will coordinate replacement schedules with ongoing projects to maximize mobilization, permitting and outreach efforts, and shared right-of-way access.

The current work addresses priority lines at the cost of $55.6 million, with in-service dates ranging from the first quarter of 2022 to the first quarter of 2023, Eversource said. Additional structures removed during these projects will continue to be assessed for internal damage. The utility will assess the remaining lines with laminated wood structures in the coming months, and additional replacement projects will be presented to the PAC in 2022 for Phase III.

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PJM MRC/MC Briefs: Oct. 20, 2021

Markets and Reliability Committee

Regulation Mileage Ratio Fails

PJM stakeholders rejected two different proposals at last week’s Markets and Reliability Committee meeting to change the undefined regulation mileage ratio calculation in Manual 28 and the tariff, sending the issue back to the Market Implementation Committee for further discussions.

One proposal from PJM failed in a sector-weighted vote of 2.12 (42.4%), short of the 3.33 (66.6%) threshold for endorsement. A separate proposal from the Independent Market Monitor did better but also failed, receiving a sector-weighted vote of 3.07 (61.4%).

Both proposals were the source of several months of stakeholder debates, but the PJM proposal received endorsement at the September MIC meeting. (See “Regulation Mileage Ratio Calculation Endorsed,” PJM MIC Briefs: Sept. 9, 2021.)

Michael Olaleye, senior engineer with PJM’s real-time market operations, reviewed the RTO’s proposal. Olaleye said PJM had not received any additional feedback from stakeholders since the issue was discussed at the September MRC meeting, so no changes had been made to the proposal.

Regulation mileage is the measurement of the amount of movement requested by the regulation control signal that a resource is following; it is calculated for the duration of the operating hour for each regulation control signal. PJM’s performance-based regulation market splits the dispatch signal in two: RegA for slower-moving, longer-running units; and RegD for faster-responding units that operate for shorter periods, including batteries. If a signal is “pegged” high or low for an entire operating hour, the corresponding mileage would be zero for that hour.

PJM has seen an increased frequency of RegA signal pegging and times the RegA signal is pegged for extended periods, highlighting a potential problem in the regulation mileage ratio calculation. The RegA mileage can be set at zero for a given hour and create a divide-by-zero error in the calculation of the mileage ratio.

PJM proposed setting the RegA mileage floor at 0.1 instead of zero, which would provide a solution for the division ratio and still maintain market design objectives while having no impact on the regulation signal design, operations or regulation market clearing.

Adrien Ford of Old Dominion Electric Cooperative offered the Monitor’s proposal, which failed an endorsement vote at the September MIC meeting. It called for a cap of 5.5 on the realized mileage ratio in all hours instead of 0.1, indicating the cap would eliminate the current undefined mileage ratio result that PJM is attempting to address. The Monitor said that based on data it collected over a 15-month span, the 5.5 cap would reduce but not eliminate the market distortion resulting from the use of mileage ratios when they incorrectly represent regulation output and that the change would affect less than 50% of impacted hours.

Steve Lieberman, assistant vice president of transmission and PJM affairs for American Municipal Power, suggested sending the issue back to the MIC to possibly come up with a different proposal and to “rehash” why stakeholders either supported or opposed the existing proposals.

“It certainly seems like an issue we need to fix,” Lieberman said. “We need a solution we can rally around.”

Stu Bresler, PJM’s senior vice president of market services, said the regulation mileage ratio issue could be taken back up at the Nov. 3 MIC meeting. But “the sooner we resolve this, the better,” he said.

Carl Johnson of the PJM Public Power Coalition said there’s “no right answer” to the regulation mileage ratio. Johnson said the choice was between a “very simple mathematical fix” from PJM and the Monitor attempting to tackle some larger structural market issues.

Johnson suggested a possible solution to “resolve some of these longstanding issues with a colossally broken regulation market.”

“This is just one tiny symptom of an overall broken structure,” Johnson said.

Paul Sotkiewicz of E-Cubed Policy Associates said the undefined regulation mileage ratio issue started off as a “math problem” to solve and morphed into an examination of larger problems in the regulation market. Sotkiewicz said the Monitor’s proposal had a “huge” impact on mileage ratios and was “like taking a sledge hammer when all you need is a scalpel.”

Sotkiewicz suggested revisiting the scope of the original the issue charge and possibly come up with a new issue charge and problem statement to examine the market problems in a long-term fix while accepting a short-term compromise on the calculation.

“If we’re going to open the hood up on the regulation market, I think we need to do this the right way,” Sotkiewicz said.

Resource Adequacy Charter Approved

A new senior task force aimed at addressing resource adequacy topics and recommending possible changes to the capacity market won stakeholder approval.

The Resource Adequacy Senior Task Force (RASTF) was approved by acclamation vote, with three members voting against it and one abstaining. The task force was presented for a first read at the September MRC meeting. (See “Resource Adequacy Charter,” PJM MRC Briefs: Sept. 29, 2021.)

David Anders, director of stakeholder affairs for PJM, reviewed the charter for the RASTF, calling it the “central clearinghouse” for work related to resource adequacy that follows discussions on the minimum offer price rule (MOPR) conducted under the Critical Issue Fast Path (CIFP) stakeholder process. The RASTF will report directly to the MRC.

The task force was partially the result of a letter issued by the Board of Managers on April 6 that urged stakeholders to address a series of topics related to the capacity market, including the evaluation of characteristics of the appropriate level of capacity procurement and the examination of the need to strengthen the qualification and performance requirements on capacity resources.

Anders said the charter includes a reporting protocol for work on the capacity market performed at other PJM groups like the Quadrennial Review currently being discussed at special sessions at the MIC, load forecasting at the Load Analysis Subcommittee, and reliability products and services at the Operating Committee to be brought to the RASTF for coordination of efforts. A dashboard on the task force website will be established to list all the capacity work being discussed.

