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November 20, 2024

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Consumers Threatens to Hold off Closing Mich. Coal Plants

LANSING, Mich. — Consumers Energy (NYSE:CMS), the state’s largest investor-owned utility, has warned it may drop its plans to close its remaining coal-fired power plants by 2025 unless the state’s Public Service Commission ensures it can recoup both the generation and revenues lost through those closures using gas-fired plants.

In a filing responding to a proposed decision presented to the PSC by Administrative Law Judge Sally Wallace on the company’s integrated resource plan, Shaun Johnson, general counsel for Consumers’ parent company CMS Energy, said that “without adequate assurance of cost recovery related to the early retirement of its remaining coal generating plants and without an adequate plan to replace the capacity and energy derived from those plants, [parent company] Consumers Energy will run those plants until their previously planned retirement dates, keeping Consumers Energy and Michigan reliant on coal for nearly two decades.”

Consumers can do that, Johnson said, because the Michigan law on utility IRP filings also allows utilities to “not accept a commission order in an IRP proceeding. And for that reason, the company is filing these exceptions to make clear that there are certain core principles to the plan — principles that the proposal for decision rejected and modified — that must be resolved to the company’s satisfaction in order to see the company accelerate its coal fleet retirement.”

The warning has raised alarms among environmental groups, which had also criticized Consumers’ IRP for the continued use of gas-fired generation, and comes at the time when the state’s Council on Climate Solutions will hold its final scheduled meeting before issuing the state’s proposed plan to go carbon neutral by 2050.

Consumers filed its IRP on June 30, 2021. In the proposal it called for closing the Karn coal plant in Exxeville in 2023, and all three units of the Campbell Generating Plant in West Olive by 2025. It had previously planned to close the Campbell plant by 2039. The IRP also called for replacing the lost generation with new renewable resources and gas plants, including plants it would acquire.

Wallace’s proposed decision calls for the commission to approve closing Karn and Campbell Units 1 and 2 as proposed. But it called for delaying closing Campbell Unit 3, the plant’s largest, for more analysis into its potential effect on availability. Wallace also urged the commission to reject the utility’s plan to purchase three natural gas plants from its subsidiary.

Under state law on IRPs, the PSC must make a decision within 300 days of when Consumers first filed its plan. While the commission took comments on the proposed decision until Monday, no further public hearings will be held on the issue before it rules.

The proposal to delay closing Campbell 3 led environmental groups to object. The Sierra Club, Michigan Environmental Council and the Natural Resources Defense Council joined in one objection, urging the PSC to approve closing Campbell 3 by 2025, calling it the “most forward-looking” item in Consumers’ initial proposal.

In Consumers’ objection to the proposed decision, Johnson said, “Without an actionable capacity plan using existing generating units to replace the retiring capacity in 2025, and without certainty on recovery of a reasonable return on the unrecovered book balance of the retired units, the entire plan falls apart. …

“Michigan will face a lost opportunity to expedite its transition to clean energy, reduce emissions, increase reliability and lower energy costs,” Johnson said. “That would mean no accelerated coal retirements … and no expanded solar buildout. That is not an outcome Consumers Energy wants to see. And we believe it is not an outcome the state of Michigan and this commission wants to see.”

Tim Werner, a Traverse City Commissioner and member of the city’s Board of Light and Power, said the threat to hold off closing the coal plants poses a risk to Michigan meeting a goal of carbon neutrality by 2050. “It would maybe not be impossible, but so difficult” to reach if the plants remained open until nearly 2040, he said.

Traverse uses electricity generated by the Campbell plants, and while city officials and residents would like the plants shuttered to boost renewable resources, Werner also recognized the complexities of reaching a decision. While many environmentalists are pushing for no natural gas in reaching carbon neutrality, Werner said that a compromise may be necessary to get the Karn and Campbell plants closed by 2025. That could include letting Consumers own and run the gas plants for a set number of years before closing them as more renewables come online.

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Congressional, White House Officials Hopeful for Passage of Tax Credit Package

WASHINGTON — Word that Sen. Joe Manchin (D–W. Va.) is open to resuming negotiations on a scaled-back version of the Build Back Better Act that he torpedoed in December buoyed speakers from Congress and the White House at the American Council on Renewable Energy (ACORE) Policy Forum Thursday.

Speakers said they hope to pass a package this spring.

National Climate Adviser Gina McCarthy reeled off a list of cost savings the bill’s clean energy investments could provide for U.S. families. For example, energy efficiency incentives could reduce home energy bills by $500 per year.

“This is what we can deliver to people,” McCarthy told an audience of almost 200 at the live event. “What’s wrong with this? Why aren’t we running as fast as humanly possible? What Congress needs [is] to get these investments on the table and to move them forward quickly. And we’re going to do whatever it takes to get these investments over the finish line.”

The Build Back Better Act contained $555 billion in clean energy tax credits and other incentives that organizations like ACORE lobbied hard for last year. The credits are critical for President Joe Biden and the industry to meet the president’s goal of a 100% decarbonized grid by 2035 and a net-zero economy by 2050.

In a string of recent media reports, the latest in E&E News, Manchin has signaled that he is still open to a reconciliation package that would include at least some of the clean energy incentives. At the same time, Manchin has said he believes responding to the war in Ukraine will require stronger “all of the above” energy policies.

Senate Finance Committee Chair Ron Wyden (D-Ore.), in an afternoon keynote delivered remotely from his Senate office, told the gathering he’s confident of having 50 votes in the Senate for his Clean Energy for America Act, which would eliminate 44 existing tax breaks and replace them with technology-neutral credits based on emission reductions.

