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November 19, 2024

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EPSA Members Renew Call for Carbon Price; See Long ‘Bridge’ for Gas

WASHINGTON — Competitive power generators on Tuesday renewed their calls for a national price on carbon emissions while complaining of a lack of market support for the flexible gas-fired generation they say will be needed to supplement renewables for the foreseeable future.

Top officials from Calpine, LS Power, Vistra (NYSE:VST), Competitive Power Ventures and Tenaska delivered their views at the Electric Power Supply Association’s Competitive Power Summit at the National Press Club, where some of their concerns were echoed by a panel of Ph.D.s and the CEOs of NERC, PJM and ISO-NE.

“I think it’s worth saying one more time: national carbon price. It’s such a no-brainer,” said Sherman Knight, president and chief commercial officer for Competitive Power Ventures. “It’s straightforward. It is efficient, and it gets it gets the job done.”

“I don’t know why we continue to have this debate about what’s the most direct way [to accomplish decarbonization]; what’s the most … even playing field; what seems to be administratively easy to do,” agreed Curt Morgan, CEO of Vistra. “And for the life of me, I’ve met with a lot of people on Capitol Hill — many you guys probably have too — and I still can’t quite get my head around why we can’t get something like a carbon price. [It’s] baffling, I think, to all of us. There is movement though; I will say I’m not as pessimistic as I was a year ago.”

“If we don’t put that price of carbon on the system, I don’t see how anything could work,” Harvard economist William Hogan said in the last session of the daylong conference. “We’re doomed to fail. So I’m very pessimistic about it.”

“I agree with everything that Bill just said,” economist Paul Sotkiewicz, president of E-Cubed Policy Associates, joked in response. “In fact, now I’m so depressed, I’m going to bring my hair dryer into my shower.”

A More Expensive Transition

“The energy transition is going to be expensive. … And it’s going to be far more expensive if we go around choosing pet projects here, here and here,” Knight said. “We feel like we’re chasing state mandates, as opposed to focusing on reliability and reducing carbon in the industry. And that gets a little bit frustrating. … We can do it, you know, but certainly it’s less effective [than] if there was a federal, or even just a regional — within an RTO — consistent, policy.”

ISO-NE CEO Gordon van Welie cited a study by the RTO that predicted the region could face negative LMPs within a decade that would “wreck the markets.”

“As the states grapple with that reality, I think there’s some empathy starting to develop towards having to put a carbon price into the electricity markets. It’s probably not the right place to do it; the right place to do it is in [the economy-wide Regional Greenhouse Gas Initiative] or some national scheme. But both of those are not really politically feasible at this point. So the next best [place] is to put it into the ISO markets. And we’re going to need to have the states tell us what number they want.”

“It pains me to say it, but I think there is value in some incrementalism, mostly because we have no other option,” said Arnie Quinn, vice president of FERC-jurisdictional markets for Vistra. He added that his company would also support a forward clean energy market like that under discussion in ISO-NE. (See Draft Study Weighs Tradeoffs of CO2 Pricing, FCEM for ISO-NE.)

“Incremental carbon pricing is better than none,” agreed PJM Independent Market Monitor Joe Bowring, who noted RGGI has had a “demonstrable impact” on system dispatch in PJM despite the fact that only four PJM states currently belong to RGGI.

The RGGI model allows states full control over the carbon quantity and price variables. The results of those state decisions change the marginal costs of generators in the PJM market, and the impacts flow through the normal market dynamics without the RTO having to make any policy decisions about carbon.

“There has to be more state cooperation — whether it’s in the form of a carbon price, or in recognizing the value of transmission — to help meet state renewable energy and other goals along with resource adequacy,” said John Moore, director of the Natural Resources Defense Council’s Sustainable FERC Project.

Travis Fisher, president of the Electricity Consumers Resource Council (ELCON), said state targets “that say you have to get to this place 30 years from now [is] a very expensive way to do it.”

Instead, policymakers should say, “‘We are going to minimize the cost of the entire system — generation, transmission, all parts of it — we’re going to minimize the cost of it, subject to all the other policy constraints.’ … It’s got to be reliability, at least cost.”

The Length of the Natural Gas ‘Bridge’

The role of natural gas also was a recurrent theme in the discussions, with NERC CEO Jim Robb and PJM CEO Manu Asthana joining generators in insisting that natural gas will be needed to supplement intermittent resources and ensure reliability.

“In a world where policymakers don’t want gas — gas has become the new coal in many areas — what do we think is going to provide that balancing capability?” Robb asked. “It could be hydrogen, but that’s a long, long way away. It could be batteries, but we don’t have a battery technology that can perform cost-effectively at the scale we would need it to with the durations that we would need. It could be small nuclear reactors [with] flexible characteristics. But that’s a long, long way off.”

Robb said he agreed with those who see natural gas as a “bridge” to a low-carbon future. What “terrifies me in this transition [is] a lot of people think that the bridge is about this long,” he added, spreading his hands a few inches apart. “And I think most people in this [conference] room would say this bridge extends from that wall to that wall. Your point of view on the length of that bridge dictates an awful lot as to what you do in terms of investing in infrastructure.”

The inability to invest in gas infrastructure or electric transmission, Robb said, “is really going to cripple our ability to meet any of the emission-reduction targets that we have.”

