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October 31, 2024

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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.”

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Shell CEO: Sector-based Mandates Critical for Global Energy Transition

Government mandates are the best policy lever for supporting the world’s energy companies in what Shell CEO Ben van Beurden sees as an uphill climb to net-zero emissions.

“We cannot outperform 100 years of innovation in petroleum-based products in a few years’ time,” van Beurden said Wednesday at the 2022 International Energy Agency Ministerial in Paris.

Shell’s (NYSE:SHEL) biggest challenge in reaching net zero is addressing emissions at the point of energy use, and the only way to do that is “by offering different products,” he said. “If we are going to change the nature of the products that we sell, we need to have different policies encouraging the use of those products.”

The fastest pathway to product innovation and affordability is to mandate product use within target sectors, according to van Beurden.

“Sustainable aviation fuels are three times as expensive as petroleum-based aviation fuels, so we cannot make them economically relevant for airlines,” he said. “If you have a mandate to put 5% in the mix, then it doesn’t really matter what it costs, it just needs to be delivered.”

Customers are most often focused on the lowest cost of energy, but as more sustainable fuels are delivered, he said, the cost of supply will decrease.

Every sector of the economy “will have a slightly different recipe to reduce their carbon intensity and to figure out the best set of policies to drive that decarbonization,” van Beurden said.

Kevin Gallagher, CEO of Australian oil and gas producer Santos, agreed with van Beurden during the IEA panel discussion on international cooperation, saying that energy companies can produce hydrogen, for example, but market demand must exist for it.

There is a “thirst and demand for fossil fuels” that is not decreasing, Gallagher said.

Even more critical, he said, is that energy companies have access to the significant capital investments needed for decarbonization. Government policies, such as carbon credits and tax incentives, can create a stable energy environment that encourages investment.

Australia’s focus on carbon credits, for example, has allowed Santos to enter the design phase of what Gallagher says could be one of the largest carbon capture and storage (CCS) projects in the world.

“We worked very hard with government over the last few years to get to the point where [CCS] projects can qualify to generate Australian carbon credit units,” he said. But international cooperation with Timor-Leste, he added, has been equally important in moving the project in the Timor Sea forward.

“It’s critically important for governments … to operationalize Article 6.2 of the Paris agreement so that we can get more of these investments,” he said. The article sets out the foundation for international cooperation on decarbonization policies, such as emissions trading schemes, and allows for the transfer of carbon credits between countries.

International Stage

Energy Secretary Jennifer Granholm, serving as Ministerial chair, highlighted the panel session as a platform for countries to share ideas.

“My hope is that we can … illuminate ideas and spread the word on practical, actionable efforts that any one of us could take on to learn from one another,” she said.

Yaroslav Demchenkov (2022 International Energy Agency Ministerial) FI.jpgYaroslav Demchenkov, Deputy Minister of Energy for European Integration for Ukraine, in Paris Wednesday | 2022 International Energy Agency

The panel paused to welcome Yaroslav Demchenkov, Ukrainian deputy minister of energy for European integration, who asked countries in attendance to “work together to integrate energy markets” and reduce dependence on Russian energy resources.

Russia’s war on Ukraine, he said, should be a catalyst to stop using Russian energy resources “as soon as possible, wherever possible.”

He also asked governments to restrict energy resources that are not easy to replace, substitute pipeline gas with other sources, such as hydrogen, and invest in balancing capacities, including storage.

“Commercialization of other types of green technology in the long run will guarantee energy independence and effectively contribute to the goal of the Paris agreement,” he said.

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NEPOOL Transmission Committee Briefs: March 23, 2022

DER Interconnection Process

ISO-NE is proposing a change to its rules that would always send distributed energy resources through state interconnection processes.

In a presentation to the NEPOOL Transmission Committee on Wednesday, Al McBride, ISO-NE’s director of transmission strategy and services, said doing so would get rid of a complex decision on whether new DER projects should be under the jurisdiction of state interconnection rules or FERC’s.

McBride said that tracking the jurisdiction status of thousands of DERs in the region is “extremely challenging and time-consuming.” And some developers, he said, are being forced to complete both state and RTO processes for no reliability purpose.