“The idea is to provide a useful tool for folks to see where everything is and to be able to access documentation,” Anders said.

PJM received stakeholder feedback to include a discussion on opportunities to address the social cost of carbon along with procurement of clean resource attributes in the RTO’s capacity, energy and ancillary services markets.

A draft of the specific scope of the work to be addressed by the task force is being developed in an issue charge that will be presented for approval at a future MRC meeting.

Transparency Forum Debated

Greg Poulos, executive director of the Consumer Advocates of the PJM States (CAPS), reviewed the proposed charter on behalf of the New Jersey Division of the Rate Counsel for the creation of a new Transparency Process Forum. Poulos first presented the charter at the September Members Committee meeting but moved the proposal after some stakeholders said the discussion would be more appropriate for the MRC. (See “Transparency Forum,” PJM MRC/MC Briefs: Sept. 29, 2021.)

Poulos said the current Stakeholder Process Forum has done a “great job” providing members with an outlet to have discussions and express concerns about the existing stakeholder process. He said there are some items that “don’t fit within that stakeholder process discussion,” and the proposed forum could provide a place to openly discuss matters that “currently take place in the back of the room.”

One of the items presented by the advocates as a possible topic for the forum was establishing a formal process to request information and data from PJM and to keep track of responses. He said having access to data was the “most pressing” issue.

“The advocates and folks from other sectors see it as an important aspect for us having the ability to get answers to certain things they’re struggling to get answers to and doing it in a public forum,” Poulos said.

Jason Barker of Exelon said his company “still [has] some concerns” after the concept for the forum was first discussed at the MC. Baker said it appears to be “a solution in search of a problem” with no clear transparency concerns.

“A new venue doesn’t seem necessary,” Barker said.

Alex Stern, director of RTO strategy for PSEG Services, asked if the sponsors would be supportive of incorporating a provision in the charter to allow stakeholders to provide input to the Monitor and PJM prior to them both filing items at FERC or in state commissions.

Poulos said he wouldn’t have a concern adding that language with the understanding that both PJM and the Monitor will do what they want to do in FERC and state commission filings.

The PJM Public Power Coalition’s Johnson said he had concerns about whether the charter was specific enough regarding how the forum will work and if enough guidance is provided for facilitators and stakeholders as to what issues should be brought to it.

“I’m really unclear as to how topics are going to be raised there and how PJM will be asked to respond to them,” Johnson said.

Carbon Pricing Senior Task Force Sunset

Members are being asked to sunset the Carbon Pricing Senior Task Force (CPSTF) after a majority of stakeholders indicated they were not ready to move forward with developing rules on leakage mitigation in carbon pricing.

Eric Hsia, senior manager in PJM’s applied innovation department, reviewed the recommendation to sunset the CPSTF, which was established in July 2019. The main objective of task force’s issue charge was to explore the impacts of emissions and price leakage between regions with and without carbon pricing policies, such as the Regional Greenhouse Gas Initiative states, and to develop business rules to manage leakage where appropriate.

The first stage of the task force included education on carbon pricing concepts like a carbon tax versus carbon cap-and-trade programs and an introduction on leakage between states. Analysis in the first stage included studies on a range of carbon prices and potential leakage mitigation approaches.

A survey conducted in summer 2020 indicated that 65% of the respondents suggested not moving forward to rule development in a second stage of the CPSTF. Hsia said some suggested that there needs to be more state interest or federal legislation to move forward with carbon pricing in the RTO.

“We want to be responsive to stakeholder feedback,” Hsia said. “And from the survey results, we did not see a strong interest from stakeholders to move forward with a market rule design.”

The committee will be asked to endorse sunsetting the CPSTF at its next meeting.

HVDCSTF Sunset

Stakeholders requested sunsetting a senior task force created last year to examine integrating HVDC converters as a new type of capacity resource in PJM.

Johnson, speaking on behalf of American Municipal Power, moved to sunset the High Voltage Direct Current Senior Task Force (HVDCSTF). An issue charge by Direct Connect Development was endorsed by the MRC in May 2020, seeking to establish HVDC converter stations’ eligibility to participate in the capacity market. (See HVDC Initiative Endorsed by PJM Stakeholders.)

The HVDC change would allow Direct Connect’s SOO Green HVDC Link — the 350-mile, 2,100-MW, 525-kV underground transmission line planned to deliver renewable energy from upper MISO to Illinois and the PJM grid — to compete in the market.

Johnson said a few education sessions were held in 2020, but “numerous” stakeholders expressed concerns about whether any solution could be found that wasn’t precluded from current FERC-approved approaches to providing capacity to PJM’s market from outside the RTO.

The task force stopped meeting last October. Several stakeholders requested that it be sunset earlier this year. (See “HVDC Senior Task Force Update,” PJM MRC/MC Briefs: March 29, 2021.) Johnson said that because the task force stopped meeting, SOO Green has brought an official complaint to FERC seeking approval of the proposal. (See SOO Green Seeks Relief from PJM Rule on External Capacity.)

“That’s probably the best way to figure out a resolution to their issue, as I don’t think the rest of the stakeholder body felt there was one available to us,” Johnson said.

The committee will be asked to endorse the motion to sunset the HVDCSTF at its next meeting.

Consent Agenda

The committee unanimously endorsed several revisions as part of the consent agenda. They included:

Members Committee

Manual 34 Revisions Approved

Stakeholders unanimously approved proposed revisions to Manual 34: PJM Stakeholder Process, addressing the inclusion of forums as stakeholder bodies. The revisions were originally discussed at the Stakeholder Process Forum and presented for a first read at the September MC meeting. (See “Manual 34 Revisions,” PJM MRC/MC Briefs: Sept. 29, 2021.)