“We will have in the future, a technology-neutral system, which was very important to Sen. Manchin,” Wyden said. “And a technology-neutral system would be tied to a very different lodestar, and that lodestar is: the more you reduce your carbon emissions, the bigger your tax savings.

“I think when Sen. Manchin says … we may need to make some additions to deal with Russia and Ukraine, I don’t think it means unraveling Clean Energy for America,” he said.

On a panel on the current state of play for energy tax credits, the name “Build Back Better” was, in most cases, strategically avoided. Rather, Will Conkling, Google’s (NASDAQ:GOOG) head of data center energy supply for the Americas, Europe, the Middle East and Africa, said the uncertainty surrounding the legislative package is making it increasingly hard for his company to sign contracts for renewable energy. Conkling said renewable energy developers “won’t even show me a price because they are so uncertain about all the different forces that are at work with that three- or four- or five-year timeline. … Will they even sign a contract today is in doubt.”

For clean energy developer Arevon, that uncertainty is being played out in supply chain delays, said Katherine Gensler, the company’s vice president of government affairs and marketing.

“Our team has spent a lot of time in the last six months renegotiating contracts and pushing schedules out into the future to try to get some alignment and a certainty about when deliveries will be made,” she said. “But it just continues to be a challenge, and there’s not a clear path.”

The Ukraine Conundrum 

The Russian invasion of Ukraine has quickly become a flashpoint in political debates about U.S. energy policy. Republicans in Congress continue to slam Biden’s clean energy agenda, calling instead for more drilling on public lands and a loosening of regulations to stimulate domestic oil production. Biden and the Democrats have countered that clean energy is now even more critical for national security.

“Clean energy is a triple-edged sword right now,” McCarthy said. “It can tackle climate change. It can bring down consumer costs for everyone. And it will be the way in which we drive to national security. This is what clean energy brings to the table every day. And with this brutal war raging in Ukraine, we’re seeing just how easy it is for autocrats to use fossil fuels as weapons, unleashing volatility in our global energy markets to pursue their own agenda.”

At the ACORE event, the Ukraine discussion centered on the challenge of balancing long-term clean energy goals with the immediate need to ramp up oil and gas production to meet the domestic and foreign demand resulting from import bans on Russian petroleum.

While responding to the current emergency and ensuring our European Union allies have stable energy resources, a longer-term view is still needed, McCarthy said.

“This is an emergency that we’ll get through,” she said. “But we cannot increase our dependency on fossil fuels. … We have to have this be a short-term, emergency fix toward a longer-term effort to achieve clean energy together, that’s consistent with the [climate] commitments that both the EU and the United States” have made.

ACORE CEO Gregory Wetstone agreed that “investments to deal with that short-term need [should] be consistent with the longer term. We want to make sure that we don’t see investments in infrastructure that become stranded assets. That’s what it comes down to,” he said. “That infrastructure needs to be compatible with a clean energy transition.”

Speaking on the tax credit panel, Bobby Andres, senior policy adviser for Wyden, similarly said that the war in Ukraine and “events in Europe may actually be spurring additional desire to move on the clean energy package.” Build Back Better was “designed to tackle climate issues, was designed for decarbonization, but the design choices also are things that help address energy costs that will spur clean energy development, which will then reduce oil and gas demand, both reducing costs for consumers and allowing us to export more of those [fuels] to our allies.”  

Failure is Possible 

Andres said he believes a reconstituted reconciliation package is the way forward, with a late spring target for passage. The window is narrow and closing, he said. With the Senate now focused on the confirmation of Supreme Court nominee Ketanji Brown Jackson, the work session between Easter and Memorial Day may be the last chance to get the package written and passed this year.

Beginning in the summer, the mid-term elections will provide significant headwinds, with representatives and senators up for re-election focused on short-term issues of concern to their voters and reluctant to push for large, expensive legislative packages, like BBB, said Jon Bosworth, legislative director for U.S. Rep. Earl Blumenauer (D-Ore.).

“Members are potentially nervous about taking bold legislative action,” Bosworth said. But, echoing Andres, he said the clean energy tax credits and other incentives can be framed as providing a longer-term solution to current economic stressors such as inflation and high gasoline prices.

“I think we have a good case that providing more energy security and stability in the years ahead [via a reconciliation package] will reduce this type of event from happening again,” he said.

But, outside Congress, selling such ideas to voters means shifting the conversation from political to more personal perspectives, McCarthy said.

“One of the things that we’ve desperately tried to do is to change the discussion from a planetary problem to a people problem,” she said. “I want people to understand that what we’re doing matters to them and to their families. … These tax incentives, the [production tax credit] and other manufacturing tax incentives are so important because they’ll put people back to work, because they will tackle the climate crisis, because they will give us security and independence.”

While Andres remains optimistic, he also admitted that failure is possible, and the fallback position for the industry would be to once again lobby to extend existing tax credits in end-of-year legislation, as occurred in 2020.

Gensler cautioned, however, that the extender option could leave out key incentives, such as a tax credit for standalone energy storage, a top priority for her company.

Echoing McCarthy, she said, “Speed is of the essence. We should be running as quickly as possible for each of these policies. Having a reconciliation bill framework presents us with a unique opportunity to lock in long-term policies. Anything we can do to really move the ball forward expeditiously is critically important.”

Rich Heidorn Jr. contributed to this report.

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FERC Issues Southern Show-cause Order on Rate Protocols

FERC on Thursday raised concerns about Southern Company’s formula rate protocols, issuing the utility a show-cause order to explain either why the protocols should remain in place under its Open Access Transmission Tariff (OATT) or how it would change the OATT to address the commission’s concerns (EL22-27).

In its order, FERC identified deficiencies with Southern’s formula rate protocols in three areas: scope of participation; transparency of information exchange; and ability of customers to challenge transmission owners’ implementation of the formula rate.

