The Bureau of Ocean Energy Management last week approved the Empire Wind project for construction, making it the sixth commercial-scale offshore wind farm to receive approval from the federal government.
The Department of the Interior said the joint venture between Equinor and BP supports the Biden administration’s aim to deploy 30 GW of OSW by 2030 and would assist New York and New Jersey in achieving their respective targets of developing 9,000 MW and 7,500 MW of OSW energy by 2035.
The project consists of two farms, the 816-MW Empire Wind 1 and the 1,260-MW Empire Wind 2, about 12 nautical miles south of Long Island and about 16.9 nautical miles east of Long Branch, N.J., respectively. EW1 is anticipated to be operational by 2027 and EW2 a year later, according to the New York State Energy Research and Development Authority.
BOEM’s Record of Decision documents environmental mitigation strategies, including compensating fishers impacted by construction in the lease area.
The approval is a positive development for an industry beset by problems recently, including regulatory setbacks, local opposition and financial constraints stemming from rising inflation that has led to project cancellations.
Danish company Ørsted canceled its two New Jersey OSW projects, Ocean Wind 1 and 2 this month after it said surging interest rates and supply chain disruptions made them unfeasible. (See Ørsted Cancels Ocean Wind, Suspends Skipjack.) A week later, Eversource Energy cited inflation as the reason for divesting its stake in the Revolution, South Fork and Sunrise projects. (See Eversource Closer to Exiting OSW Venture with Ørsted.)
Empire itself appeared to be in jeopardy after the New York Public Service Commission last month denied a request to amend power purchase agreements because of inflation pressures. (See NY Rejects Inflation Adjustment for Renewable Projects.)
New York on Nov. 30 will launch a new OSW solicitation open to all, including those with existing contracts, allowing developers to re-propose their projects at higher prices and offering an option to withdraw from previous agreements.
“A New York parade of positive developments has lifted the industry over the past month,” Oceantic Network CEO Liz Burdock said. BOEM’s approval of Empire maintains “the industry’s forward momentum while still ensuring environmentally responsible development.”
Empire “will stimulate the regional economy, revitalize ports and create many new job opportunities — including new manufacturing, installation, maintenance and operations jobs,” said JC Sandberg, chief advocacy officer at the American Clean Power Association.
Clean Ocean Action, an environmental organization based in Long Island, said it was concerned about the approval, writing on Facebook that the government was “fast-tracking” OSW projects.
“Too many questions remain unanswered about the impacts of offshore wind projects, such as Empire Wind 1 and 2, to move so quickly and recklessly forward with massive ocean industrialization,” the group said. “The ocean deserves more care, especially since it’s a prime buffer for climate change impacts.”
Green municipal aggregation (GMA) programs have cut costs for consumers in Massachusetts while lowering emissions, according to a new report by the Green Energy Consumers Alliance (GECA). However, the slow rate of approvals of new municipal aggregations at the state’s Department of Public Utilities (DPU) has limited the reach of these programs, researchers said.
GMAs are a type of community choice aggregation, which enables a municipality to buy electricity in bulk for ratepayers. GMAs include higher amounts of renewable energy certificates (RECs) than are required by the state’s Renewable Portfolio Standard (RPS). The RPS requires electricity suppliers to acquire a minimum number of RECs based on the amount of electricity they supply.
The researchers at GECA — a clean energy advocacy group that supports expanding municipal aggregation programs — compared the costs of 41 GMA programs to the basic service rates offered by the state’s investor-owned utilities from August 2017 to October 2023. The GMA programs included in the study had 5-11% more Class I RECs than the state’s RPS requirement.
The study estimated the active GMAs across the state are “adding approximately 1 million megawatt hours of renewable energy to the grid above and beyond RPS requirements per year,” equal to the power demand from 150,000 to 200,000 homes, largely displacing natural gas generation.
“That’s a pretty good number, and it’s gravy all on top of the state’s renewable portfolio standard,” said Larry Chretien, a co-author of the report and the executive director of GECA.
Regarding cost savings, the report found GMA customers saved an average of 3.3 cents per kWh compared to standard utility rates, equaling $200-$237 of annual savings for a household that averages 500-600 kWh per month.
These savings largely came from the ability of municipal aggregations to time their bids for energy supply when prices are lower, compared to the fixed schedule of supply procurements required for utility basic service, the study said.
Although GMA rates typically were lower than utility basic service, they were marginally higher than municipal aggregations that did not exceed the number of RECs required by the state’s RPS, Chretien told NetZero Insider.
“For every 5% of additional RECs that you include, it adds roughly 0.2 cents per kilowatt hour,” Chretien said. He noted that the increased cost of GMAs compared to typical municipal aggregations is small relative to the savings over utility rates and that customers can choose to opt out of the GMA to get the lowest price.
While GMAs have delivered significant benefits for Massachusetts residents, the report singled out the slow pace of municipal aggregation application approvals at the state DPU as a barrier to increased implementation.