Michele Greening, senior lead stakeholder affairs consultant for PJM, said several new forums have been created, but PJM found that Manual 34 didn’t define a forum as an official type of stakeholder group. The manual revisions define a forum as a stakeholder body to provide consistency with other defined stakeholder groups and to provide clarity to the purpose and role of a forum in the stakeholder process. The charters for all new forums must be approved by the MRC.

A forum is now defined as a “stakeholder body formed to address specific topics and scope as outlined in its Markets and Reliability Committee-approved charter. Forums are non-decisional stakeholder groups.”

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WeaveGrid Plans New EV Charging Project Under Cohort X

Electric vehicle charging software provider WeaveGrid has started a yearlong accelerator journey as a member of Cohort X, the latest group of companies backed by the nonprofit Elemental Excelerator.

WeaveGrid will select a utility in either California or Hawaii to deploy an EV charging project as part of the accelerator program, founder and CEO Apoorv Bhargava told NetZero Insider.

Elemental’s program offers a “great opportunity for us to start building relationships across both of these states with some of the regulated utilities,” Bhargava said. In addition, Elemental provides mentor pairing and investor matching sessions.

“As far as accelerators go, they are probably top of the line in the fact that they have immense connections to venture capitalists,” he said.

The new cohort is the 10th group to earn a place in Elemental’s program. Elemental started as a Hawaii-based accelerator and later opened an office in California after partnering with Laurene Powell Jobs’ Emerson Collective.

Cohort X has 19 members across the sectors of circular economy, clean water, decarbonized mobility, clean energy, and food and land systems.

Elemental’s program takes a tracked approach, Bhargava said. It recognizes that companies have different business issues that they are facing when they enter the cohort.

“Not all of us are going through the same de-risking moments,” Bhargava said.

WeaveGrid is in a track that funds companies to deploy a project, and they have access to Elemental’s network of companies for their projects.

“The project involves doing something that scales your technology and your solution in a massive, multiplicative way, or what they call the 10x factor,” he said, adding that the project also must have deep community engagement.

WeaveGrid’s software solution enables large-scale integration of EVs onto the grid, according to Bhargava.

“At our core, we have a software platform that works to provide utilities visibility, some amount of predictability and also control through managed charging,” he said.

Bhargava describes the company’s approach as “continuous multivariable optimization,” which allows it to “optimize charging to solve for the full system costs and benefits.”

WeaveGrid does not consider EVs as distributed energy resources. “There’s a tendency to lump all things that don’t look like a power plant into the DER category, and we believe that because people buy EVs first and foremost for the mobility value, they are not the same as any other DER,” Bhargava said.

The company, he said, thinks about the entire lifecycle of a person’s driving and charging experience to optimize the charging element to meet the needs of the driver and the utility.

“Utilities are really waking up to this and starting to innovate quite a bit in the space,” he said.

Xcel Pilot

WeaveGrid is in an active pilot project with Xcel Energy (NASDAQ:XEL) as part of the utility’s Charging Perks program for Colorado EV owners.

Xcel has a goal of powering 1.5 million EVs in the eight states it serves by 2030, according to Nadia El Mallakh, area vice president of strategic partnerships and ventures at Xcel.

Charging Perks “is about making it easy for drivers to use smart charging, and it rewards them for charging their car at optimal times,” she told NetZero Insider. The program encourages customers to charge up during off-peak hours, which is mostly evenings and overnight, when Xcel has abundant renewables on its system.

Customers receive $100/year for participating, and El Mallakh says Xcel expects to run the pilot for two years. It launched the pilot for Telsa drivers in June and then to other EV brands in September.

“This is one of the first smart-charging pilots in the country between an energy provider and multiple non-Tesla automakers,” she said. “Tesla drivers can also participate in the pilot through evPulse, the EV charging optimization platform from WeaveGrid.”

The utility has a target to enroll 600 customers in Colorado, and El Mallakh says 150 had signed up by the beginning of October. Data from the pilot will inform Xcel’s decision on whether to launch the charging program in some or all of its service territory.

“Our customers are our North Star to see if this is working well for them and if it’s useful for the electric grid,” she said.

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West Ponders Roles for Green Hydrogen

There’s a growing consensus in the West that green hydrogen could play a key role in decarbonizing the region’s energy system, but questions still loom around exactly how the fuel will be applied in that effort.

“There still is a broad range of opinion about hydrogen’s role in the clean energy future, and I think as responsible regulators and a policy community, we’re trying to figure out what that looks like and how we guide the marketplace in the conversations in our respective jurisdictions,” California Energy Commissioner Andrew McAllister said Wednesday at the fall joint conference of the Committee on Regional Electric Power Cooperation and Western Interconnection Regional Advisory Body (CREPC-WIRAB).

Europe is further along in the “conversation” about hydrogen, McAllister said. “We can learn from that.”

McAllister has been expressing bullish sentiments over green hydrogen for at least a year. Speaking at the Green Hydrogen Coalition’s (GHC) first annual conference last November, he mused that “the planets are aligning” for the fuel source.

At the CREPC-WIRAB meeting last week, he said that observers from outside the industry are starting to pay attention, pointing to a recent article in The Economist that declared that green hydrogen’s “moment is here at last” while also “acknowledging it is going to take some big investments.”

“There are big bets being made, and I think there’s a lot of positive momentum,” he said.

McAllister thinks it will take a “generational” investment in infrastructure to elevate hydrogen’s position in decarbonization.

“And yet we don’t really have time to wait a generation to make it, so we have to sort of figure out what works and then scale that as quickly as possible,” he said.