“I think it is a long bridge,” Asthana responded. “In fact, PJM is on the record as saying that we think we need access to our thermal generation until and unless there’s replacements of assets in place.”

Devin Hartman, energy and environmental policy director for R Street Institute, said NERC and others need to address a “reliability and cost education problem.”

“There are folks — a sizable population — that genuinely believe that we can just force all natural gas off the system nationwide [in] this decade, replace it with renewables, and costs will go down and reliability will be maintained,” he said. “We have a stronger role to play in educating policymakers and others in understanding these mechanisms. How do markets drive [generator] entry and exit? How do they manage risk?”

Where’s the Market Support?

Asthana said capacity markets may be increasingly important in providing incentives to gas generators as energy markets respond to renewables with zero marginal costs. “And you know, maybe there’s an answer in the form of other ancillary services that we procure for ramping or some other form of flexibility.”

Generators said that while they continue to support competitive markets, they are not providing price signals for new gas units.

Vistra’s Morgan said the industry is “at a crossroads,” with reliability at stake.

“I may be the boy that cried wolf, but that’s OK. I’m telling you … there is a big disconnect in places like PJM and in places like ISO New England if we don’t do something about this,” he said. “We’ve got to have an analysis done that figures out that marginal resource that is necessary, under the most extreme circumstance, with the intermittent resources out, that will ensure reliability. And the ISOs have to be the ones to step up and do this because they’re the objective person. [If] we come to the table, people say, ‘Oh, they’re those greedy generators, or ‘they’re just talking their book again.’

“I don’t know how to build a gas plant today, in a competitive market, with not knowing how long it’s going to be around,” he continued. “I don’t know how you can say that $50/MW-day, or $2 or less a kilowatt-month on a capacity clear supports new build of a gas plant. … Look, competitive markets have brought better reliability, lower costs. … But we’ve got a lot of hands in these markets, and a lot of forces are [attempting] to drive lower and lower capacity” prices.

CPV’s Knight agreed that “price signals do not currently support investment in new dispatchable generation in most of the country.”

“I think that what we have to be careful about is saying competitive markets aren’t incentivizing investment. And I think that is absolutely not true. I think what we’re talking about here is tweaking the competitive markets … as the infrastructure transition occurs … so that it can unleash the power of private capital to come in and make investments — or not have private companies preserve capital by retiring perfectly good assets that are needed for the transition.”

Generators said the move to effective load-carrying capability should help the most flexible gas units.

“If it takes you 24 hours to start up, that’s not that useful to the grid with intermittent resources,” Morgan said. “So combined cycle plants that have much more flexibility ought to have a higher effectiveness rating than … a gas steamer that takes 24 hours to start up. … We can’t just come in always pushing our own [generation]. We have to admit that some of our dispatchable resources are less effective.”

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BPA ‘Full Speed Ahead’ on May WEIM Entry, but Issues Remain

The Bonneville Power Administration is on track to enter the Western Energy Imbalance Market on May 3, despite lingering issues with market integration software, agency officials said Thursday.

“It is still very much full speed ahead as we continue to work through the outstanding milestones and progressing towards our May go-live date,” Nita Zimmerman, BPA’s chief business transformation officer, said during a stakeholder meeting.

The federal power marketing agency was originally scheduled to begin transacting in the WEIM on March 2, along with Avista and Tacoma Power. But after beginning parallel operations Dec. 1, BPA delayed entry by two months because of technical problems and customer training issues. The parallel production environment allows new participants to submit bids and base schedules, collect e-tags and learn how to adapt operations to real-time developments. (See BPA Postpones Western EIM Entry by 2 Months.)

“We managed through the slight delay, and we’ve made progress to meet the milestones necessary for participation, including resuming parallel operations [with the WEIM] on March 8,” Zimmerman said.

She said BPA on Wednesday submitted its WEIM “readiness attestation” to CAISO, the market’s operator, which will in turn submit the document to FERC.

“With this success achieved, there is still more work to be done,” Zimmerman said. “BPA will continue to test and implement the systems necessary to participate in the EIM.”

The outcome of that testing will be the subject of an April 19 meeting of BPA executives responsible for issuing a “go/no-go” decision on the May 3 entry date, said Mark Symonds, the agency’s director of commercial operations.

“That’s where we bring our executives together and make sure, from a functional readiness standpoint, we are in all-systems-go from a systems, process and people standpoint, to make sure that we have the level of confidence that we need to run our EIM operations on May 3,” Symonds said.

Elsa Chang, BPA’s EIM program manager, said the most “critical” problems to be addressed have to do with integration of the “sub-allocation” and outage management systems related to WEIM operations.

The problem with the sub-allocation system has been particularly thorny. That system is designed to allocate the costs and payments for WEIM settlements back to BPA customers. Testing has revealed discrepancies between CAISO settlement statements and the sub-allocation amounts, BPA’s Rasa Keanini said.

Chang said BPA expects to complete its work on the sub-allocation system by the May 3 WEIM go-live date but also has a contingency plan in place in case fixes provided by the software vendor fail to pass BPA’s testing by that date.

“We plan to have the work delivered no later than June 25, which is the day BPA issues our first EIM bill to our transmission customers,” she said.

Chang said BPA has also encountered “performance issues” with its WEIM outage management software, which went live March 8 when the agency re-entered parallel operations with the market.