Several municipalities have been waiting in the DPU’s queue for multiple years. There are 23 aggregation plans pending before the DPU, while only one new community has received an order of approval since the start of 2022.
In August, the DPU announced a proceeding to create guidelines for the municipal aggregation approval process and proposed an “expedited review process” for aggregation plans that comply with an established template (D.P.U. 23-67). The new guidelines are aimed at streamlining the approval process while making sure ratepayers are properly informed and protected.
“Municipal aggregation is an important tool for communities to utilize clean energy, provide ratepayers with more flexibility, and help cities and towns pursue our collective clean energy and climate goals,” DPU Chair Jamie Van Nostrand told NetZero Insider in a statement. “Addressing these delays is a top priority for the DPU, and we look forward to announcing finalized guidelines that will help facilitate a timely review of applications.”
The DPU’s proposal has received pushback from municipalities and other stakeholders (including the state’s Department of Energy Resources) for limiting the flexibility available to communities.
“Quite frankly, we’re disappointed in what they proposed,” Chretien said. GECA’s study concluded it’s debatable whether “the proposed guidelines and templates would adequately support the municipal aggregation model or further impinge the model’s ability to bring economic and environmental benefits to the Commonwealth.”
In response to a large number of comments, the DPU recently scheduled a technical session Dec. 20 to discuss the proposal with stakeholders.
Meanwhile, GECA is supporting legislation introduced in the Massachusetts House and Senate which would impose a 90-day timeline on the DPU to approve aggregation plans and amendments.
AUSTIN, Texas — The 20th Texas Energy Summit, organized by the Texas A&M University System’s Energy Systems Laboratory, again focused on the intersection of air quality and energy, with sessions on energy management, renewable energy, storage, zero-emission fleets, sustainability and resiliency during the Nov. 14-16 event.
Attendees explored policies and programs that improve the environment, advance new technologies, reduce costs and waste, and foster economic development.
Not that Texas needs to foster economic development. It already has the eighth largest economy by GDP in the world ($2.36 trillion), having passed Italy last year. The state’s economy is expected to overtake France’s within the decade, Texas Association of Business CEO Glenn Hamer said.
Texas’ lax regulatory environment and cheap labor have attracted much of that business. That, in turn, has led to a staggering population increase, putting a strain on the state’s infrastructure. Citing employment data from the state and national sources, Texas says it led all 50 states in job creation over the past 12 months, adding more than 391,000 jobs to a workforce that now numbers a record 15.16 million. The 2.9% growth rate is better than the national average of 1.9%.
“Not only do we have, depending on who you talk to, anywhere from 1,000 to 1,200 people moving to Texas every day, but nobody’s bringing water with them or more power,” said Kathleen Jackson, interim chair of the Texas Public Utility Commission.
“Customer demand is increasing very quickly. We’re seeing industrial growth, huge industrial growth,” said Warren Lasher, who opened an eponymous consulting firm when he left ERCOT two years ago.
He chose Samsung’s “monster” $17 billion semiconductor lab being built in Taylor, not far from ERCOT’s lead operations center, as an example of that growth. The 1,200-acre site is twice as large as Samsung’s flagship facility in South Korea.
“And then we’ve got the Tesla [Gigafactory in Austin]. We’ve got LNG facilities being built along the coast. We’ve got industrial growth in the Corpus and Houston ship channel, just between Austin and Dallas. There’s an enormous amount of increased industrial demand data centers. “And then if you look down the road, electric vehicles coming online, potentially hydrogen facilities, more LNG facilities.”
Lasher, who handled system planning for much of his 17 years at ERCOT, said the answer is more transmission.
Jackson chose a different direction, referring to energy efficiency as “the little black dress.”
“It goes with everything,” she said, including manufacturing, residential and small business. “So, as we move forward in Texas, I think we’re very, very well-positioned to be able to do things here that we can’t do anywhere else in the nation or maybe even the world. We’re growing, we have a competitive market that actually promotes innovation. I’m really excited about where we are today.”
An audience member asked Jackson whether Texas would accept federal funding for a rebate program that compensates Texans who retrofit their homes with energy efficient appliances. Florida, a state that, like Texas, is sometimes allergic to the federal government, recently rejected the grant and with it, access to $341 million the Inflation Reduction Act allotted to fund the program.
Jackson paused for a moment before responding to the question.
“I’m advocating for energy efficiency, for demand response and for using the resources that we have,” she said. “There are so many things involved in that particular decision as to whether you [think] that particular financing is appropriate for Texas. In my personal viewpoint, we have many resources here already that we can really pull together and we can use to move forward and make a difference.”
Texas politicians have been focused on dispatchable power from thermal resources since the disastrous and deadly February 2021 winter storm, despite the fact those very resources were unable to access fuel during the event and became part of the problem. This year’s legislative session responded with the Texas Energy Fund (TEF), a $7.2 billion low-interest loan program intended for the development of up to 10 GW of natural gas plants that voters approved Nov. 7. (See 2023 Elections Bring Billions for Texas Gas, Dem Wins in Virginia, NJ.)