Green Bloom in Utah Desert?

One of the country’s biggest green hydrogen investments will take shape at the Intermountain Power Plant (IPP) in Delta, Utah. The Los Angeles Department of Water and Power (LADWP) next year kicks off an ambitious effort to convert the 1,800-MW coal-fired plant into a natural gas-fired generator designed to burn a fuel mix containing 30% green hydrogen that will be produced and stored on site.

The utility’s goal is to eventually burn 100% hydrogen after only “modest” modifications to the plant’s Mitsubishi turbines, said Greg Huynh, LADWP operating agent manager, during WECC’s annual meeting in September.

LADWP envisions IPP as a kind of large storage project, with wind and solar surpluses being used to electrolyze water into hydrogen, which will be stored in salt caverns near the plant and later used to fuel dispatchable firming energy when weather-dependent variable resources taper their output, especially for periods longer than those that can be served by most storage batteries.

“The idea of multiday and seasonal energy storage is going to become very important,” Huynh said. “What we’re looking at is the seasonal shifting of renewable energy; as energy is being curtailed in the shoulder months of the year, what we could do [is] take that energy and store it in large volumes and for a long time.”

With connections to Nevada via a 345-kV AC line and to Southern California through a 500-kV DC line, IPP’s location in the Western Interconnection positions it well to perform that reliability function, Huynh said.

At the CREPC-WIRAB meeting, GHC special adviser Laura Nelson lauded the IPP project and echoed the theme of green hydrogen playing a key role in contributing to grid reliability in the West. Nelson said GHC has been “engaging folks that are doing modeling on this front, like [WECC], the National Labs and other stakeholders, that are evaluating the role and potential for green hydrogen to serve as some of that dispatchable and long-duration energy storage.”

GHC last year launched the Western Green Hydrogen Initiative to explore the production and use of hydrogen to support policies to decarbonize the Western grid.

“It seems really in our interest to come together as states and as provinces to consider roadmaps or paths forward for developing resources that can address this issue, and green or clean hydrogen certainly shows up as one of those opportunities,” Nelson said. “And this isn’t going to be specific for any state or province. It really is going to be a significant regional lift in terms of identifying and realizing this opportunity.”

Grid Potential

For all his optimism regarding green hydrogen, McAllister last week seemed sanguine about the short-term prospects for applying the fuel to the electric grid.

With a target to decarbonize its grid by 2045, California’s modeling has shown that “the need for clean, firm power has really emerged as a gap” that green hydrogen could fill, McAllister acknowledged. But at this point it’s still too difficult to estimate the future cost-effectiveness of using hydrogen in the power system, he said. “If you’re going to do a production cost model, you need to know what the costs are and what that trajectory looks like.”

Instead, California is currently focusing most of its hydrogen efforts on other sectors of the economy.

“We know that transportation is going to be a big focus for hydrogen, and that’s where most of our policy and our investments have taken place thus far,” McAllister said. “And also in the industrial sector for high-heat applications and difficult-to-electrify sectors.”

David Bobzien, director of the Nevada governor’s Office of Energy, said his state is establishing a “beachhead” in the hydrogen economy with Air Liquide’s construction of a blue hydrogen plant in North Las Vegas that will produce enough fuel for about 40,000 vehicles, which will be shipped to California.

“But it stands to reason that you can see the next phase for that being fuel availability for transportation needs in our own state,” Bobzien said.

“I would maybe suggest focusing on transportation to start as sort of a bite-sized step,” McAllister advised, adding that California’s efforts have focused on funding programs to build hydrogen fueling infrastructure and help original equipment manufacturers get a foothold into the state to develop the market.

GHC’s Nelson also sees opportunity for green hydrogen in the transportation sector, including maritime and air transport, as well as in the natural gas sector. But her emphasis at the CREPC-WIRAB meeting was on the electric industry.

“As we look at these fossil fuel plants that are going to be decommissioned, what are we going to replace them with?” Nelson asked. She sees “significant” opportunities for green hydrogen in the power sector, including in fuel-blending, replacement of existing plants and microgrid applications.

“I think the modeling work that we’re going to pursue through the Western Green Hydrogen Initiative will definitely help to continue to inform what that opportunity looks like.”

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ERCOT Board of Directors Briefs: Oct. 22, 2021

Grid Operator Expects Tight Conditions, Outages Remain High

Interim ERCOT CEO Brad Jones told his Board of Directors on Friday that tight operating conditions Monday may necessitate a conservation call, setting off a flurry of comments from the regulators present that the call is just one “tool in the toolbox” for maintaining reliability.

A similar conservation call in April spooked legislators and customers when conditions approached the criteria for a first-level energy emergency alert. (See ERCOT Faces Tight Conditions — Again.)

Unusually high demand and above-normal seasonal generation outages were to blame for the near-emergency. ERCOT anticipates similar conditions Monday, when temperatures are projected to creep into the low 90s, while wind production is expected to be low and thermal outages remain above normal. The grid operator expects about 63 GW of demand, 8 GW or so up from last week.

Jones stressed that ERCOT was not calling for conservation, but only monitoring the conditions.

“If we need to call for conservation, we will do that before the event and we will make sure that all Texans are aware of the condition,” Jones told the board. “If we need conservation, that is to ensure the grid remains reliable. We won’t be drawing ourselves out of an unreliable condition, we will be preparing and communicating to customers in advance if we need to do so.”

Public Utility Commission Chair Peter Lake interrupted Jones’ CEO report to remind those Texans who might be watching the meeting’s video stream that “conservation is another tool in the toolbox … used in grid operations around the world.”

“The PUC’s expectations and encouragement is that the EROCT operations team will take all measure necessary to prevent us from getting into an emergency,” he said.