“This system is necessary for BPA to participate in the EIM, so issues can potentially result in both safety and reliability problems,” Chang said, adding that BPA has “patched” the system and will continue to monitor it and resolve any problems.

Customer Concerns

Stakeholders on the call voiced concerns about what BPA will do if the software system issues have not been sufficiently addressed by the time BPA official meet on April 19 to make the “go/no-go” decision.

“What happens if things don’t, don’t go quite as well as we expect?” Adam Cornelius, principal utility analyst with Snohomish County Public Utility District in Washington, asked.

“That’s really a great point,” Symonds said, “and it’s one that we’re watching very closely and why we have been working very collaboratively with our vendor to clear the defects that get identified and be able to test the sub-allocation routine and not just validate the routine itself.”

Symonds said he expects BPA to make “significant progress” on that front ahead of the April 19 meeting.

“It is possible that things could go in a different direction,” Symonds said. “That’s why we’ve continued to reinforce our [WEIM] participation principles up and down the line for years — that we have the ability to manage our participation in the market.”

Ed Mount, director of power supply planning and operations at The Energy Authority, pressed the sub-allocation system issue, saying the allocations are “where the rubber hits the road” for his company’s customers.

“Is there a contingency plan for billing customers if there are still discrepancies that are being seen between the sub-allocation system logic and what you’re being billed with CAISO?” Mount asked.

Symonds described the complexity of that system logic and the importance of the quality of the metering data being fed into the system.

He said BPA would contact “selected” customers — mostly those at aggregated customer meter points — regarding the data over the next few weeks “so that we can tackle any of those issues that we think we are seeing now, rather than waiting until after go-live or even our first settlement statement to see it.”

“We also have different contingency plans that we can exercise along the way, in the event that we continue to have any issues with how those calculations come together,” he added.

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NERC Chief: ‘Longer, Deeper, Broader’ Weather Presents New Reliability Challenges

WASHINGTON — Extreme weather events during the last two years have brought “extraordinary clarity” about the reliability risks posed by the changing climate, NERC CEO Jim Robb said Tuesday.

Jim Robb 2022-03-29 (RTO Insider LLC) FI.jpgNERC CEO Jim Robb | © RTO Insider LLC

“These weather systems are … longer, deeper, broader,” Robb told the Electric Power Supply Association’s Competitive Power Summit, citing “heat domes” in the West and the February 2021 winter storm, named “Uri” by the Weather Channel. “And that’s a real problem, because utilities can’t rely as much on transfers [from other regions] to bail them out.”

NERC was able to identify generation that could have preserved ERCOT’s ability to serve load during Uri, “but we’d be wheeling it from peninsular Florida and Montana and places like that,” Robb said. “And the cost to build that transmission is ungodly.”

Uri resulted in several days of rotating blackouts in Texas to prevent a grid collapse, the largest manually controlled load shed event in U.S. history. It also showed that weather can cause outages to more than wind and solar generation. Natural gas-fired units represented 58% of all generating units that experienced unplanned outages, derates or failures to start, a joint FERC-NERC report concluded.

As weather challenges rise, the drive to electrify transportation and heating means the demand for reliability will only increase, Robb said. “Our tolerance for even momentary outages or any sort of disruption is going to go to zero very, very quickly.”

As a result, he said, “we really need much, much better situational awareness between the system operators, the generators and, importantly, the fuel suppliers.”

A common link in NERC’s assessments of major reliability events driven by weather — including the 2011 and 2018 cold weather events — is that “the system operator and the generators just didn’t know whether their fuel was going to show up or their plants could perform. So, the operators are scrambling to make decisions in real time that they should have had the ability to plan for,” Robb said.

He also repeated his call for a different “mindset” on reliability and resource adequacy, saying the calculation of peak annual load plus reserve margin is no longer sufficient because of intermittent generation and gas plant fuel risks.

Concerns are most acute in California, Texas and New England, “the three hotspots for how the world has evolved,” Robb said. “This will be coming to the theater near you soon. It may take a while, but the dynamics are clearly there.”

Paul Sotkiewicz 2022-03-29 (RTO Insider LLC) FI.jpgPaul Sotkiewicz, E-Cubed Policy Associates | © RTO Insider LLC

Also speaking at the conference, Paul Sotkiewicz, president of E-Cubed Policy Associates, said ERCOT needs “some sort of reliability call option.

“I’m not going to use the term ‘capacity market’ because that’s a dirty word in Austin. … But the whole point is that you need some sort of reliability call option to say, when the system gets to a certain condition — I don’t care if it’s summer peak, winter peak, the shoulder period — if I need you, I can call on you.”

Calpine CEO Thad Hill echoed Robb’s concern, saying the Biden administration and some state energy policymakers are causing “changes to major tariffs in the markets, where it’s about emissions first, cost second and reliability third.”

Obligation to Perform

Robb said the wholesale markets must redefine generators’ “obligation to perform.”

NERC learned that many generators shut down by Uri had made “a pure economic decision” not to winterize, Robb said.

“They said, ‘Look, it’s not worth it for me to invest in this amount of winterization for this unit because I just won’t show up that day. And sure, I may forgo a day of very high prices, but I don’t [think] the probability of that happening justifies the investment.