“There’s a couple of different ways you can approach [dispatchable power]. One is from the demand side and the other is the consumption side,” Democratic State Sen. Nathan Johnson said. “On the demand side, we did what government often does well, sometimes poorly, and that is subsidize.
“The side that was neglected largely, but not completely, was the demand side. The fastest way to have extra power is to not use it, right? Don’t bake cookies at 5:30 when the grid is about to go down,” he said, alluding to the conservation notices that have become a part of ERCOT’s summer operations.
“We got notes and everybody got mad about it, because we’re so used to having a surplus of electricity,” Johnson said.
Asked why energy conservation isn’t one of the tools in the state’s toolkit, he said, “It’s not politically popular. But to think that the solution would be to spend money making systems more efficient or spend money to reward customers for not losing electricity just doesn’t have the same political punch as the other.”
Johnson did manage to add $1B to the TEF bill to set up microgrids at critical facilities, such as hospitals and fire states.
“If the grid goes down, you do not want nursing homes, water towers, water treatment facilities, law enforcement, hospitals, grocery stores, you don’t want those things to be without power,” he said. “We’ve created a plan where we’re going to subsidize the purchase by municipal entities and small private businesses that control vital systems to deploy these backup power systems that will give them power for a couple of days while we fix the grid.”
CPS Puts GRIP Grant to Good Use
CPS Energy CEO Rudy Garza celebrated his utility’s award of a $30 million grant from the U.S. Department of Energy’s Grid Resilience and Innovation Partnerships (GRIP) Program. He said he was proud CPS was the only Texas utility to receive a GRIP grant and one of the largest utility awards nationally. (See DOE Announces $3.46B for Grid Resilience, Improvement Projects.)
“Finding revenue that doesn’t have to come from our ratepayers is really, really important to us,” he said, noting the funds will be used to install batteries and solar panels at substations. Garza said CPS has chosen three substations on the east side of the city “where a lot of our low-moderate income customers are.”
“We’re thinking about underserved communities, we’re thinking about how [energy burdens] customers and how to continue to protect those folks,” Garza said. “We’re going to put this technology there so that in the event that we’re in a load-shed moment, that we’ll be able to keep those particular substations on and learn how to make our systems more resilient. I think we’re going to learn a lot from it and I think it’ll create opportunities for [DOE] going forward.”
He recalled sitting in the DOE offices with San Antonio Mayor Ron Nirenberg and CPS Board of Trustees Chair Janie Martinez Gonzalez. Garza said the trio told the department it was going to improve the substations anyway.
“Partnering with the DOE allows us to bring those costs down and make them more affordable for our customers,” he said. “I think that was a message, quite frankly, that resonated with the Department of Energy.”
One thing in Texas’ favor in addressing skyrocketing growth is ERCOT’s ability to quickly interconnect new resources. Whereas the process can take up to 10 years or more in some regions, it can take as little as five or six years in the Lone Star State.
“Unlike other markets, aside from the transmission planning challenges, the interconnection process is tremendously faster and it is also much more [transparent] about when we’re actually going to get online,” Cypress Creek Renewables’ Matthew Crosby said. “We take the risk with [generic transmission constraints] popping up in markets where we might not have anticipated other generation was going to locate, or where load was going to locate. But that’s the risk that we’re willing to take to be able to have more certainty, because that certainty is really valuable for our customers.”
David Treichler, director of strategy and technology for Oncor, said the utility had been spending about $1 billion a year hooking up new customers. Oncor now is adding between 60,000 and 70,000 new meters every year, with costs approaching $3.25 billion when 2023 is up.
“We try to get people connected as quickly as possible, but we’re also trying to identify places where we need to build new transmission that will serve the areas that [renewable developers] are looking at,” he said. “We work very collaboratively with the people who are developing generations to try to make sure that we have the lines in the right place.”
ISO-NE has provided additional information on the second phase of its Longer-Term Transmission Planning project, which is intended to facilitate transmission investments to meet the states’ policy goals.
The proposal would enable the New England States Committee on Electricity (NESCOE) to direct ISO-NE to issue a request for proposals (RFP) to address concerns identified in a longer-term transmission study (LTTS). After soliciting proposals, ISO-NE will consider stakeholder input and select a preferred solution to solve the identified issue.
Following ISO-NE’s selection of a solution, NESCOE will have 30 days to either accept the default regionalized cost allocation methodology, propose a new methodology or terminate the process.
“If a different cost allocation method is selected, the costs needed to address the reliability and/or market efficiency needs will be regionalized, while the additional costs to address the longer-term needs are subject to the alternative cost allocation methodology,” Brent Oberlin of ISO-NE said.
At the October TC meeting, ISO-NE said it’s considering assigning some projects to incumbent transmission owners, instead of going through the RFP process. However, following mixed feedback from stakeholders, ISO-NE proposes to abandon this aspect of the project.