Commissioners Will McAdams and Lori Cobos echoed Lake’s comments. Jimmy Glotfelty was available by phone but did not offer a comment.

Board Chair Paul Foster said he agreed with the commissioners and added that he expected ERCOT “to take any action necessary under its broad reliability authority to avoid an EEA condition” and to ensure grid reliability.

“Texas expects nothing less than for the grid operator to use all available tools at its disposal, and distribution-voltage reduction is one of those important reliability tools,” Foster said, reading from a document in front of him.

He then instructed ERCOT staff to file an urgent revision request giving the grid operator “ultimate flexibility” to use voltage-reduction measures before declaring an EEA. Foster asked that the Technical Advisory Committee bring the measure to the board for its consideration in November.

The TAC last week canceled this Wednesday’s meeting because of a lack of time-sensitive items to consider. It is next scheduled to meet next on Nov. 17.


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ERCOT has been deploying ancillary services and reliability unit commitments to maintain a 6.5 GW level of operating reserves as thermal outages have fluctuated. | ERCOT

ERCOT has maintained conservative operations since the April event and another in June, when wind generation failed to show up. The grid operator has increased the operating reserves and reliability unit commitments it deploys and has been doing so sooner. It is expecting about 17 GW of thermal outages, which is down from a high of 24 GW last week.

Lake: No-go for TAC’s Status Quo

As TAC Chair Clif Lange, with South Texas Electric Cooperative (STEC), wrapped up his update to the board, he was reminded of the political realities overhanging the market participant-driven committee.

ERCOT has rolled out a 60-point roadmap to grid reliability that includes an item ensuring the TAC is composed of “senior-level members from each member organization.” The committee, currently comprising 30 members representing seven market segments, engaged in a sometimes testy exchange with Jones during its July meeting over the level of stakeholder involvement. (See ERCOT Technical Advisory Committee Briefs: July 28, 2021.)

Lake complimented the committee on its work before segueing into concerns that market participants wield too much influence in ERCOT.

“We do know that after [legislation passed this year], that status quo is not what the path forward needs to look like. I don’t know what the path forward will be with our new board members … but I’m confident they will be evaluating the stakeholder process to ensure that we make improvements where we need to make them, while also retaining the valuable elements of what TAC has done to date,” he said, nodding to the three voting members currently on the board.

“Stakeholder input is critical to making this market work well, but I also know we can’t continue with business as usual,” Lake said. “I have full faith in these gentlemen to make improvements that we at the commission expect and that the legislature and the governor expect.”

Foster said he agreed with Lake and that he expected the board will “propose a number of changes while we continue to work with TAC and the whole team.”

The board still has room for six new directors following legislation this year that revamped its makeup. The PUC chair and ERCOT’s CEO will sit on the board as non-voting members. (See New ERCOT Board Approves Governance Changes.)

Jones to Launch Listening Tour

ERCOT has launched a statewide listening tour, with stops in locations like Odessa in West Texas and Brownsville in the Rio Grande Valley. Jones, who is to meet with business and community leaders in dozens of communities across states, said one of the scheduled stops includes a town hall in Carrollton, a northern suburb of Dallas.

“I know what the conditions were [during the February winter storm]. I know how difficult it was for consumers,” he said. “I want them to have the opportunity to tell me directly and hear them out. I want to make sure the people know what we are trying to achieve.”

Jones said ERCOT and the rest of the state is well ahead of the recommendations included in FERC and NERC’s recent preliminary report on the winter storm.

“We have already been addressing every one of those items,” he said.

ERCOT is facing a $35.2 million negative variance in its 2021 budget, driven by higher legal costs and a $26.4 million shortfall in revenue. System administration fees are off $9.2 million, but the grid operator’s interest income is down $19.8 million.

“It’s basically gone away,” Jones said. He noted staff had expected a 2.5% interest rate, but that is now a “very small fraction” of 1%.

The negative variance is essentially the same as it was in August, when it stood at $35.6 million.

Non-controllable Load Participation

The board approved 12 revision requests dating back to August, including an other binding document change (OBDRR032) that aligns non-spinning reserve deployment and recall procedures with revisions from a nodal protocol change (NPRR1093). The latter measure allows ERCOT to explore temporary workarounds for non-controllable load resources to participate in non-spinning reserves and provide additional capacity for the grid operator in the coming winter and summer seasons. The non-controllable resources will be deployed after offline units participating in non-spin. (See ERCOT Technical Advisory Committee Briefs: Sept. 29, 2021.)

STEC and Lower Colorado River Authority had both opposed the OBDRR over concerns that it presented a “discriminatory ‘last in, first out’ preference” for non-controllable resources, reducing the likelihood that they would “actually be called upon” over generation resources providing the same service and being compensated the same amount.

The utilities removed their objection following a recent non-spinning reserve service workshop and discussions with PUC and ERCOT staff that led to NPRR1011 being filed. The proposed measure provides a resource-neutral, deployment-grouping requirements by including generation providing offline non spin with non-controllable load resources proving non-spin reserve.

“The bottom line is this effort brings more resources to bear and increases the margin of safety for the ERCOT grid next summer,” Lake said.