“We have to create the proper set of incentives and … penalties so that a generator saying, ‘I’ll be there’ — they’ve got to be there. And if they’re not, I’m sorry, they should get whacked on the knee. And they should be incented to be there under a broader range of conditions than we might have thought of before. Because the tails in the distribution of outcomes — these tails are becoming really, really important.”

Educating Rate Regulators

Devin Hartman, energy and environmental policy director for R Street Institute, said NERC needs to help educate policymakers about the need for flexible natural gas units and services such as ramping. (See related story, EPSA Members Renew Call for Carbon Price; See Long ‘Bridge’ for Gas.)

State utility regulators “are really struggling with prudency decisions now. They’re looking at this and saying, ‘We don’t even understand you’re talking about ‘ramp,’” Hartman said.

“This has never been classically built into [integrated resource plan] considerations. And they’re really struggling to kind of operationalize it at that level. Increasingly, reliability cost and environmental performance are a function of regional portfolio conditions. And that means … you actually have to have enhanced information flows and better coordination.”

Arnie Quinn 2022-03-29 (RTO Insider LLC) FI.jpgArnie Quinn, Vistra | © RTO Insider LLC

Arnie Quinn, vice president of FERC-jurisdictional markets for Vistra (NYSE:VST), said the grid is unlikely to see “reliability catastrophes” as a result of the transition to renewables.

“I think it will be more likely that we will see a lot of resource adequacy RMRs [reliability-must-run agreements] and fuel security RMRs and a bunch of other little RMR actions and things that bury costs,” he said. “And quietly, costs will go up in a way that’s very non-transparent.”

Glass Half Empty

Asthana and Hartman expressed optimism that RTO stakeholder processes will develop the market designs needed to support efficiency and reliability.

Robb was less confident.

“We got to get the stuff figured out now so that as we redevelop the system over the coming 10, 20, 30 years, we’re leaving something behind that we’re going to feel proud of,” he said. “Right now, it’s not clear to me that we’re going to get there. You guys are optimistic. I’m paid to be the [glass] half-empty guy.”

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East Boston Substation Saga Continues as Eversource Seeks Permits

The long-standing fight over Eversource’s planned East Boston substation is not over.

The utility is asking the Massachusetts Energy Facilities Siting Board to expedite approval of 15 state and local permits and certificates it says have been delayed or not considered quickly enough.

But in doing so, Eversource has given the project’s many vocal opponents another opportunity to state their case for why the project shouldn’t go forward at all.

The EFSB initially approved the project, which has served as a powerful example of the conflict between regional transmission planning goals and local siting concerns, last February. (See Controversial East Boston Substation Approved.)

Eversource’s Case

Eversource, backed by Massachusetts officials, has warned that the substation is necessary to fill a fast-growing capacity need.

“Electric service in the East Boston and Chelsea area is at risk,” said Craig Hallstrom, the company’s president for regional electric operations, at a public EFSB hearing Wednesday.

He called the plan a “standard utility design” to locate a substation at a customer load center. East Boston, he said, is the only Boston neighborhood that doesn’t have one, instead being served by the Chelsea substation.

Eversource Substation Render (Energy Facilities Siting Board) Content.jpgA preliminary design concept from Eversource for the facade of its proposed substation | Energy Facilities Siting Board

 

“Without this new substation … it will be a challenge for this area to be part of the new electrification of systems like EVs and heat pumps,” Hallstrom said.

The project won’t be complete for several years once construction starts, but that hasn’t stopped Eversource representatives from employing grim warnings about immediate danger in their arguments for the plan.

“This summer, we’re hoping we have some beautiful hot weather as things go back to normal and we’re heading out of this pandemic,” said Nicole Bowden, an Eversource community relations specialist.

“You’re coming home from work. Your kids are coming home from camp. Everyone’s tired. You’re ready to get in the shower. You don’t have any electricity. The water’s not hot. You can’t sit down and watch the Red Sox game. The A.C.’s not blowing; the fans aren’t blowing. And it’s going to be three, four, five, six days of this.”

“We want to avoid this,” Bowden said.

Opposition Continues

The project is opposed by many East Boston residents and nearly every relevant elected official in Boston, from city council to the mayor to the state’s two senators. The city’s voters also overwhelmingly opposed siting the project there in a non-binding referendum in November.

Widespread frustration among opponents stems from the project’s location near public spaces, in a flood zone, and in an environmental justice community that has seen a long history of environmental hazards and pollution.

That opposition has extended to the company’s latest request to expedite the 15 certificates.

“As far as my interpretation, this is Eversource requesting to evade the permitting process and build this thing before the appeals that have been filed … are finished,” East Boston resident Leonard Olsen said at the hearing. “It’s equally absurd as the project itself.” Opponents have also challenged Eversource’s claims about the need for the project, noting that past load projections over the long process of planning the project have at times failed to come to fruition.

“It feels a bit like the boy who cried wolf, as we’ve seen what the actual summer peak loads have been in comparison to some of what the projections are,” said John Walkey, director of Waterfront & Climate Justice Initiatives at the advocacy group GreenRoots.

Some public officials representing the area recognize the need for more infrastructure to meet the area’s demand for electricity, especially considering decarbonization efforts. But they say Eversource has not met the moment.