The first issue is based on the commission’s requirement that formula rate protocols allow “all interested parties [to participate] in information exchange and review processes,” including ratepayers, state utility regulatory commissions, consumer advocacy groups and state attorneys general. FERC found that the wording of Southern’s protocol may have inadvertently left some stakeholders out of the process.

“While Southern allows an ‘interested party or Commission Trial Staff’ to participate in the customer meetings, information exchange, and challenge procedures, its formula rate protocols do not define the term ‘interested party’ to generally identify which parties can participate,” FERC said. It ordered Southern to either rewrite the relevant section to specify who may participate in the procedures and to provide all such parties access to information about annual updates to the protocols, or to show cause why it should not be required to do so.

The commission’s transparency argument warns that interested parties might not be able to access the information they would need to evaluate the correctness of the formula rate, potentially leaving them unable to challenge it. This is because Southern’s protocol only requires that “workpapers and underlying service data” be filed as supporting documentation.

This requirement is a violation of previous FERC orders that mandate that “formula rate protocols must include greater detail regarding the financial and cost information from which a transmission owner’s rates are developed. This information must include underlying data and calculations supporting the formula rate annual updates … [including] underlying data and calculations supporting the formula rate annual updates.”

FERC also found Southern’s protocols deficient in several other ways: providing no procedure for making document requests, limiting the reach of potential information requests, failing to require disclosure of accounting changes that might impact the formula rate, and not providing for an annual meeting, among others. Again, the utility is required to justify its protocols or explain how it plans to remedy the issues.

Finally, the commission said Southern’s formula rate protocols do not provide sufficient detail relating to how interested parties can file formal and informal challenges to the utility’s rates. For example, Southern’s protocols do not require senior representatives to work with interested parties and improperly “limit the subject of a formal challenge to an interested party’s previous informal challenge.”

In addition, FERC said the language of Southern’s protocols “strictly [limits] the commission’s procedural options” regarding challenges to the utility’s rates. Specifically, the commission noted that Southern asserted its burden of proof in any FERC-ordered proceeding falls under Section 205 of the Federal Power Act; this raises the possibility of an attempt to prevent any proceeding under Section 206 of the FPA.

Under the commission’s order, Southern is required to file its response within 60 days. Interested parties are also invited to respond in the same docket.

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PG&E Rate Request Prompts Protests

Pacific Gas and Electric’s request for major rate hikes over the next four years, following substantial increases this year, provoked an outpouring of customer complaints during recent public forums held by the California Public Utilities Commission.

PG&E said it needs a huge boost in its 2023-26 General Rate Case (GRC) in part to pay for electric system upgrades to prevent wildfires.

In one CPUC forum Tuesday, however, residents objected to PG&E receiving more money for grid hardening to prevent wildfires after years of deferred maintenance and lax vegetation management led to some of the worst fires in state history over the last five years.

“I think these are unreasonable increases, and PG&E needed to address some of their problems years ago,” Bernadette Mcewen, a senior citizen from rural Tuolumne County, told two CPUC commissioners and an administrative law judge. “What are we going to expect from these increases? Just further increases, I would assume.”

Mcewen said her electric bill had increased by more than 20% since 2018.

PG&E “shareholders also need to take the burden of future [wildfire] prevention,” she said. “I do not believe that this hefty increase should be shouldered completely by the ratepayers.”

The combination of wildfire mitigation efforts, rising natural gas prices and California’s transition to renewable energy have led to steeply rising bills for customers of the state’s three largest investor-owned utilities, including Southern California Edison and San Diego Gas & Electric.

PG&E customers have borne the worst of it. The utility’s electric ratepayers were hit with a $1 billion rate hike in January followed by a $1.1 billion increase in March. The increases were mainly driven by higher-than-expected prices for natural gas, used in generation, and newly imposed FERC transmission-rate requirements.

Together, the increases worked out to a 19% rate hike in the past two months, or about $28 per month for the average customer.

In its 2023-26 GRC, now before the Public Utilities Commission, PG&E asked for a $15.5 billion base revenue requirement for its gas and electric operations — an “unprecedented” 30% increase over its 2020-22 GRC, according to the CPUC’s Public Advocates Office, which filed a protest in the matter.

That could translate to a 16% rate hike for residential electric customers in 2023 and a cumulative 23% increase through 2026. Combined with this year’s rate hikes, customers could see a 42% increase in their electric bills in five years. Average residential customers who paid about $135 per month last year would pay $186 by 2026.

In its protest, The Utility Reform Network (TURN) called the proposed rate hikes “shocking increases … not seen before in a major utility’s general rate case.”

The costs could be far higher than the GRC suggests, especially if the CPUC eventually approves a PG&E proposal to bury 10,000 miles of power lines in high-threat fire districts, TURN said.

Cost estimates for the effort have been scanty until recently, but information provided by PG&E to RTO Insider this week shows an estimated cost of nearly $11 billion for the undergrounding effort from 2022 to 2026. State and federal infrastructure funding could potentially pay for some of the effort, but ratepayers would likely have to absorb a significant share.

In the meantime, PG&E has asked for more than $1 billion in its GRC to prevent wildfires following five years of catastrophic blazes ignited by PG&E equipment. The money would pay for grid hardening and upgrades including undergrounding about 170 miles of power lines in and around Paradise, the town destroyed by the PG&E-caused Camp Fire in November 2018.

“PG&E’s most important responsibility is the safety of our customers and the communities we serve,” the utility said in its amended application filed March 10. “Our GRC forecast includes reasonable costs required to provide safe and reliable service and follow best industry practices.”