Other approved changes included three additional NPRRs, another OBDRR, two changes to the planning guide (PGRRs), two system change requests (SCRs), and single revisions to the nodal operating guide (NOGRR) and the resource registration glossary (RRGRR):

      • NPRR1082: changes the testing criteria for emergency response service (ERS) load with obligations less than 100 kW co-located with an ERCOT generator.
      • NPRR1087: ensure any critical load in ERS programs can continue to support critical operations if they are deployed by requiring an attestation that the resource is not located behind an electric service identifier (ESI ID) for a critical load. The NPRR also requires a qualified scheduling entity representing an ERS resource to ensure and attest that it is not located behind an ESI ID for a critical load or itself is not the critical load.
      • NPRR1090: clarifies that ERCOT has the flexibility to declare when exhausted ERS service types will be renewed for some or all of the ERS time periods and extends the deployment limit of weather-sensitive resources.
      • NOGRR232: squares the guide with NPRR1093’s revisions.
      • OBDRR033: matches the methodology for using the operating reserve demand curve to calculate the real-time deployment price adder with NPRR1093’s revisions.
      • PGRR093: reinserts three requirements into the board-approved graybox language for PGRR082 that were inadvertently removed in its revisions.
      • PGRR094: aligns the guide with current practices by grayboxing language requiring project construction start and completion date submittals until system implementation in the resource integration and ongoing operations-integration services system.
      • RRGRR031: amends the glossary to accommodate registration of settlement-only energy storage systems to require the same level of registration detail required for energy storage resources under RRGRR023.
      • SCR813: modifies the network model management system to highlight change submissions related to jointly rated equipment, listing other entities that have also provided ratings. The submitter will be asked to confirm that the requested changes have been coordinated with the associated companies.
      • SCR814: introduces a limit on the total number of point-to-point obligation bid intervals that can be submitted into the day-ahead market per counterparty.

The directors also signed off on staff’s recommendation for a $101.5 million transmission project that addresses reliability and aging infrastructure needs in the Port Lavaca area on the Gulf Coast. Staff said they recommended a more expensive project to meet resiliency criteria along the coast. (See “Members Endorse $101M Tx Project,” ERCOT Technical Advisory Committee Briefs: Sept. 29, 2021.)

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Stakeholders Endorse PJM ARR/FTR Market Changes

A joint PJM-stakeholder proposal to address the RTO’s auction revenue rights (ARRs) and financial transmission rights won endorsement after failing an initial vote at last week’s Markets and Reliability Committee meeting.

The changes, whose proponents included Calpine, Exelon, NextEra Energy, Vitol and Public Service Enterprise Group, was endorsed in a sector-weighted vote of 3.74 (74.8%), surpassing the necessary 3.33 (66.6%) threshold. In a first round of voting, the proposal failed the sector-weighted vote with 3.16 (63.2%) support.

Members first endorsed the proposal at the Market Implementation Committee meeting earlier this month with 84% support, and now it heads to the Members Committee for a final vote in November. (See “ARR/FTR Market Task Force Proposal,” PJM MIC Briefs: Oct. 6, 2021.) Two other proposals presented as alternatives failed in sector-weighted votes.


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Brian Chmielewski, PJM

” data-credit=”© RTO Insider LLC ” style=”display: block; float: none; vertical-align: top; margin: 5px auto; text-align: right; width: 200px;” alt=”Chmielewski-Brian-2017-08-10-RTO-Insider-FI.jpg” align=”right”>Brian Chmielewski, PJM | © RTO Insider LLC

Brian Chmielewski, manager of PJM’s market simulation department, said the changes “represent the culmination of a two-year stakeholder process” that were initiated after the GreenHat Energy default in 2018, including a six-month review by an independent consultant and work done at the ARR/FTR Market Task Force.

GreenHat acquired the largest FTR portfolio in PJM between 2015 and 2018 but defaulted on the portfolio in June 2018, leaving PJM stakeholders to cover more than $179 million in the market to the present. When the company defaulted, GreenHat had only $559,447 in collateral on deposit with PJM. (See Doubling Down — with Other People’s Money.)

Chmielewski said the resulting work was a “balanced package” that received overwhelming stakeholder support at the MIC.

“We believe the changes in the proposal strike an appropriate balance in advancing the benefits for load while advancing the efficiencies of our current FTR auction structure,” Chmielewski said.

PJM Proposal

Chmielewski reviewed the proposal, which included revisions to the tariff and the Operating Agreement, saying they were guided by the findings of a report developed by London Economics International (LEI), a consultant enlisted 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 its other markets to evaluate risks and benefits of rule changes. (See “PJM Seeking Consultant on ARR/FTR Task Force,” PJM MIC Briefs: May 13, 2020.)

PJM-ARR-FTR-market-design-(London-Economics)-Content.jpgProposed enhancements to PJM’s current ARR/FTR market design. | London Economics

Chmielewski said the proposal aimed to recognize recommendations made in the LEI report 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 to ensure “open access to firm transmission service by providing a congestion-hedging function.”

The proposal was broken into three separate areas as recommended in the LEI report, with an ARR track dealing with “equity” issues, an FTR track for “efficiency” issues and a transparency track for a “simplicity” model.

Chmielewski said the ARR section was the main part and intended 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.

The other main features included a guarantee of 60% of network service peak load for each load-serving entity, which was meant to “protect zonal native load hedging ability with additional upfront capability.” The proposal also expanded the source/sink availability for ARR allocation so that they “align with any source/sink that is available for bid in the annual FTR auction.”

Key-market-components-of-RTOs-ISOs-(London-Economics)-Alt-FI.jpgKey market components of RTOs/ISOs across the country. | London Economics

The FTR section contained features intended to “advance the efficiencies” of the FTR auction structure. Efficiencies cited included market liquidity and future price discovery, Chmielewski said, both of which are designed to add value and contribute to a competitive market.

The changes also add hedging product to account for on-peak weekend and holiday hours to increase hedging flexibility; increase the bid limits in all FTR auctions from $10,000 to $15,000; and add a $1/MW-period class clearing price floor for all FTR option products.

The transparency section includes recommendations to “help bolster confidence in the FTR action results,” Chmielewski said, including the creation of a network model user guide to standardize market procedures and the posting of market limits utilized in approved cases for binding constraints.