“The opposition is not that we don’t need infrastructure to meet our greener future, that we won’t need to be able to generate for our EV stations,” said Lydia Edwards, a former Boston City Councilor who was elected to the state Senate in January. “I just think what we’ve been trying to say for the past several years, and in many languages, is that we can be more creative than this. This is not going to prepare us or help us become healthier in our future,” Edwards said.

What’s Next? 

Anyone who wants to be a participant or intervenor in the EFSB case has until April 19 to file a petition.

The EFSB will hold an adjudicatory hearing on the Eversource certificate request starting on May 17.

In its consideration, the board will look again at the need for the facility, its design, and whether granting an exemption from state and local requirements is “reasonable and consistent with providing necessary energy supply for the Commonwealth with minimal impact on environment and lowest possible cost,” board member Donna Sharkey said.

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FERC Conditionally Accepts Rockland Electric’s ROE Adder in PJM

FERC on Tuesday conditionally granted Rockland Electric Co.’s request for a new base return on equity (ROE) of 10.54% and a 50-basis-point ROE adder for its continued participation in PJM (ER22-910).

The commission also accepted Rockland’s proposed updated annual transmission revenue requirement (TRR) under PJM’s tariff, suspending it for five months to become effective Aug. 30, subject to refund.

Both the ROE and TRR will be subject to review in hearing and settlement judge procedures established by the commission.

Rockland’s service territory includes parts of three counties in New Jersey that border New York — Bergen (eastern division), Passaic (central division) and Sussex (western division). The company said it turned over operational control of its eastern division transmission assets to PJM in 2001, while Rockland’s central and western divisions, along with Orange and Rockland Utilities (O&R), are members of NYISO.

According to Rockland, New Jersey law does not mandate that it maintain membership in PJM or any other transmission organization. Rockland said its transmission systems with O&R have historically been operated as a single system, “irrespective of state geographical boundaries or regional operating authority jurisdiction,” and O&R “continues to design and operate them as a single integrated system.”

“Prior to joining PJM, Rockland contends that it did not have its own annual transmission revenue requirement or transmission rates on file with the commission,” FERC said in its order. “However, upon joining PJM, Rockland separated its annual transmission revenue requirement for its eastern division from O&R’s transmission rate.”

Rockland said it conducted a “variety of transmission projects to expand and improve the safety, reliability, and capacity” of the integrated transmission system from 2016-2020 that “justifies” it updating its transmission rates. The company said it derived its updated annual transmission revenue requirement by:

  • calculating the 2020 annual revenue requirement for the integrated transmission system of $73,637,503 and
  • multiplying it by the ratio of the 2020 Rockland system peak load of 395 MW to the 2020 integrated transmission system peak load of 1,416 MW.

Rockland said it applied the calculation with a reduction of $187,217, which “accounts for the annual passback of net excess accumulated deferred income taxes (ADIT),” coming up with an updated annual transmission revenue requirement of $20,354,318, equating to $51,530 per MW/year.

The company said the updated rates were just and reasonable because they are “derived from a methodology the commission has already approved” and “reflect a composite fixed charge rate composed of reasonable factors derived from reasonable calculations.”

Rockland also requested a 50-basis-point adder to its base ROE for continued participation in PJM, saying the commission approved the participation adder in its 2017 rate case. The company said its PJM membership “continues to be voluntary.”

The New Jersey Division of Rate Counsel argued that Rockland “improperly proposes to include the costs of facilities that are physically located within the footprint of and under the control of NYISO and are not available for use by PJM transmission customers.” The Rate Counsel also argued that Rockland’s load ratio share methodology “leads to a result in which a PJM transmission customer physically located in the PJM footprint is paying a portion of the costs of O&R facilities located within the NYISO footprint that NYISO operates and controls.”

“Rate Counsel argues if the combined O&R and RECO transmission facilities are an integrated transmission system, then the customers on the two systems are similarly situated and it would be unduly discriminatory for customers on an integrated transmission system to pay different rates as a result of where on the overall system they connect,” FERC said in its order.

Rockland responded by saying the Rate Counsel attempted to “inaccurately paint a picture that the integrated transmission system consists of two separate and distinct pieces that are operated and controlled by two different regional transmission organizations.”

The company also said that if the commission adopted the Rate Counsel’s rationale, it “may have widespread dramatic impacts on transmission ratemaking with respect to any transmission system that is owned by more than one utility.”

Commission Finding

FERC conditionally granted the request for a 50-basis point adder, saying it was consistent with Section 219 of the Federal Power Act and commission precedent.

“Rockland is a member of PJM, and there is no evidence in the record suggesting that its membership is not voluntary, such as evidence suggesting New Jersey law mandates Rockland maintains its membership in an RTO,” FERC said.

The commission conditioned its approval on the adder being applied to a base ROE shown to be “just and reasonable,” with the resulting ROE required to fall within “the applicable zone of reasonableness,” to be determined in the settlement judge procedures.  Approval of the incentive was further conditioned on Rockland’s continued membership in PJM.

The commission found that its preliminary analysis suggested the proposed rate changes “may be substantially excessive” and would be “more appropriately addressed in the hearing and settlement judge procedures.”

FERC suspended the rates for five months and encouraged the parties to the proceeding to “make every effort to settle their dispute” before hearing procedures begin.