“Regulations require PG&E to take certain actions,” it said. “As an electric utility, PG&E’s wildfire mitigation proposals in this GRC follow the legislature’s mandate to ‘construct, maintain and operate its electrical lines and equipment in a manner that will minimize the risk of catastrophic wildfire posed by those electrical lines and equipment’ and achieve ‘the highest level of safety, reliability and resiliency.’”

The utility also asked for $900 million for its move from its century-old San Francisco headquarters, which it agreed to sell last year for $800 million, to its new building in nearby Oakland.

Other major expenses include a $220 million increase for utility pole and meter replacements, $172 million for new customer connections and upgrades associated with electric-vehicle adoption, and $168 million for hydropower plant improvements, the CPUC said in a summary.

PG&E’s 2023-26 rate case is a new four-year combined gas and electric plan ordered by the CPUC. Prior GRCs were two years, with gas and electric filings weighed separately.

The CPUC will decide PG&E’s rate case later this year. The plan is scheduled to take effect Jan 1, 2023

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New York Residents Question Nuclear Plant Decommissioning Safety

New York residents concerned about safety issues told state officials this month that they lack representation on the board overseeing the Indian Point nuclear plant decommissioning (Case No. 21-01188).

Several residents recommended that Peekskill-based scientist and environmental activist Courtney Williams be appointed to the Decommissioning Oversight Board (DOB), speaking at its public meeting held with the Indian Point Closure Task Force on March 17, with many submitting their comments for a Wednesday deadline.

“This is really discriminatory not to have community representation by a qualified resident from an environmental justice community,” White Plains resident Ellen Weininger said.

Weininger also joined others and a group called “Stop the Algonquin Pipeline Expansion” in seeking better oversight of Camden, N.J.-based Holtec, managing the decommissioning, and Enbridge’s cooperation in safeguarding its three high-pressure Algonquin natural gas pipelines that pass close to the shut-down nuclear plant and its growing platforms of spent-fuel casks.

“A secretive company with a continuously morphing array of limited liability entities is now in charge, with the [Nuclear Regulatory Commission] handing out exemptions like hotcakes at each site Holtec is working on,” the environmentalists said.

Holtec formed a partnership with Montreal-based SNC-Lavalin to help win regulatory approval of its bids to decommission nuclear plants in three states, but later dissolved the partnership, according to several comments.

Holtec had reached out to an international company, which then did not work on Indian Point. DOB member Sandra Galef expressed concern that the relationship was “just a façade.” Galef is the state assemblywoman for the 95th District that includes Buchanan, site of the nuclear plant.

“We’re taking a fleet approach,” Rich Burroni, site vice president for Holtec, said.

Holtec is decommissioning the Pilgrim plant near Boston and is ahead of schedule at Oyster Creek in New Jersey. “We’re an international company, so we’ve taken that experience, and it’s helped us here at Indian Point,” Burroni said.

Safety First

Williams said that she was “very happy” to hear from Burroni that he now knows how to contact Enbridge, that there’s a direct line in the control room and that there are iron plates over the pipeline.

“All of that is new since I visited the plant in December, and they had no idea who their Enbridge counterparts were, how to reach out to them and didn’t feel it was necessary to put plates down, etcetera,” Williams said. “I hope that Holtec is not still assuming that if the pipeline blows up, they’re going to go out there with fire hoses.”

She also complained that the DOB’s responses to questions posed at its previous public meeting in October were not posted online until the day of the current meeting.

Iron plates on top of pipeline road crossings would not prevent a rupture, but would be serious projectiles in a rupture, and deactivated reactors do not reduce the potential of a cataclysmic fuel pool explosion should a rupture occur, North Salem resident Susanna Glidden said.

“Construction of Indian Point never should have been approved near two fault lines and on top of the gas pipeline with another added a few years later and recently the massive [Algonquin Incremental Market] AIM pipeline,” Glidden said.

Approval of the 42-inch, 37.6 mile-long AIM pipeline was based on being able to shut off the gas from the control room in Houston in three minutes should a rupture occur, but that was found to be a false claim, she said.

“Moreover, instead of stored fuel casks lined up like bowling pins broadcasting a target for terrorism, we want them protected the real way with a hardened surface and berms,” Glidden said.

Indian Point radiation monitoring (Holtec) Content.jpgIndian Point radiation monitoring updates from March 2022 | Holtec

Indian Point is one of only five U.S. nuclear power plants with continuous radiation monitoring capability, Burroni said. The site’s exiting pad will hold 75 spent-fuel casks, and the company is building a new pad that will hold an additional 52 casks, with the final concrete pour scheduled for this spring.

It is not necessary to hit a transmission pipeline to cause it to rupture, as abnormal service loading can cause the pipeline to either crack or stress, said Rick Kuprewicz, president of Accufacts and a pipeline safety expert.

“There can be unusual decommissioning activities that could put a stress on the pipelines even though that activity is off the pipeline right of way, so it’s important that Holtec and Enbridge communicate what the various activities are and be sure that Enbridge understands what’s going on,” Kuprewicz said.

Union Concerns

Local unions also have become frustrated with Holtec during the Indian Point decommissioning process.

The company has excluded Chauffeurs Union Local No. 456 from construction work that its members have performed for decades, said task force member Louis Picani, who represents Teamsters and Local 456.

“Now Holtec is excluding Teamsters from performing construction work at the site for all decommissioning work,” Picani said. “Moreover, while the Teamsters were told that they would be included in a successor agreement covering this work, Holtec has reneged.”

In addition, Local 456 has long represented the nuclear security officers at Indian Point and has filed numerous grievances concerning Holtec breaching the collective bargaining agreement, as well as retaliating against members for engaging in protected, concerted activity, he said.

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BPU Approves Agreement to End the Use of Coal Plants in New Jersey

The last two coal-fired electricity generation units in New Jersey will close under an agreement approved Wednesday by the New Jersey Board of Public Utilities (BPU) between the plants and the utility they sold power to for more than three decades.