Under the proposed change, all distribution-connected generation would go through state interconnection processes, although it would still be reviewed by the RTO because of the rules laid out in section I.3.9 of the tariff.

The RTO is planning to present redlines at next month’s TC meeting.

Update on Ambient-adjusted Ratings Compliance

ISO-NE is also working on a compliance filing for FERC Order 881, which requires the incorporation of ambient-adjusted transmission line ratings. Such ratings take air temperature into account when determining how much electricity can move through the lines.

Graham Jesmer, ISO-NE regulatory counsel, told the committee that the RTO is moving to have the filing ready by a July 12 deadline.

The order requires RTOs and ISOs to “allow transmission owners to electronically update transmission line ratings at least hourly.”

The compliance filing will consist of a new attachment to the tariff, which the RTO will be writing over the next few weeks.

After it finalizes the filing, ISO-NE will have to move to implementation, which has a deadline of July 2025, Jesmer said. That will involve changes to the RTO’s governing documents and systems and software, as well as conversations with transmission owners and providers, which Jesmer said are already underway.

676-J Compliance

The committee also voted to recommend that the Participants Committee approve the RTO’s revisions to Schedule 18 and Schedule 24 of the tariff. The revisions would address FERC’s directive in Order 676-J to incorporate by reference cybersecurity standards and Parallel Flow Visualization standards from the latest version of the Standards for Business Practices and Communication Protocols for Public Utilities adopted by the Wholesale Electric Quadrant of the North American Energy Standards Board.

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ReliabilityFirst Plugs SBOMs as Essential Cyber Tools

At ReliabilityFirst’s monthly Technical Talk with RF on Monday, cybersecurity consultant Tom Alrich said a software bill of materials (SBOM) can be a useful tool for utilities to meet their obligations under NERC’s reliability standards, particularly CIP-013-2 (Cybersecurity — supply chain risk management).

Introducing the topic, Alrich noted that the SBOM idea has been gaining traction after being included in President Biden’s Executive Order 14028 last May. (See Biden Directs Federal Cybersecurity Overhaul.) But while the concept has gained some recognition in the public sphere, Alrich said many outside the cybersecurity industry don’t fully understand what it is, joking that he was “sure your children have all asked you that question at one time or another.”

“You might tell them that if they had a software bill of materials for each of the video games that they run, they might know which games contain Log4j,” Alrich said, referring to the vulnerability in an Apache open-source software library that was discovered last year and is thought to impact millions of devices and applications worldwide. (See DHS Launches Cyber Review Board.) “If a game does contain Log4j, they might not want to use it until the developer provides a patch.”

Hacked Software Can Spread Quickly

SBOMs are intended to address potential vulnerabilities associated with the reality of modern software development: applications increasingly are not individually coded from the ground up, but largely built from bits of code available in public or private repositories like Github. Log4j, for example, is a freely available component that programmers can insert into their code; the resulting app can log errors and normal system processes, a vital feature for software in a wide range of industries.

These components are often copied and pasted with few changes: Alrich estimated that “in some software products, more than 90% of the code is components,” and 90% of those components are open source, with most of a modern programmer’s work being to “tie components together.” This means that if an attacker manages to slip malicious code into the source, it can spread quickly to myriad platforms, similar to the 2020 hack of the SolarWinds Orion network management software (though that incident involved compromising a company’s official update channel rather than public code repositories).

An SBOM helps to mitigate this issue by providing customers a machine-readable list of software components in a particular product. Under Biden’s executive order, all software developers working for federal agencies will be required to produce SBOMs starting in August; Alrich predicted that the lists will “become a quasi-requirement for all software” as more organizations become aware of the risks of open-source components.

Providing an SBOM does not mitigate any vulnerabilities in a software product by itself, but because it is machine-readable, it can greatly speed up the hunt for compromised components. Alrich provided a diagram showing one way to use an SBOM, in which automated software checks each component against the National Vulnerability Database or other lists of potentially dangerous software.

The resulting list is then checked against a vulnerability exploitability exchange (VEX) to determine which flaws are actually exploitable. As Alrich explained, most vulnerabilities cannot actually be exploited in a finished piece of software, so this step can greatly cut down on a cybersecurity team’s time and effort.