Commissioner Mark Christie issued a concurrence, saying an ROE “should reflect the market cost of equity capital, no more and no less, to the best of the regulator’s ability to determine, including pricing in risk.”

“An ROE adder, by definition, awards the utility more than the market cost of equity capital,” Christie said. “An ROE adder is literally an involuntary gift from consumers to a monopoly provider. While I recognize that ROE adders for RTO membership reflect current commission policy dating back several years, it is my hope we will finalize our proceeding initiated last year. This is particularly salient at a time when transmission charges are among the fastest growing components of consumers’ bills.”

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NREL: US Will Need 2,100 American-made OSW Turbines by 2030

Reaching President Joe Biden’s goal of putting 30 GW of offshore wind off the Atlantic and Pacific coasts by 2030 will require a supply chain capable of producing more than 2,100 wind turbines and more than 6,800 miles of cables, according to a report released Monday by the National Renewable Energy Laboratory (NREL).

And most of the components for those turbines and cables must initially come from Europe, even though “it is unlikely that the international suppliers will have sufficient throughput to support construction of both European and U.S. offshore wind projects,” the report says.

“If a domestic supply chain is not developed in time, bottlenecks in the global supply chain will present a significant risk to achieving the national offshore wind energy target,” the report says.

But Ross Gould, vice president of supply chain development at the Business Network for Offshore Wind (BNOW) sees such supply chain challenges in terms of economic development and job growth. “We know that there is a wide range of opportunities for manufacturing companies in the U.S. to participate in the offshore wind supply chain,” said Gould, who worked with NREL on the report. “These offshore wind projects have the capability of creating tens of thousands of jobs.”

By 2028, offshore turbines using 100% American-made components could create up to 62,000 jobs, the report says, and even turbines with only 25% domestic content could generate about 15,500 jobs, the report says.

But the path to hitting any of those numbers, as laid out in the report, is daunting. For example, while plans are underway to build 11 new OSW manufacturing facilities that can produce major components, such as turbine blades and towers, major gaps exist in the domestic supply chain for the components those factories will need.

Offshore turbines contain around 8,000 components, many of them much larger than similar components for onshore turbines, Gould said.

Offshore turbine blades are as long as a football field, “significantly larger than their onshore relatives,” Gould said in an interview with NetZero Insider. “And so, while we have the capabilities to produce [blades] for onshore, those companies would need investment to upgrade their equipment, as well as potentially training [employees] on the new equipment.”

Other components are not being produced, or produced at scale, in the U.S., the report says. For example, the permanent magnets used in offshore turbine generators require rare-earth metals that are not mined and cannot, at present, be processed in the U.S.

Still another obstacle, the huge size of some offshore components may also mean they can’t be transported by highways, Gould said. They will need to be built near a body of water and port facilities large enough and deep enough for the wind turbine installation vessels (WTIVs) and other ships used to build and operate offshore projects ― which brings up additional supply chain gaps, the report says.

Of the 22 ports on the Atlantic Coast, the Portsmouth Marine Terminal in Virginia is the only one that currently has the capacity to accommodate WTIVs, the report says. Others, such as the New Bedford Marine Commerce Terminal are not large enough but can serve as marshalling areas, using smaller “feeder barges” to ferry components out to installation vessels.

Such workarounds may be less expensive, the report says, but “they also introduce additional risk and logistic complexity to transfer components from the barge to the WTIVs at sea.”

These installation vessels must also comply with the provisions of a 1920 federal law known as the Jones Act, which requires that ships carrying goods between U.S. ports be American built, owned and operated. The report estimates that at least five such ships will be needed, but only one is currently under construction, for Dominion Energy’s Coastal Virginia Offshore Wind project.

Estimated cost per WTIV ranges from $250 million to $500 million, the report says, and each ship could take up to three years to build.

The Next BOEM Auction

The study is the first of two reports NREL and other industry stakeholders, including BNOW, will be producing on the offshore wind supply chain. The first part is intended to set out the scope of the needed buildout and the challenges ahead, Gould said. The second, to be published later this year, will look more closely at the kinds of investments and other support that will be needed to reach Biden’s 30 GW goal.

The push for getting an offshore supply chain up and running as quickly as possible is being driven by the growing number of offshore projects in development up and down the East Coast.

In February, the Bureau of Ocean Energy Management (BOEM) held a record-breaking auction for six offshore leases in the New York Bight, pulling in bids totaling $4.37 billion. If fully developed, the six auction sites could produce more than 19 million MWh of electricity per year, enough to power close to 2 million homes, based on BOEM’s estimate of 3 MW/sq km. (See Fierce Bidding Pushes NY Bight Auction to $4.37 Billion.)

The next BOEM auction, announced Friday, will be held on May 11, for two offshore leases in the Carolina Long Bay, off the coasts of North and South Carolina. According to the BOEM announcement, the two sites, totaling 110,091 acres, could produce up to 1.3 GW of energy, enough to power 500,000 homes. The final sales notice for the auction lists 16 eligible bidders, including Duke Energy Renewables, Ørsted North America and Shell New Energies.

With thousands of megawatts to be built in less than a decade, Matt Shields, senior offshore wind analyst at NREL, estimates that two or three manufacturing plants will be needed for each major offshore wind component, such as blades and cables. Costs per facility could range from $200 million to as high as $900 million, he said.