“The ISO is concerned that further work on this concept will delay the Phase 2 effort and understands NESCOE’s interest in establishing this process without delay,” Oberlin said.
Oberlin also clarified that the LTTS process will be separate from the RTO’s public policy process, which exists to fulfill transmission needs associated with state, federal and local policy requirements.
ISO-NE will respond to feedback and introduce the initial proposed tariff redlines at the Dec. 21 TC.
The timeline for building the Nemadji Trail Energy Center (NTEC) in Wisconsin has been pushed into next year as clean energy groups continue to challenge the need for the planned gas-fired plant.
Minnesota Power, Dairyland Power Cooperative and Basin Electric Power Cooperative filed an update with the Public Service Commission of Wisconsin to report that onsite relocation work on the $700 million plant in Superior, Wis., won’t begin until April. Work was originally slated to begin in the third quarter of this year (9698-CE-100).
The utility and cooperatives now say the 625-MW NTEC won’t reach commercial operation until 2028 — not March 2027, as anticipated in the last update in July.
Dairyland said the holdup is a result of permitting, litigation and supply chain delays. In an email to RTO Insider, Dairyland spokesperson Katie Thomson said delays could drive up the cost of the project and risk grid reliability.
NTEC still needs a wetland permit from the U.S. Army Corps of Engineers and a stormwater permit from the Wisconsin Department of Natural Resources.
The slowdown comes as the Sierra Club and Clean Wisconsin continue to argue that the plant is harmful and unnecessary.
The two environmental groups this year asked the Wisconsin PSC to reopen the docket and rescind its 2020 approval of the plant. They also appealed a 2022 decision on their lawsuit alleging that the PSC failed to consider the full environmental impact of the plant (2020CV000585).
Last year, Dane County Circuit Judge Jacob Frost upheld the regulators’ approval of NTEC and said the PSC followed the law when issuing a certificate of public convenience and necessity, though he acknowledged the “massive impacts a major project of this nature holds for the state.”
In its 2020 decision, the Wisconsin PSC concluded that renewable energy combined with battery storage was “not yet capable of replacing a plant of this size.”
But the two groups argue that the planned construction of 489 MW in battery projects in Wisconsin will be complete a few years before NTEC is slated to begin running and is enough to negate the need for the plant.
They also continue to insist that the utility and cooperatives didn’t sufficiently analyze alternatives before settling on the gas plant. The groups maintain the cooperatives should instead pursue some of the $9.7 billion in federal funding available through the Inflation Reduction Act to help rural electric cooperatives transition from fossil fuels to renewable generation.
The groups say customers will be paying to recover the costs for NTEC at least into the 2050s, past the end date of most net-zero carbon pledges.
This year, Clean Wisconsin attorney Brett Korte said the PSC has a chance to reconsider the plant “to protect ratepayers and the environment by recognizing that the energy landscape has fundamentally changed since 2020.”
“This plant was always a bad investment, but it would be incredibly unwise to leave so much money on the table and stubbornly stick with fossil fuels that are going to harm communities and the environment in Wisconsin. The new federal funding really is a game changer, and Wisconsin should do everything it can to capitalize on the opportunities it presents,” Korte said.
Superior Mayor Jim Paine has changed his tune on the plant, saying it’s no longer needed. In a July letter commenting on a revised supplemental environmental assessment by the Department of Agriculture’s Rural Utilities Services, Paine said his “change of heart, mind and spirit” boils down to Dairyland’s acquisition of the 503-MW RockGen Energy Center gas plant in 2021, the ramp-up of renewable energy and energy storage, and a belief that the NTEC site is ill-suited for industrial development.
Construction will require the developers to fill in about 20 acres of wetlands on the banks of the Nemadji River. It would also be located near indigenous mass burial grounds.
Nemadji Trail Energy Center project map | Minnesota Power, Dairyland Power Cooperative and Basin Electric Power Cooperative
The Sierra Club said NTEC would be located “at the top of a steep slope with a historically high risk of erosion, potentially causing stormwater runoff.” The group pointed out that the utilities estimate they will have to pump almost three million gallons of water daily to operate the plant, close to the total daily water usage of the City of Superior itself.
Four of the Superior City Council’s 10 members — Nicholas Ledin, Jenny Van Sickle, Garner Moffat and Ruth Ludwig — also submitted letters of opposition. The council passed a resolution in favor of the plant in 2019.
Dairyland Says Plant is Crucial
Dairyland insists the plant is necessary to fill lulls in renewable energy output, delivering a bridge to a zero-carbon future. It also said the plant could be retrofitted to operate on up to 30% hydrogen.
“Today, there are not commercially available, utility-scale long-term battery storage technologies on the market to meet current and anticipated energy requirements,” Thomson said. “Currently, battery storage simply does not have the ability to replace the 24/7 power generated by power plants. A battery supplies energy measured in hours between charges, whereas a power plant supplies reliable energy for days, weeks or even months when wind and solar are unable to meet the demand for electricity.”