Chmielewski said the ARR changes are anticipated to take effect by February 2023, and the other changes in the proposal could happen even sooner.

Alternative Proposals

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Erik Heinle, D.C. OPC

” data-credit=”© RTO Insider LLC” style=”display: block; float: none; vertical-align: top; margin: 5px auto; text-align: left; width: 200px;” alt=”heinle-erik-2019-01-04-rto-insider-fi.jpg” align=”left”>Erik Heinle, D.C. OPC | © RTO Insider LLC

Erik Heinle of the D.C. Office of the People’s Counsel reviewed the group’s alternative proposal, which was identical to the joint proposal except that 100% of the surplus allocation would have been given to ARR holders. Heinle said the LEI report was “pivotal” for the group’s evaluation of the allocation issue and that it “really focused on what was best for the market.”

Heinle said the LEI report recognized the dual purpose of the market through returning congestion charges to load and supporting hedging activities, both of which benefit consumers. And while the PJM proposal addressed several important issues, Heinle said, the issue of auction and congestion surplus was left unchanged.

“This places D.C. OPC in the unfortunate and uncomfortable position of offering an alternate that does address these equity concerns,” Heinle said.

The OPC alternative proposal nearly won stakeholder endorsement in the first round of voting, receiving a sector-weighted vote of 3.28 (65.6%).

In reviewing the IMM’s proposal, Monitor Joe Bowring said he disagreed with a recommendation in the LEI report that load should be satisfied with receiving 50 to 75%, instead of 100%, of overpayments. He also said the other proposals didn’t go far enough on the congestion payment issue.

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PJM Monitor Joe Bowring

” data-credit=”© RTO Insider LLC” style=”display: block; float: none; vertical-align: top; margin: 5px auto; text-align: right; width: 200px;” alt=”capacity transfer rights ” align=”right”>PJM Monitor Joe Bowring | © RTO Insider LLC

“PJM’s proposal takes some tiny, tiny steps towards increasing the congestion revenues that belong to load,” Bowring said.

The Monitor’s proposal also failed to receive endorsement in the first round of voting, garnering a sector-weighted vote of 1.33 (26.6%).

Susan Bruce, counsel to the PJM Industrial Customer Coalition, said she appreciated all the work taken on by PJM and stakeholders on the issue. The LEI report gave members a clear path to come up with solutions, she said.

“In the wake of GreenHat, this was very important form the customer’s perspective to understand what’s going on in this market,” Bruce said.

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House E&C Hearing Pits Offshore Wind Against High Energy Prices

Throughout a four-hour session Thursday, the House Energy and Commerce Subcommittee on Energy’s Democratic members kept the focus on the economic development potential of the offshore wind industry and its emerging domestic supply chain and jobs. Republicans meanwhile hammered away on current high oil and gas prices and possible threats to the affordability and reliability of the nation’s energy supply as winter approaches.

Energy and Commerce Committee Chair Frank Pallone (D-N.J.) cited the positive impacts of the emerging offshore industry in his home state, which is working toward deploying 7,500 MW of projects by 2035. Three projects now moving forward have brought “thousands of jobs and billions of dollars of investment to the Garden State. But to be clear, the economic benefits of offshore wind won’t just accrue on the coast; they will impact communities across the country,” Pallone said.

Fred-Upton-(House-Energy-and-Commerce-Committee)-Content.jpgRep. Fred Upton (R-Mich.) | House Energy and Commerce Committee

He pointed to a recent report from the Business Network for Offshore Wind that found more than 500 supply contracts for offshore components across the country and pitched for the transmission funding in the Democrats’ budget reconciliation bill. Pallone also argued that fossil fuels and their volatile price swings are creating uncertainty and unreliability for energy consumers. “Doubling down on existing fossil fuel infrastructure makes little sense.”

Rep. Fred Upton (R-Mich.), the subcommittee’s ranking member, said he was “a little bit troubled by the topic of today’s hearing because we are in an energy crisis right now, which is what I believe this committee ought to be focused on. The price of gas and many energy commodities are at a seven-year high,” with the Energy Information Administration anticipating price rises in propane (54%), heating oil (43%) and electric heating (6%) in the months ahead.

He also questioned the feasibility of President Biden’s goal of deploying 30 GW of wind off both coasts by 2030. “It’s very difficult to imagine that any projects are going to get built without substantial taxpayer and ratepayer subsidies, and of course, we have the questions of permitting,” Upton said. Other obstacles include “poor economics, operating reliability in harsh conditions … negative environmental and fishery impacts, workforce and labor issues,” he said.


Kim-Schrier-(House-Energy-and-Commerce-Committee)-Content.jpgRep. Kim Schrier (D-Wash.) | House Energy and Commerce Committee

These basic positions were replayed, with minor variations, throughout the hearing, reflecting the tension between current concerns over rising energy costs and the planning and investment required to shift the nation’s energy supply to clean sources.

Rep. Kim Schrier (D-Wash.) saw the apparent conflict as more of a false dichotomy given the mounting impacts of climate change.

“We need a full portfolio of alternative sources of energy: hydro, nuclear, solar and wind, including offshore and onshore,” Schrier said. “But no natural gas is coming offline until we have enough renewable energy to replace it; so, tying these together, which some of my colleagues are doing, is misleading. It’s fear mongering, and it’s just making a bunch of excuses for doing nothing.”

Building a US Supply Chain

The current momentum behind offshore wind at the federal and state level comes as the U.S. finds itself lagging in a booming global market. According to the Department of Energy’s 2021 Offshore Wind Market Report, while the U.S. offshore project pipeline stands at 35 GW, actual projects in operation total only 42 MW versus the 33 GW of installed capacity worldwide. Europe and China are the market leaders.