Where the SBOM helps with CIP-013 compliance is in allowing utilities to independently “identify, assess and mitigate” supply chain risks as the standard requires. Without an SBOM, utilities must rely on their suppliers to monitor for potential risks and give them timely information; with the list a utility can do this itself.

“SBOMs are a tool; they don’t mitigate risk themselves, but they’re the indispensable tool for doing that,” Alrich said.

More Changes to Align Release Schedule

Also in Monday’s webinar, ReliabilityFirst’s manager for risk analysis and mitigation Anthony Jablonski provided an update on the status of the ERO Enterprise’s Align software platform and Secure Evidence Locker.

Align project timeline (ReliabilityFirst) Content.jpgThe remaining steps in the most recent version of the Align project timeline | ReliabilityFirst

Currently NERC and the regional entities are still rolling out Release 3 of the platform, which began in December with a staggered schedule. SERC and ReliabilityFirst began their implementation in February and March, respectively; all other entities will start their adoption in April.

Release 3 was originally planned to be the last stage in the platform’s introduction, but NERC decided to split the final release in two to reduce the complexity of the task. Jablonski said on Monday that the new Release 4, originally set to roll out in the fourth quarter, has been split again. The first part will now roll out in the second quarter, comprising audit and scheduling functionality; the second, which the organization has dubbed “Release 4.5,” will be introduced in the fourth quarter, covering inherent risk assessments and compliance oversight plans.

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National Grid Proposes 100% Fossil-free Gas System in Mass.

National Grid (NYSE:NGG) is proposing to transition its natural gas service in Massachusetts to 100% fossil-free gas by 2050 to help the state meet its decarbonization goals.

The utility filed a Net-zero Enablement Plan Friday with the Massachusetts Department of Public Utilities for the regulator’s investigation into the role of gas distribution companies in reducing greenhouse gas emissions.

Eliminating fossil fuels from National Grid’s gas supply would require pursuing delivery of renewable natural gas (RNG) and renewable hydrogen to all customer classes, the utility said in the plan. National Grid’s proposal builds on recommendations in an Energy & Environmental Economics (E3) report filed Friday in the “Future of Gas” docket (20-80) that identified eight decarbonization pathways for the state.

Each pathway achieves net-zero GHGs by 2050 compared with 1990 levels at varying costs, and they offer options ranging from ongoing use of the gas distribution network to complete network decommissioning across the state. Key components of National’s Grid net-zero proposal align with the consultant report’s Hybrid Electrification pathway, according to the plan.

A hybrid pathway balances benefits and challenges of electrification and decarbonized fuels by limiting renewable fuel use and mitigating issues related to electric infrastructure expansion, the consultant’s report said. Of the eight pathways, the hybrid approach had the least cumulative cost, $64-$92 billion. Scenarios that included high levels of electrification for buildings and 100% gas network decommissioning had the highest cumulative cost, $87-$135 billion.

While the hybrid pathway is based on 100% renewable gas for residential and commercial customers only, National Grid proposed extending that transition to industrial customers as well. The utility also would expand on the pathway through networked geothermal system deployment and deep energy efficiency measures that address building envelopes and appliances. (See National Grid Wins Approval for $15.6M Geothermal Demo.)

In a separate report filed Friday on regulatory considerations related to the eight pathways, E3 determined that a gas utility transition to renewable fuels is limited by supply and the state’s regulatory structure. Based on E3’s findings, National Grid said the state must authorize gas utilities to develop an RNG procurement program that offers competitive solicitations.

In addition, the utility called for the state to implement a Renewable Heating Fuel Standard that directs natural gas providers to procure an increasing portion of supply from clean fuels, such as RNG or hydrogen.

Eversource Energy (NYSE:ES), the second largest gas distribution utility in Massachusetts behind National Grid, made minor commitments to fossil-fuel alternatives in its decarbonization plan filed Friday. The utility submitted an operational plan covering 2023-2025 with proposed initiatives to:

  • conduct market assessments for in-state and out-of-state RNG;
  • procure RNG from a locally sourced project;
  • develop a small-scale demonstration project for RNG storage at a liquified natural gas site;
  • assess hydrogen blended into its gas network by up to 2% by volume; and
  • develop hydrogen pilots to examine re-purposing the gas network to transport hydrogen.