“These figures typically don’t include additional investments in port capabilities to support these big facilities,” Shields said in an email to NetZero Insider. “We can safely say that, if we do build all these facilities, it will be in the billions of dollars and will require a mix of public [and] private investment.”

While the current report does not address policy, Shields said, “There are a lot of nuances about what exactly is needed. … The most important thing is certainty about projects actually getting built so that OEMs can have low-risk return on investment.”

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FERC Fines Dynegy $569K for Misleading Ramp Rates in PJM

FERC on Monday approved an agreement between Dynegy and its Office of Enforcement that will have the company pay more than $569,000 to settle allegations that it violated the PJM tariff by misrepresenting the ramping levels of 10 of its combined cycle combustion turbines in 2017 (IN22-3).

Enforcement found that the units’ real-time energy market offers misrepresented that they could “ramp to their maximum oil-based output attained during their summer capacity tests (ICAP) while running on gas.” The office also alleged that Dynegy failed to comply with the requirement that each unit be able to “change output at the ramping rate specified in the offer data.”

Dynegy stipulated to the facts in the agreement but neither admitted nor denied the alleged violations. The company agreed to pay disgorgement plus interest, totaling $119,425 and a civil penalty of $450,000 to the U.S. Treasury and to submit two annual compliance monitoring reports identifying “any known violations” regarding the PJM units identified in the investigation.

“The PJM market and its market participants bore the cost of Dynegy’s violation,” FERC said. “The commission directs PJM to use its best efforts to allocate the disgorgement funds on a pro rata basis to affected market participants.”

Background

The commission said the 10 units identified in the investigation were split among three facilities in PJM: Pleasants Power Station in West Virginia; Armstrong Power Station in Pennsylvania; and Troy Energy Facility in Ohio.

FERC said during PJM’s capacity auctions for the 2016/17 and 2017/18 delivery years, the previous owner of the units offered and cleared capacity “at a level that would require the units to run on oil” to meet their ICAP during a capacity test, with Dynegy inheriting an “oil-based” ICAP for each unit for both delivery years when they were acquired.

“However, these units were unlikely to be able to reach their oil-based ICAP when the units were already running on gas on summer days in 2017 consistent with the ramp rate that Dynegy entered for these units’ real-time offers,” FERC said.

In the summer of 2017, Dynegy’s real-time offers represented that the units could attain oil-based ICAP “in less than a minute if dispatched from a unit’s maximum output on gas that day to the higher oil-based ICAP.”

FERC said for the units to achieve maximum output after starting on gas in the summer months, they would “likely have to switch to oil” by ramping down to about 20 MW and then ramping back up after the fuel changeover was completed. The process would take about 28 minutes to go from the unit’s daily maximum output on gas to the oil-based ICAP.

The investigation found the real-time offers “misrepresented the ramping rate for the segment of the real-time offer curve that could only be reached on oil” and that Dynegy submitted “false or misleading information” to PJM that the units could ramp upward to the oil-based ICAP in one minute.

Dynegy calculated each combined cycle’s maximum generation using a formula incorporating the next day’s forecasted ambient conditions under both gas and oil, the commission said, and the calculations were used to determine the unit’s day-ahead and real-time offer curves and economic maximum for the day.

“In the summer months of 2017, the oil-based ICAPs were generally too far above the daily predicted gas max for Dynegy to reasonably expect that the units could reach their oil-based ICAP on gas alone,” FERC said.

Dynegy sold the Troy and Armstrong facilities in July 2017 to LS Power. Vistra (NYSE:VST) acquired Dynegy, including the Pleasants units, in April 2018.

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Constellation Hit with $4.7M Penalty for Violating CAISO RA Rules

Constellation NewEnergy (CNE) has agreed to pay $4.7 million in penalties for violating CAISO tariff provisions related to the treatment of imports intended for resource adequacy.

FERC on Tuesday issued an order approving a settlement in which the company will pay a $2.4 million civil penalty to the U.S. Treasury Department for violating the RA rules and associated FERC regulations. The company must also disburse $2.3 million in funds to CAISO, which will be distributed to network load (IN22-4).

A subsidiary of Constellation Energy (NASDAQ:CEG), CNE describes itself as “a full-service energy company that provides comprehensive and innovative solutions to meet the energy needs of governmental, large commercial, institutional and industrial customers.”

At issue in Tuesday’s order was CNE’s past practice — until 2017 — of not sourcing electricity for import before selling energy into CAISO’s day-ahead and real-time markets.

“CNE did not have a specific source of power linked to a specific RA import prior to submitting offers and instead intended to rely on the bilateral spot energy market if needed,” the commission wrote. “As a part of this business practice, CNE regularly offered its import capacity into the CAISO day-ahead market at $399/MWh. If those day-ahead offers cleared, CNE would reoffer the import capacity in the real-time market at either $899/MWh or $999/MWh.”

In June and August 2017, CNE failed to meet RA-related dispatches in California because it could not secure electricity in the bilateral market, prompting it to end the practice.

But FERC’s Office of Enforcement found that CNE’s practice violated the commission’s market behavior rules — specifically 18 C.F.R. section 35.41(a) — and sections 4.2.1, 37.2.1.1, and 37.3.1 of the CAISO tariff.