The BPU backed a petition filed by Atlantic City Electric (ACE) (NASDAQ:EXC) seeking to modify power purchase and sales agreements that the South Jersey utility held with Chambers Cogeneration and Logan Generating Plant, the board said in a release. As a result, coal-fired generation at Logan, a 225-MW facility located in Swedesboro, and Chambers, a 285-MW facility in Carney’s Point, will “end after a brief period of transition,” the BPU said.

The deal concludes what ACE describes in its petition as a pair of contracts struck more than 30 years ago under which the utility soon began losing money because of changing market conditions. While the agreements will bring the benefit of ending the emissions of extensive volumes of greenhouse gases, they will also enable the utility to reduce its ongoing losses, which would otherwise have continued until 2024.

The agreement requires ACE to make a series of negotiated, fixed monthly payments for the outstanding period of the power purchase and sales agreements, the BPU said. These will be partly offset by payments to ACE customers from Logan and Chambers, it said.

Gov. Phil Murphy, who has made the state’s transition to clean energy a central element of his four-year tenure, said the closures are a key element of that effort.

“These agreements today allow us to further shift New Jersey’s energy portfolio away from harmful coal generation and focus on clean energy technology,” Murphy said.

Starwood Energy Group — a Greenwich, Conn.-based private equity investment firm that owns the plants — said in a release that it expects the plants to cease coal-fired generation in May.

“We are pleased to continue our focus on sustainable energy transition by creating win-win solutions with our counterparties such as ACE,” CEO Himanshu Saxena said.

Ongoing Losses

ACE said that under the agreement, customers would get $30 million in energy bills savings through the end of 2024.

The utility entered into contracts to buy power from the two plants in 1988, but by 1994 the “pricing terms included in the contracts resulted in payments in excess of the market value of the output of the facilities,” ACE said in a petition it filed with the BPU in December. As a result of the high costs, all of the energy and capacity purchased by ACE under the contracts was sold into PJM’s wholesale markets, the petition said; none of the power generated was being used to meet the needs of customers.

“ACE does not earn a return on, or benefit from, these agreements in any way,” the petition said. “Consequently … ACE has sought for many years to identify and employ strategies for renegotiating, modifying and/or eliminating the Chambers and Logan agreements.”

The order approved by the BPU said ACE estimated that had it not negotiated the termination agreement with the two plants, the sales and purchase contracts would result in payments of $417.8 million to the two plants. That would have been offset by PJM revenues of $159.3 million, leaving customer costs of $258.5 million, it said.

Starwood purchased the plants, as well as two other plants in Arkansas and West Virginia, in 2017. At the time, the company said three of the plants purchased “comply with current and currently anticipated environmental regulations and are relatively recent vintage assets that do not have legacy environmental issues.”

Reducing Pollution

ACE Region President Doug Mokoid said the company is proud to “do our part in helping to establish the state as a clean energy and climate leader.”

“This accomplishment means more than bill savings for our customers,” he said in a release. “It means cleaner air for our communities and a safer environment for generations to come.” The company in September announced a “major climate change commitment” that called for the company to take “actionable measures” to cut greenhouse gases, such as transitioning to clean energy for its buildings, electrifying 50% of its vehicles and installing energy-efficient lighting at company facilities.

The New Jersey chapter of the Sierra Club welcomed the move and said that Starwood plans to work with a clean energy developer to bring renewable energy projects to the former coal plant locations. A letter of support for the ACE petition filed by Sierra with the BPU said the two plants have “pumped out between 1.5 [million] and 2 million tons of carbon dioxide pollution every year since 2016.”

“This is a huge milestone in the state’s transition to a clean energy economy,” said Greg Gorman, conservation chair of the chapter. The organization is “thrilled that Starwood Energy is looking to directly transition to cleaner, cheaper renewable energy at these sites, ending nearly three decades of pollution in Carneys Point and Penns Grove, historically overburdened communities on the Delaware River.”

The New Jersey Division of Rate Counsel, which reviewed the plans and agreements outlined in the petition, said in a March 7 letter that it would not oppose the deal. The agency said there were environmental benefits to closing the plants, although the delay in closing them and other factors mean the benefits are “not easily quantified.”

It also said it could not say the financial benefits to customers were “just and reasonable,” because they could diminish in certain scenarios.

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DOE Gets Hydrogen Hub Advice from Industry and Others

Midwest industries with operations in Ohio and Pennsylvania filed detailed responses to the U.S. Department of Energy’s initial request for information (RFI) on what it will take to develop a multistate hydrogen hub replacing natural gas with hydrogen in refining, power generation, steel and cement making, and fertilizer production.

DOE has been authorized to spend $8 billion to foster the development of regional hydrogen hubs, including one or two hubs that convert natural gas to hydrogen for regional use, and sequester the resulting carbon dioxide underground if it is not needed for other industrial processes. The resulting “blue hydrogen” can be mass produced with established technologies at a fraction of the cost of hydrogen produced with electrolysis.

Ohio, Pennsylvania and West Virginia sit above the Marcellus and Utica shale gas formations that have produced massive quantities of natural gas at prices well below the national average for the last decade. The development of a tristate hydrogen hub in the region would provide a new use — with a resulting boom — in shale gas development.

The Ohio Clean Hydrogen Hub, with more than 50 members, and the Midwest Hydrogen Center of Excellence at Cleveland State University noted that Ohio’s industries are within 600 miles of 60% of the nation’s population and are well connected “via energy delivery highways” both with the Upper Midwest and the East Coast.

The group also noted that industries in the state have a use for carbon dioxide and that CO2 not needed could be injected deep underground because Ohio’s geology is well suited for injection wells.