However, Thomson added that Dairyland is “enthusiastic” about batteries and other forms of energy storage and noted the co-op is exploring pumped hydro storage in abandoned mines and was recently awarded a battery storage grant from the Department of Energy.
She said NTEC’s ramping capability will help support Dairyland’s planned portfolio of 12 new wind and solar projects totaling 1.7 GW that could be funded under the IRA’s Empowering Rural America program, the same $9.7 billion program the Sierra Club and Clean Wisconsin urged the cooperatives to pursue.
Thomson said NTEC will dependably supply power at “60% less carbon, 100% less mercury and 97% less other emissions than coal.”
Clean Wisconsin has said rather than reducing emissions, the plant will annually release 3 million tons of carbon pollution into the environment.
The plant would operate as a merchant generator selling power in MISO markets. The RTO last year commented in support of the plant to the Rural Utilities Service, saying it would welcome new gas-fired capacity to bolster resource adequacy in its footprint. (See MISO Executives Spotlight Fleet Evolution Planning, Risks.)
Community groups are hailing the Kentucky Public Service Commission’s decision this month to reject a proposed gas plant from Louisville Gas & Electric and Kentucky Utilities (LG&E-KU) while greenlighting multiple planned solar installations and coal plant retirements.
The Kentucky PSC’s order authorized LG&E-KU to build only one of two 640-MW natural gas plants that it proposed in its $2.1 billion integrated resource plan and allowed the retirements of the coal-fired Mill Creek Units 1 and 2 and three smaller gas-fired units (2022-00402).
The coal retirements total about 600 MW, while the gas unit retirements will subtract about 47 MW from LG&E-KU’s portfolio. They will take place from 2024 to 2027.
The commission also denied approval of the companies’ requested retirement of KU’s coal-fired Ghent Unit 2 and Brown Unit 3, totaling almost 900 MW. It said the retirements should be deferred until it’s clearer what new environmental regulations will be enforced.
The new gas plant will be located at LG&E’s Mill Creek station. The PSC disallowed LG&E-KU’s proposal for a second new natural gas plant at KU’s E.W. Brown station.
The PSC also allowed all six of LG&E-KU’s proposed solar facilities at a combined 877 MW, a 125-MW battery storage plant and the utilities’ 2024-2030 demand-side management plan that includes more than a dozen new energy efficiency programs.
The storage project will be Kentucky’s largest utility-scale battery. The commission said the solar facilities will offer “significant savings” to customers and noted the critical role battery storage can play in the resource transition.
Intervenors in the case — Mountain Association, Metropolitan Housing Coalition, Kentucky Solar Energy Society and Kentuckians for the Commonwealth — say that the PSC’s ruling is a landmark decision that advances clean energy in a state whose legislature earlier this year enacted a law requiring the commission to review planned fossil-fueled power plant retirements using a presumption that they should remain in operation (SB4).
In a joint press release, the groups said they were disappointed with the approval of a new natural gas plant and the decision to keep two aging coal plants online. However, they said the order “offers major advances for clean energy in Kentucky and indicates that the PSC is weighing the risks of new and existing fossil fuel plants pose to ratepayers.”
“LGE-KU must not ignore this opportunity to ramp up efficiency programs, solar energy and battery storage to make any additional gas plants unnecessary,” they said.
“The denial of a $650 million, 40-year commitment to a risky natural gas plant is a major victory for ratepayers,” said Catherine Clement of Kentuckians for the Commonwealth. “And the closure of those old Mill Creek coal units will mean better air quality for the people of Louisville and the surrounding region.”
Josh Bills of the Mountain Association said LG&E-KU realizes that the plants are too costly to continue to operate because they require “massive investments to bring them into compliance with air and water quality regulations.” He said the Kentucky PSC’s order establishes a course for future coal plant retirements and “importantly” acknowledges that energy efficiency programs and distributed resources can reduce demand enough that the output from the Ghent and Brown units might not need to be replaced with an expensive new gas plant.
Chris Woolery, representing the Mountain Association, agreed that successful energy efficiency programs could shave enough demand to offset the need for a major power plant.
Tony Curtis of the Metropolitan Housing Coalition said his organization is looking forward to assisting LG&E-KU on implementing the new energy efficiency offerings, especially for those who “struggle to pay their bills each month and can really benefit from home energy improvements.”
After the PSC’s order, PPL — the parent of LG&E-KU — said in a U.S. Securities and Exchange Commission filing that the utilities’ planned capital investments in new and existing facilities in Kentucky are “materially consistent” with the utilities’ original $2.1 billion plan.
John Crockett, president of LG&E-KU, said the utilities are “pleased” that the PSC approved many aspects of the original plan.
LA QUINTA, Calif. — California PUC President Alice Reynolds set the tone for the theme of climate resilience at the National Association of Regulatory Utility Commissioners Annual Meeting with a story about the history of the Salton Sea.