The commission explained that section 35.41(a) states that “where a seller participates in a commission-approved organized market, seller must operate and schedule generating facilities, undertake maintenance, declare outages, and commit or otherwise bid supply in a manner that complies with the commission-approved rules and regulations of the applicable market.”

Enforcement determined that CNE violated that rule by violating sections of the CAISO tariff that require market participants to follow the ISO’s dispatch instructions when the company could not respond to the RA-related dispatch signals in June and August 2017.

FERC found that CAISO’s tariff “requires that market participants have a ‘reasonable expectation’ of being ‘available and capable of performing at the levels specified in the bid’ at the time it is placed in the day-ahead market. Enforcement determined CNE lacked a sufficiently reasonable basis for its expectation that it would be able to wait to secure electricity in the spot market to support its RA imports during times when the market was constrained.”

Enforcement also pointed out that it was “unreasonable” for CNE to expect that electricity would be readily available in the spot markets when CAISO prices were reaching or exceeding $999/MWh, “because such prices usually reflect an environment in which it is difficult to secure sufficient supply to meet demand,” the commission said.

“In particular, we note that CNE’s conduct went against the purpose of RA, which is to ensure that firm resources are available to address supply shortfalls,” FERC concluded.

In addition to paying the penalties, CNE also agreed to only use specific generation sources or firm contracts with respect to importing RA in the future.

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Vermont Senate Advances State’s 1st Environmental Justice Bill

The Vermont Senate passed a bill 28-1 Tuesday that would, for the first time, legally define what environmental justice means in the state.

“We are among a handful of states left that have not passed an EJ bill because we long thought this is an urban issue or this is a Black and white issue,” Sen. Kesha Ram Hinsdale, sponsor of the bill, said during a March 25 floor debate.

The bill (S.148) provides a framework to ensure Vermonters “don’t experience the rural isolation of poverty and pollution without also experiencing the political power needed to remedy their situation,” Hinsdale said.

Hinsdale first introduced an EJ bill for the state 14 years ago but has yet to see the policy make it to law. She introduced the current version last April, and it did not move out of the Senate Natural Resources and Energy Committee before the end of the legislature’s first biennium session.

The bill received a significant boost of support in December with the release of the Vermont Climate Council’s Initial Climate Action Plan, which called for adoption of a statewide EJ policy to inform the work of state agencies and departments. And in February, a group of 33 advocacy organizations wrote to the Senate asking for passage of the bill.

Upon passage of the second reading of the bill in the Senate Friday, Vermont Lt. Gov. Molly Gray called the legislation an “important first step” in putting EJ into the workings of the government.

“We know from Hurricane Irene [in 2011] and other extreme weather events, that there are individuals and communities in Vermont who are disproportionately impacted by climate change,” Gray said in a statement. “If we are going to reach our climate goals and protect the environmental health and well-being of all communities, every Vermonter must be able to fully participate.”

With the bill’s passage in the Senate, it now moves to the House Natural Resources, Fish and Wildlife Committee, which has already reviewed the bill and will consider it for recommendation to the full House, Hinsdale told NetZero Insider.

Bill Provisions

The bill would set an EJ policy that says environmental burdens and benefits must be distributed equitably among Vermont’s communities. In support of that policy, the state would review past investments to determine which communities have received environmental benefits associated with those investments. And starting in 2024, nine government entities, including the Public Utility Commission, would coordinate investments in a way that ensures EJ populations receive at least 55% of the benefits.

It also defines an EJ population as a census group in which:

  • the annual median household income is less than 80% of the state median household income;
  • Persons of Color and Indigenous Peoples represent 6% or more of the population; or
  • 1% or more of households have limited English proficiency.

To help state agencies and departments collaborate on EJ efforts, the bill would establish a 12-member interagency EJ committee, comprising government officials and a diverse, 17-member advisory council consisting of community members. At least half of the advisory council members would have to reside in an EJ population.

In addition, the bill would allocate funds for the Agency of Natural Resources to create a state mapping tool that identifies EJ populations and measures environmental burdens “at the smallest geographic level” possible.

The Senate passed an amendment March 25 that reduced a $3 million appropriation for the bill to $700,000, of which $500,000 is allocated to the mapping tool. Sen. Richard Westman, in recommending the amendment, said that the Appropriations Committee sought to move “non-immediate spending” for later consideration in its work developing the full state budget.

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MISO Fills out Executive Team

MISO will promote and install new officers of its executive management effective April 1.

The grid operator announced last week that it will add three vice presidents and promote three current vice presidents to the senior level.

New senior vice presidents will include current Vice President of System Planning Jennifer Curran, General Counsel and Corporate Secretary Andre Porter and Chief Digital Officer Todd Ramey. Curran and Ramey have been with MISO for about 20 years apiece; Porter joined the RTO in 2016.

New vice presidents will include Executive Director of System Operations Renuka Chatterjee, Executive Director of System Planning Aubrey Johnson, and Melissa Seymour, executive director of external affairs for MISO’s Central region.

Chatterjee is a 21-year veteran of MISO. Johnson and Seymour joined MISO in 2017 and 2013, respectively.

CEO John Bear said the Board of Directors was fully supportive of the promotions. In a press release, he said the six “have individually and collectively made exceptional contributions to MISO’s history by sharing their expertise and consistently demonstrating our core values.”