“The [eventual DOE] RFP should give preference for at least one blue hydrogen-focused hub,” the Ohio group wrote. “The Appalachian region offers not only significant access to natural gas but also additional feed stocks from coal, waste coal, biomass co-firing and nuclear. Ohio also has ideal geology for carbon dioxide injection.

“Ohio’s well established markets for the use of carbon dioxide with urea and cement manufacturing put the state in a unique position to utilize every aspect of existing industries to further bolster hydrogen generation.”

Kirt Conrad, CEO of the Stark Area Regional Transit Authority and an organizer of the Ohio Clean Hydrogen Hub Alliance, said that despite separate filings to DOE, the Alliance is committed to working with Pennsylvania and West Virginia and other nearby states to develop a hydrogen hub.

Adding that creating the hub will also need assistance from the states — for example, for authorization to build hydrogen pipelines and sequestration of carbon dioxide — Conrad said the effort essentially has to be industry-driven.

“The state needs to support us at some level. But ultimately, if you really look at the RFI, it’s people putting together projects in a plan to, basically, create a hydrogen ecosystem. So really is going to be the private sector, the users and consumers of hydrogen that are going to be the centerpiece of this,” he said.

Although Ohio and Pennsylvania groups last month separately announced the creation of industry groups to compete for the DOE hydrogen grant, both have worked together in the weeks since. (See Penn., Ohio and W.Va Considering Regional Hydrogen Hub.)

Despite that, the Ohio alliance and the Pittsburgh-based Northern Appalachian Industrial Alliance, whose members include heavy industry in both states, each submitted a separate filing in answer to the RFI.

Michael Docherty, executive director of Pittsburgh-based IN-2-Market, said he was not authorized to release the 17-page document the Pennsylvania alliance submitted because not all of its members had agreed to releasing it. But he stressed that the alliance is strongly committed to working with other groups in the effort to qualify for and win a DOE grant.

“We are absolutely — and have been from the beginning — committed to a tristate and regional approach,” he told NetZero Insider. “We believe that that’s the only way that this is going to be successful. And so we’re taking on the difficult task of working across state boundaries and across all these different regional stakeholder groups to try to find common ground.

“That includes engaging with all the key stakeholders, including legislators, labor, industry, universities [and] economic development. We are just in the early stages of those efforts, but we’re just trying to be a convener and a catalyst for promoting the opportunity and [to develop] a common vision. That’s probably the most succinct way I could put,” he said.

The West Virginia governor’s office did not respond to earlier calls for comment. But U.S. Sen. Joe Manchin (D-W.Va.) issued a released Tuesday announcing the state’s coalition had submitted a response to DOE.

In that release, Gov. Jim Justice (R) wrote: “West Virginia is the place where this all-important hydrogen hub belongs. As one the world’s energy powerhouses for generations, West Virginia has long served as the home of all kinds of cutting-edge technological advances in energy production, thanks to our rich natural resources and our skilled and dedicated workforce.”

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Fierce Competition in Plans to Upgrade NJ Grid

Atlantic City Electric (NASDAQ:EXC) outlined eight proposals Tuesday on how to enhance and upgrade New Jersey’s electricity grid to prepare for the influx of clean energy from the state’s planned 7.5 GW of offshore wind projects.

Anbaric, a renewable energy transmission and storage company, said its portfolio of 19 grid proposals could provide a “complete,” “flexible” and “low risk” system of land and sea power cables and interconnection points capable of handling New Jersey’s entire planned offshore wind generation.

More modestly, Rise Light and Power — a subsidiary of LS Power, a clean energy development, investment and operating company — suggested running cables from offshore turbines to a South Amboy, N.J., brownfield that, after conversion to a “renewable energy hub,” would be “uniquely positioned” to address the state’s needs.

The proposals were among 80 outlined by 13 companies or partnerships at a public hearing Tuesday that provided the first glimpse into the fruits of the competitive solicitation by the New Jersey Board of Public Utilities (BPU) for proposals on how to connect offshore wind turbines to the state’s grid and to upgrade it to handle the extra power.

The bidders laid out their proposals in a three-and-a-half-hour online session that was the first of four to review the responses to a solicitation conducted by the BPU with PJM under FERC Order 1000’s State Agreement Approach, as well as draw public input into the merits of the proposals. Future sessions will focus on integrating offshore wind energy into the grid, environmental permitting issues, and ratepayer protections and cost controls in the projects. (See PJM, NJ Seek FERC OK for OSW Tx Process.)

The BPU says it will decide which, if any, of the proposals to adopt over the coming months and will announce the outcome in October.

“The board is the ultimate decision-maker,” Andrea Hart, a BPU legal specialist who hosted the meeting, said as she brought it to a close with a warning about what the board is seeking.

“These projects are not likely to be pursued if they do not result in the development of lower costs, lower risks or a higher benefits for the interconnection and delivery to New Jersey offshore wind residents,” she said.

Identifying NJ’s Needs

The state is planning to generate 7.5 GW of offshore wind power by 2035, about half of which has been awarded in two solicitations, with another three expected, the first of which is expected to begin in Janurary.

In the second solicitation, the BPU in June awarded leases for two offshore wind projects: Ørsted’s 1,148-MW Ocean Wind II, located about 14 miles from the New Jersey shoreline; and Atlantic Shores, with 1,510 MW of electricity in an area between 10 and 20 miles off the Jersey Shore near Atlantic City, to be developed by a joint venture between EDF Renewables North America and Shell New Energies US. Those awards followed the BPU’s first award in 2019 of Ocean Wind, an 1,100-MW project also developed by Ørsted. (See NJ Awards Two Offshore Wind Projects.)