Heather-Zichal-(House-Energy-and-Commerce-Committee)-Content.jpgHeather Zichal, ACP | House Energy and Commerce Committee

Still, Heather Zichal, CEO of the American Clean Power Association (ACP), provided an optimistic overview of the emerging U.S. industry, with Biden’s 30-GW goal and other state targets jump-starting a domestic supply chain that will provide certainty for developers and investors.

Looking ahead, Zichal called for a federal tax credit for offshore wind component manufacturing and federal leadership in planning the transmission and distribution systems that will be needed to meet Biden’s target. While some projects will be able to interconnect through existing infrastructure, Zichal said, “sustaining long-term growth of offshore wind will require a coordinated approach to transmission that spans multiple-leased areas, states and regions. Forward-thinking transmission planning will help to expand the market for offshore wind more quickly and benefit the supply chain,” she said.

FERC’s Advance Notice of Proposed Rulemaking on transmission planning and cost allocation is a good first step, she said, as is PJM’s work with New Jersey, integrating the state’s project pipeline into its regional planning. (See FERC Tx Inquiry: Consensus on Need for Change, Discord over Solutions.)

David-Hardy-(House-Energy-and-Commerce-Committee)-Content.jpgDavid Hardy, Orsted North America | House Energy and Commerce Committee

David Hardy, CEO of Ørsted North America, began his presentation by noting his firm’s Danish parent company started out in fossil fuels but is now fully divested from oil and gas, focusing instead on renewables. In the U.S., the company is taking a two-pronged approach to building the domestic supply chain it needs for projects to be built off the coasts of New Jersey, New York, Connecticut and Rhode Island.

“This includes first building U.S. capability with existing American companies and, second, attracting European firms to build facilities here in the U.S., creating foreign direct investment in new American jobs,” Hardy said.

Ørsted has partnered with Kiewit, a Nebraska-based engineering and construction firm, to build an American-made offshore wind substation, which will be manufactured in Texas, he said. Factories in Pennsylvania, North Carolina, Alabama and West Virginia will be producing steel for American-made offshore wind installation and operations vessels, also being built in Texas.

But Hardy cautioned against comparing the nascent offshore industry in the U.S. with its more developed counterpart in Europe, which “has had several decades to build the infrastructure needed to support a mature offshore wind industry. Although we are making considerable progress in building the U.S. supply chain, it remains a challenge that needs regulatory certainty and incentives if we want to achieve 30 GW by 2030,” he said.

Mark-Menezes-(House-Energy-and-Commerce-Committee)-Content.jpgMark Menezes | House Energy and Commerce Committee

Speaking as a private citizen, Mark Menezes, former deputy energy secretary under President Donald Trump, was less bullish on offshore wind, acknowledging its potential but arguing the technology still faces too many obstacles and high costs. He pointed to Maine, where Gov. Janet Mills recently signed a new law banning offshore wind projects in state waters — aimed at protecting the state’s lobster and recreation industries — while allowing development in federal waters.

Menezes and other Republicans also pointed to the current spike in energy prices in Europe, which they linked to the region’s reliance on offshore wind and a lull in North Sea wind speeds in September.

According to WindEurope, an industry trade group, combined on- and offshore wind energy provided 23.4% of the region’s power on Friday. The European Commission is pushing even faster deployment of renewables as the solution to high electricity and gas prices, along with targeted, near-term measures to protect the region’s most vulnerable populations from the current high prices.

Winter Wind, More Power

Responding to a question from Rep. Cathy McMorris Rodgers (R-Wash.), the full committee’s ranking member, Menezes criticized Biden’s cancellation of the Keystone XL pipeline and his initial moratorium on oil and gas leasing on federal land. Such actions, he said, may have had a chilling effect on oil and gas investment.

Following a court order, the moratorium was lifted, and a recent Associated Press report found that the Interior Department has approved 2,100 permits for oil and gas drilling on federal land since Biden took office in January, the highest level since George W. Bush was president.

Meanwhile, a question from Rep. Diana DeGette (D-Colo.) gave Hardy the opportunity to counter Republican concerns about the performance of offshore turbines in harsh weather. In high winds, the turbines will shut down to “protect themselves,” he said.

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MISO, SPP Eye Small Interregional Tx Projects

MISO and SPP said last week they will likely establish a smaller interregional project type similar to MISO’s and PJM’s Targeted Market Efficiency Project (TMEP).

If approved, a TMEP — small, $20 million and under upgrades — could become the grid operators’ first interregional transmission project.

MISO’s Ben Stearney said the upgrades will be designed to handle persistent congestion on the RTOs’ SPP seam.

“I think the MISO-PJM process provides a pretty good framework,” he told stakeholders during Friday’s Interregional Planning Stakeholder Advisory Committee (IPSAC).

Stearney said the projects will use a “straightforward” benefit analysis that relies on historical market-to-market congestion. He said staffs must line up market data to identify beneficial projects.

He predicted it would take four to six months for MISO and SPP to draft a TMEP process under their joint operating agreement (JOA) and separately develop regional cost-allocation methods to divide costs among respective members.

Advanced Power Alliance’s Steve Gaw asked whether staffs could accelerate enshrining the TMEPs’ process in their JOA. “My read is you’ve got a lot of support for this,” Gaw said.

Stearney said the RTOs want to collect formal stakeholder feedback on the new study type before proceeding. “I really want to kick off this study process in earnest in 2022,” he said.

The RTOs’ state regulators have already asked the grid operators to commit to a TMEP-type category. (See 4th Time No Charm for MISO-SPP Interregional Study.)

They will hold another IPSAC in early 2022 to further discuss TMEPs and CSPs.