Eversource also wants to develop a pilot for hybrid air-source heat pump systems that link to auxiliary natural gas furnaces. The pilot would test demand response and fuel switching of customers using the hybrid heat-pumps during winter peaks. Eversource also plans to expand a networked geothermal pilot it launched last year into a comprehensive utility-scale program.

Liberty Utilities, Unitil (NYSE:UTL) and Berkshire Gas filed their net-zero plans with the DPU Friday, each identifying some level of commitment to decarbonized gas supply.

Berkshire plans to offer biomethane from landfill gases in the near-term, while hydrogen and RNG, the utility said, could be long-term resources in some sectors, such as buildings and heavy-duty transportation. Liberty said it plans to offer increasing proportions of RNG to customers over time, and Unitil expects to establish targets for biomethane that would be capped at a certain cost threshold.

In a joint filing, the state’s five gas utilities asked the DPU to approve their net-zero plans along with a proposal to update them on a three-year cycle aligned with energy efficiency program planning. 

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SEC Seeks Standard Disclosures for Climate-related Business Risks

The Securities and Exchange Commission voted Monday 3-1 in favor of a proposed rule that would expand and standardize how public companies disclose business risks related to the climate and greenhouse gas emissions.

“Investors representing literally tens of trillions of dollars support climate-related disclosures because they recognize that climate risks can pose significant financial risks to companies, and investors need reliable information about climate risks to make informed investment decisions,” SEC Chair Gary Gensler said in a statement.

Under the proposal, SEC registrants would have to provide information in filings about, among other things, oversight of climate risks, impact of those risks on business and financial statements, and any climate-related targets or goals. Climate-related risks, as defined in the proposal, are the negative effects of climate events on business operations or activities within the company’s value chain.

In addition, the SEC is seeking GHG emissions data related to direct business operations and energy use, and in some cases, value-chain operations. Standardizing how and when companies provide emissions data would remove uncertainty associated with voluntary reporting, according to the proposed rule.

GHG disclosures expressed as metric tons of carbon dioxide-equivalent per unit of revenue, for example, would give investors a basis for comparison across industries and companies, the commission said.

Jack Lienke, regulatory policy director at the Institute for Policy Integrity, supported the SEC’s proposed rule in a statement Monday, saying the commission “no longer has the luxury of ignoring climate change.” The SEC, he said, must protect investors by demanding the same transparency on climate risk as other financial risks.

The SEC based the proposed rule on the 2017 disclosure recommendations of the Task Force on Climate-related Financial Disclosures created in 2015 under the direction of the Group of 20 finance ministers.

Commissioner Hester Peirce, who was appointed by President Donald Trump to fill a Republican seat, voted against the proposal, saying that it “will undermine the existing regulatory framework that for many decades has undergirded consistent, comparable and reliable company disclosures.”

The existing filing rules, Peirce said, already require companies to disclose risks, such as those related to climate. In 2010, the commission issued guidance on how its rules at the time could require disclosure of climate issues for a business. Since then, investor interest has grown for more specific climate-related details in company filings, the SEC said in its proposal.

“It is appropriate for us to consider such investor demand in exercising our authority and responsibility to design an effective and efficient disclosure regime under the federal securities laws,” the commission said.

Peirce, however, said the proposal “exceeds the commission’s statutory limits.”

“Many calls for enhanced climate disclosure are motivated not by an interest in financial returns … but by deep concerns about the climate,” she said. The commission, she added, has a responsibility to limit disclosure requirements so they do not “bury the shareholders in an avalanche of trivial information.”

Compliance with the new rules would follow a phased approach, based on filing class. Assuming an effective date in December, filers would have to be in full compliance with everything but value-chain emissions disclosures for fiscal year 2025. Full compliance with value-chain emissions data reporting would begin in fiscal year 2026.

Sen. Edward Markey (D-Mass.) said the proposed rule is an “important step,” but he called for more aggressive action from the commission.

“I urge the SEC to expand the proposal to quickly require [value-chain] emission data, and to incorporate environmental justice considerations — such as assessment of the specific risks to [Black and Brown] communities — into the reporting requirements,” he said in a statement Monday.