The BPU and PJM set out a rough guiding framework with the elements that the board believes need to be addressed as the RTO prepares for the increase in power when offshore wind projects come online. They include four onshore locations on the existing grid — one in North Jersey, two in the center of the state and one in the south — that are suitable interconnection points. The board also identified several “power corridors,” through which lines could run onshore from the coast to the connecting sites, and five suggested routes for cables running underwater to the shore.

Finally, the BPU suggested an “offshore transmission backbone” running offshore parallel to the coast, to which the turbines would connect and on which several offshore substations would be sited, providing the connecting points for cables running to the shore.

Vying for Attention

Presenting their proposals, bidders sought to distinguish themselves from the competition, not only with project details, but by touting their experience in the field, understanding of the New Jersey market, commitment to helping the state meet its clean energy goals, and ability to bring jobs and investment to the state.

Jersey Central Power & Light (NYSE:FE), which provides power to customers in 236 municipalities in New Jersey, touted its heavy presence in the state and its knowledge of what customers want.

“One of the things we’re very proud of is that in 2020, we purchased about $500 million worth of local goods and services, and of those purchased in New Jersey, over 40% of them were from diverse suppliers,” JCP&L President Jim Fakult said.

Others, clearly mindful of the sensitivity of the issue and local concerns at the potential disruption from construction and laying cables, stressed their efforts to choose cable routes and shore landing points that would avoid such disruption.

Consolidated Edison (NYSE:ED) representatives said it had opted to pursue a plan, called Clean Link New Jersey, that would create power corridors and run cables to the shore from the transmission backbone. For the latter, the company proposes an HVDC cable capable of carrying 2,400 MW that would require one or two interconnection locations, the company said.

The offshore cable would come on land at a “nonpublic location where our construction will not impact the beach … and minimize any impacts to the public,” said Morad Hekmat, a project manager for Con Ed.

Public Service Enterprise Group (NYSE:PEG), which submitted several proposals in a partnership with Ørsted, said their projects — collectively called Coastal Wind Link — would carry 4.2 GW of offshore wind power to the shore if all the elements were used. The proposals offer potential connections to not only Ørsted’s two projects but those of other developers, the company said.

Another element of the proposal is converting the AC power of the turbines and transporting the electricity through 320- to 400-kV DC cables under the sea floor, the company said. The cables would come ashore and run below ground to another converter, which will switch it back to AC before interconnecting to the grid.

Raymond DePillo, PSEG’s director of offshore wind development, added that the company’s proposal is distinct for its use of a “mesh grid” that links different offshore projects together, which provides the “ability to move energy between the projects continuously.”

“That means that the power can be delivered to the part of New Jersey that benefits the most from it in real time, lowering energy costs for consumers,” he said.

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Maryland Clean Energy Bills Pass 1st Hurdle on Crossover Day

“Crossover day” in the Maryland General Assembly is traditionally a legislative marathon in which bills must be passed in one house and cross over to the next to have any chance of final passage before they adjourn, this year on April 11.

Monday was the cross-over cut-off, and energy advocates across the state were tracking a number of bills down to the wire as committees met, compromises were made, and bills scored the three readings required for passage. Under Maryland law, bills must be “read” three times in each house to pass. In general, a first reading occurs when the bill is introduced; the second, when it is approved by a committee; and the third, when it gets a positive vote on the House or Senate floor.

The biggest and most significant piece of energy legislation, the Climate Solutions Now Act (SB 528), passed the Senate on March 14, and is scheduled for its first House hearing, before the Energy and Transportation Committee, on Thursday. If enacted, the bill would raise the state’s emission-reduction target to 60% below 2006 levels by 2030 and set a 2045 deadline for reaching net-zero emissions.

Other provisions in the bill target landfill methane emissions, new energy conservation standards for buildings and purchase requirements for zero-emission vehicles (ZEVs). (See Md. Senate Sets 2045 Net-Zero Target.)

While less comprehensive, other clean energy bills also moved ahead before or on Monday. Community solar, for example, had several key wins.

HB 1039 would provide an exemption from local or county property taxes for community solar projects used in “agrivoltaics,” which the bill defines as the simultaneous use of land for solar power generation and agriculture. The bill would also establish a 50% tax credit for community solar projects located on brownfields, landfills or “cleanfills,” which are lands with uncontaminated construction waste. Qualifying community solar projects approved on or before Dec. 31, 2025, would be eligible for the credit.

Meanwhile, SB 264 would extend property tax exemptions to other community solar projects of 2 MW or less that provide 50% of their power to low-income customers and are located on a rooftop, parking canopy or a brownfield. HB 440 would change the maximum size of community solar projects that can use virtual net-metering from 2 MW to 5 MW.

Electric Buses and Trucks

HB 696 would require the Maryland Public Service Commission to set up an electric school bus pilot program that would provide at least 25 electric buses and up to $50 million in rebates to participating school districts.

When the buses are not in use, a utility could draw power from their batteries through vehicle-to-grid technology without compensating the school district. School districts would be chosen for the pilot based on the “locational value” the bus batteries might have for the grid, and on the health and economic impacts for low-income and disadvantaged communities.

HB 1391, the Clean Cars Act, would establish a grant program to subsidize up to 20% of the cost of medium- and heavy-duty ZEVs.

HB 108, and its Senate counterpart, SB 524, are aimed at ensuring that the state’s energy efficiency program, EmPOWER Maryland, is providing measurable energy savings for customers: 0.4% per year beginning in 2023. It would also require the Department of Housing and Community Development to formulate a plan to provide energy-efficient home upgrades for low-income households across the state. Both bills were passed in their respective houses and crossed over.