In her opening remarks at the conference Nov. 13, Reynolds explained how the sea — a highly saline body of water in the Southern California desert about an hour from the conference location — was created by an extreme weather event in 1905 when Colorado River floodwater breached an irrigation canal and spilled into the Salton Sink.
The landlocked body of water is now considered a key domestic mining location of a critical mineral needed to manufacture batteries for the energy transition: lithium.
“There’s so much history related to the Salton Sea before this event and after, but I wanted to raise it as an early lesson in resiliency and also an event that created opportunity,” Reynolds said. The Salton “provides the potential for sustainable extraction of lithium and for geothermal generation, both of which are needed for our clean energy transition.” (See ‘Lithium Valley’ Could Accelerate California EV Sector Growth.)
In the future, Reynolds said, inevitable climate-caused extreme weather events could present an opportunity to develop new technologies — like using lithium from the Salton Sea to power electric vehicles — to better adapt to climate change.
Funding for Climate Mitigation
On the heels of Reynolds’ speech, many discussions at the conference centered on the crucial role the energy sector will play in building the infrastructure needed for climate mitigation and resilience.
David Crane, undersecretary of infrastructure at the Department of Energy, discussed DOE’s role in addressing climate change.
“We want to transition the country to a clean energy economy while being true to the historic mission of the electricity industry, in particular to deliver safe, affordable and reliable power,” Crane said during a panel.
The panel’s moderator, Commissioner Ann Rendahl of the Washington Utilities and Transportation Commission, asked what DOE planned to do with the historic funding it received from the country’s Infrastructure Investment and Jobs Act and the Inflation Reduction Act. According to Crane, the agency was given $96 billion for financial assistance equity grants, and its Loan Program Office has around $400 billion in loan capacity.
The agency plans to announce an additional $20 billion in funding in the next few months, with the hopes of allocating it by the end of 2024, Crane said.
Tools for Resilience
Industry officials and regulators emphasized the need to look beyond mitigation toward creating a system of resilience that can support the country in the event of a climate disaster.
“Today, I think resilience is coming much more into the forefront,” said Katie Jereza, vice president of corporate affairs at the Electric Power Research Institute (EPRI). “Because we’re going to be more reliant on electricity, resilience is going to be of much more value in the future.”
Commissioner Tammy Cordova of the Nevada Public Utilities Commission echoed those concerns, saying that for utilities to deliver the level of reliability demanded, they need to be resilient in the face of climate change.
During a panel moderated by Cordova, Curt Stokes, senior attorney with the Environmental Defense Fund, highlighted the need to understand risk.
“What we advocate for is, as the electrical utility is planning and understanding how it serves its customers and as we work with individual communities and parts of the communities, understand what risks they’re facing and the role of the electrical utility grid in making sure that those communities are resilient,” Stokes said.
Morgan Scott, director of Climate READi at EPRI, discussed a tool designed to increase the power sector’s collective approach to managing climate risk.
The first is understanding the type of data that exists to characterize climate hazards to a power station.
The second outlines how to use the data to assess risk to assets and inform design criteria for new assets that will be needed. As part of the effort, EPRI is building a climate asset matrix that lists every asset on the power system and each weather variable it could be exposed to.
The third component brings this information to a system level, looking at what assets need to be prioritized in the event of an extreme weather event.
Forty-two electric sector companies and over 80 stakeholder organizations in the U.S., Canada, the U.K. and France have joined Climate READi.
Andy Bochman, senior grid strategist with Idaho National Laboratory, spoke about the Climate Resilience Maturity Model, which considers the well-being of different infrastructure assets and ranks cities in terms of vulnerability and readiness. The model, which is promoted by the Environmental Defense Fund, can be used by energy regulators to hold utilities accountable to their obligation to provide safe, reliable and affordable service by managing climate related risks and building resilient systems.
Energy officials asserted that the tools they’ve developed are important steps in the right direction, but that more needs to be done.
“We spend a lot of time talking about mitigation, and we should, but with emissions rising every year, we’re not really getting much performance bang for all the noise and expenditure buck,” Bochman said. “We are building wind, solar and storage, EVs are coming — I have one, I have solar panels — but that’s not changing the amount of emissions that are going out globally appreciably, so we need much more attention on resilience and adaptation than it’s getting right now.”
New Jersey Gov. Phil Murphy (D) said Nov. 21 that the state has adopted the Advanced Clean Cars II rule effective Dec. 18, sparking relief from supporters who pushed for it to be ready for the 2027 model year and disquiet from business groups who say it will make vehicles more expensive.
Murphy said the move to adopt the rule, which was first crafted and adopted by the California Air Resources Board, would put the state on a “road toward better air quality and cleaner choices for new car buyers while combating the worsening climate crisis.”
A prepublication copy of the rule will be posted in early December to the Department of Environmental Protection’s Rules and Regulations webpage.