HB 88 would require the PSC to submit a yearly report on distribution planning to the legislature, including on how it supports the state’s clean energy goals. It would also require the PSC and Maryland Energy Administration to encourage and support the state’s utilities in applying for grid planning funds that may be available from the Infrastructure Investment and Jobs Act.

With Democrats having solid majorities in both houses, the bills stand a good chance of passing by “Sine Die,” the last day of the session.

However, Republican Gov. Larry Hogan has already voiced strong opposition to the Climate Solutions Now Act. In a March 10 statement, Hogan called the bill a “reckless and controversial energy tax” that would impose “massive burdens on Maryland families and small businesses.”

Hogan pointed to a 2020 study from the World Resources Institute, in which Maryland had ranked first in the nation in decoupling its energy use from economic development. According to the study, the state cut its emissions 38% between 2005 and 2017, while at the same time increasing its GDP by 18%.

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MISO Delays $13B Long-range Portfolio’s Recommendation

MEMPHIS, Tenn. — MISO has delayed by a month a recommendation to the Board of Directors of a $13 billion package of long-range transmission projects.

During a Tuesday meeting of the board’s System Planning Committee, senior staff said they will seek board approval for the Midwestern 345-kV transmission lines in July instead of June.

Jennifer Curran, vice president of system planning, said the extra month will be used for an additional stakeholder workshop to discuss the projects. MISO had originally targeted a March approval for the first long-range projects.

“We do think it’s appropriate to act with deliberate speed, so we meet the reliability imperative,” Curran said of the remaining stakeholder discussions.

The stakeholder-led Planning Advisory Committee (PAC) will now consider whether to endorse the long-range portfolio May 27 instead of May 11. (See MISO Long-range Tx Plan Overlaps with SPP Study.)

Curran said staff are finalizing the first cycle of long-range plans “in earnest.” She said reliability analyses are complete and planners continue to work on business cases.

She reassured the board that benefits will be “well in excess” of the $13 billion portfolio MISO will recommend. The PAC meeting was the first time the RTO disclosed a cost estimate for the portfolio.  

MISO has cut one long-range project, dropping one of two 345-kV lines in southern Minnesota.

Curran said MISO considers the first cycle of projects final, with no more project proposals accepted for consideration. She said additional projects “are best reserved” for the second tranche of proposals.

The first cycle of long-range projects nearly quadruples early spending estimates for the 2022 MISO Transmission Expansion Plan. (See Initial MTEP22 Portfolio has $3.3B in Costs.)

Curran said the projects’ business cases will account for bolstered reliability, reduced resource adequacy requirements, avoided transmission and generation projects, decarbonization goals, avoided load shed events, and savings stemming from decreased congestion.

Barbara Krumsiek 2022-03-21 (RTO Insider LLC) FI.jpgMISO Director Barbara Krumsiek listens to updates during Board Week in Memphis, Tenn. | ©RTO Insider LLC

MISO Director Barbara Krumsiek said the benefits being hashed out in the business cases are “priceless.” “We don’t want to see the lights go out,” she said. “We don’t want to see load loss.”

Director Mark Johnson thanked MISO for naming and analyzing the first projects.  

“If you had asked me a year ago if we’d be where we are today, I wouldn’t have laid money on it,” he said. “But we have to move … I don’t think we can afford to wait. The decisions we’re making today will have an impact for decades.”

Johnson reminded stakeholders in the room that MISO and its members have a responsibility to ensure the grid’s continued reliability for “generations to come.”

“This is really a milestone getting to this day,” Clean Grid Alliance’s Beth Soholt said in agreement. However, she pointed out that the projects must go through challenging permitting and siting processes at state commissions.  

Soholt invoked the Cardinal-Hickory Creek project, a stalled line from MISO’s 2011 long-term portfolio that’s been held up in lawsuits over its siting through a protected area. (See Federal Judge: Tx Line Can’t Cross Wildlife Refuge.)

“I just don’t want to have multiple Cardinal-Hickory Creeks,” Soholt said. “We really don’t have anything until we have these lines in the ground.”

She asked MISO to build a coalition of support around the long-range lines and spread awareness of their necessity.

Board Addresses Long-range, JTIQ Overlap

MISO board members also touched on a two-project overlap between the long-range plan and the Joint Targeted Interconnection Queue (JTIQ) study with SPP.

Two proposed projects in the Dakotas and Minnesota are included in both the JTIQ study results and MISO’s long-range transmission portfolio. The RTO said it will likely build the two projects on its own dime since long-range planning takes precedence over the JTIQ study and SPP’s benefits are small. Both projects are located within MISO’s footprint. (See MISO, SPP Finalize JTIQ Results with MISO Tx Duplicates.)

Some directors seemed torn on the decision not to seek projects costs from SPP.

“I don’t want to be parochial about it, but if there’s a cost to SPP …” Krumsiek said before trailing off.

“Do you want to wait, or do you want to proceed?” asked MISO President Clair Moeller, pointing out that it could take some time for the RTOs to agree on cost allocation for JTIQ projects. MISO has already filed for FERC approval of a postage stamp allocation for its long-range projects.

“I want to proceed,” Krumsiek answered quickly.

Aubrey Johnson, executive director of system planning, said should the two projects proceed under MISO’s long-range planning, they would become part of its base case modeling. He said staff would then re-run its analyses to update adjusted production cost savings estimates for the remaining JTIQ projects.

The grid operator plans to seek board approval of the JTIQ projects early next year.

The RTO also said it envisions working with SPP to make a joint filing of the JTIQ projects’ proposed cost-allocation methodology at FERC by the end of the year.

Johnson said the RTOs’ staff are under pressure to agree on a cost-allocation process, but he said both grid operators have found value in working together.

“We’ve got a relationship out of it,” he said. “And I think we’re better off for it.”