New Jersey is the ninth state to adopt the rule, which will require all new light-duty vehicles sold in the state to be zero emission by 2035. Combined, the state adoptions mean that by the end of 2035, 28.5% of the sales of new light vehicles in the U.S. would have to be zero-emission vehicles (ZEVs), according to a tracking list put together by the Sierra Club.
The rule requires manufacturers to make ZEVs a steadily increasing portion of their car sales, starting with 35% for model year 2026, increasing to 68% in 2030 and reaching 100% in 2035. It defines ZEVs as battery-electric, hydrogen fuel cell or plug-in hybrid. The rule also includes increasingly stringent low-emission vehicle standards aimed at reducing tailpipe emissions of gasoline-powered cars and heavier passenger trucks.
Urban Benefits
Murphy announced his decision in a release containing quotes supporting the move from several environmental and pro-EV groups and the mayors of four urban communities in the state — Newark, Plainfield, Passaic and Trenton — who said rule would help combat emissions from the heavy traffic in the state.
“As the largest automobile transportation hub and energy generation center in the state, Newark has much to gain through this rule,” Mayor Ras Baraka said. The rule will mean “greater investment into ZEVs, more jobs for city residents and more availability of these vehicles for motorists.”
Transportation is the largest source of emissions in the state, generating about 37% of the emissions, and supporters of ACC II contend that the state needs tough requirements to accelerate the uptake of EVs and dramatically curb emissions. They say that more moderate programs such as offering incentives won’t stimulate enough purchases and don’t provide the certainty of the state’s commitment that the ACC II rule does.
“By accelerating the growth of the EV market, ACC II will spur continued investment and innovation in the transition to a clean energy transportation sector,” said Richard Lawton, executive director of the NJ Sustainable Business Council.
Price Hikes
The New Jersey Business and Industry Association (NJBIA), which led a campaign against the rule, called it an “unworkable mandate,” adopted over the opposition of more than 100 business and labor groups and thousands of people. (See NJ Businesses Demand Halt to EV Sales Promotion Rules.)
Ray Cantor, a lobbyist for the NJBIA, said the state does not have the charging infrastructure to support a sudden, massive uptake of EVs. He added that because EVs are still much more expensive than gas vehicles, the sudden surge in sales requirements would result in consumers looking for lower-priced used vehicles, pushing the price up.
“At the end of the day, the DEP did not heed any of those concerns, nor did it offer any solutions to them,” he said. “This ban of the sale of new gas-powered cars, in such an expedited time, does not take costs or feasibility into account. It does not take the lack of local and highway infrastructure into account. It does not take grid capacity into account. It ignores consumer choice. It doesn’t take New Jersey residents into account, especially low- and moderate-income families. And it doesn’t take the lack of actual environmental benefit into account.”
Incentive Program Closure
State officials say New Jersey has more than 123,000 electric vehicles on the road, representing 12% of new vehicle sales. Since just last December, sales of EVs have surged 50%, according to the state.
But that is a tiny portion of the estimated 6 million light-duty vehicles registered in the state.
The New Jersey Coalition of Automotive Retailers says that to increase EV sales volumes, the sector needs to bring the vehicle price down and make more charging stations available, which would help consumers overcome range anxiety.
To combat those concerns, state agencies have created a variety of programs to provide vehicle subsidies that bring the cost of an EV closer to that of a gas vehicle and help pay for the installation of charging infrastructure. The Board of Public Utilities said Nov. 20 that it is closing the fourth year of its Charge Up New Jersey program because the funds had been exhausted. The program had awarded $30 million since it opened on July 12, the BPU said.
The Charge Up New Jersey program, which offers subsidies of up to $4,000 for the purchase of an EV, has awarded $120 million over four years and funded the purchase of 35,000 vehicles.
The agency said it expects the fifth year of the program to open in July 2024.
KENT, Wash. — Opponents of Washington’s fledgling cap-and-trade program, which the state refers to as cap-and-invest, have delivered 418,399 signatures to the secretary of state’s office in a push to repeal the program.
The petition needs 324,516 valid signatures by Dec. 29 to advance to the Legislature. If lawmakers take no action on the petition, it will go to a November 2024 referendum.
“We’re going to give the voters a chance to vote it down,” Brian Heywood, a King County hedge fund manager leading the effort, said at a Nov. 21 press conference in Kent in front of a U-Haul trailer containing boxes of signatures. Heywood is providing more than 80% of the petition drive’s budget, according to the website of Let’s Go Washington, an organization Heywood has bankrolled to back the repeal effort and other initiatives.
Administered by the state’s Department of Ecology, Washington’s cap-and-invest program went into effect at the start of this year, requiring carbon-emitting entities to participate in auctions to bid on allowances that permit them to pollute. Opponents blame the program for the state’s high gasoline prices, saying oil companies are passing on their compliance costs at the gas pump. (See Cap-and-trade Driving up Washington Gasoline Prices, Critics Say.)
Smokestack emissions from Washington’s five oil refineries are exempt from the program, while the gasoline they produce is not.
‘Dead on Arrival’
The petition “will be dead on arrival,” state Sen. Joe Nguyen (D), chairman of the Senate’s Environment, Energy and Technology Committee, told NetZero Insider. The initiative will have to go through his committee before getting a wider hearing in the Senate.
Heywood said public ballot measures supporting a cap-and-trade program were defeated before the Legislature passed the cap-and-invest program in 2021. “The Legislature said ‘F U’ to the voters and [it] is saying ‘F U’ again,” Heywood said in response to the fact that a Democratic-controlled Legislature would be hostile to the petition.
Nguyen said the petitioners are unaware of the cap-and-invest program’s benefits. Also, he said, the 2021 law is the result of compromises reached among environmentalists, advocates for disadvantaged communities and the business community, including some in the oil industry. Nguyen also contended the petition’s backers are climate change deniers.
“Of course, climate change exists. Of course, humans cause climate change. I’m just not a member of the mother-breathing Church of Gaia,” Heywood said. He later added: “This money is going to the political friends and allies of the governor. To be honest, this is a money grab.”
In an email to NetZero Insider, Gov. Jay Inslee spokesperson Mike Faulk said: “As for the false claim about how auction revenue is spent, if he can’t back it up, then it’s not even worth printing. We’ve been more than happy to share with folks where the funds are going.”
The cap-and-invest program is on track to raise almost $2 billion in 2023. So far, $300 million has been appropriated to 188 projects. These include intermingling solar projects with farmlands, adding climate change to urban growth planning, climate change projects for the state’s tribes, capturing methane from landfills, installing solar panels on nonpublic buildings, dealing with child asthma in the SeaTac area, building infrastructure for electric vehicles, building a hybrid fuel/electric ferry, and overhauling ferry docks and terminals to handle electric ferries.
Faulk said 43% of cap-and-invest revenue is earmarked for poor and overburdened communities, with an additional 7% going to the state’s tribes.
The cap-and-invest petition is part of a Let’s Go Washington package of six petitions. Heywood said the organization is close to collecting 400,000 signatures for them. A standard rule of thumb in collecting initiative signatures is to gather far more than needed because the secretary of state’s office will throw some out because they are not valid.
Other petitions include calling for repealing a new capital gains tax on people earning at least $250,000 in capital gains. Another wants to forbid any state or local income tax in Washington, which has neither. No state income tax has been proposed for a long time.
BALTIMORE, Md. ― Some solar companies in the Mid-Atlantic have stopped looking for sites for utility-scale installations in the region due to the current backlog of renewable energy projects in PJM’s interconnection queue, according to Steve Swern, senior director for generator interconnection at Sol Systems, a Washington, D.C.-based developer.
The RTO is not expected to clear that backlog and start reviewing new applications possibly until 2026, Swern said Nov. 16 during a panel discussion on interconnection at the Solar Focus conference hosted by the Chesapeake Solar and Storage Association (CHESSA). “So how do I tell a corporate off-taker that, sure, we can site a project for you to deliver renewable energy in PJM. Is a [commercial operation date] by 2030 OK?”
A regional trade association, CHESSA’s members primarily are solar and storage developers in D.C., Maryland and Virginia — all in PJM’s 13-state service territory. When looking to site solar projects in the PJM footprint, Swern said, multiple strategies are considered, including bypassing the queue by approaching utilities to connect to their distribution grids.
The company intends to move ahead with projects it already has in the PJM queue but “is approaching utilities — transmission utilities, distribution utilities — to really push the envelope of how big can we build, what clients can we connect to, without involving the scrutiny, the oversight and the jurisdiction from the RTO,” Swern said.
Getting more solar on the grid is a critical issue in D.C., Maryland and Virginia, each of which has set ambitious targets for running their respective electric systems on 100% clean power ― by 2032 in D.C., 2035 in Maryland and 2050 for Virginia.
But reaching those goals likely will mean being able to import clean power from PJM. The nation’s capital, for example, has minimal generation within its 68 square miles, seven of which are water. PJM has warned Maryland of potential rolling blackouts if one of the state’s remaining coal plants, the 1,238-MW Brandon Shores generating station, is taken offline in 2025, as currently planned.
According to figures from PJM, its power mix is still more than 60% fossil fuels. On the carbon-free side, in 2022, nuclear accounted for about one-third of the RTO’s generation fuel mix, but wind and solar together stood at 4.9%. At the same time, solar, wind and storage make up almost all of the over 300 GW of projects in PJM’s interconnection queue, as reported by the Lawrence Berkeley Laboratory.
The grid operator is working on a Regional Transmission Expansion Plan aimed at adding the capacity needed for new renewables or other power that will replace retiring coal plants.
Like Swern, James Mirabile, the principal engineer for interconnection at Baltimore Gas and Electric (BGE), said getting renewables interconnected on distribution systems is an easier lift. In 2022, BGE had 91 projects totaling 139 MW in its interconnection queue, 35 MW of which went online that year. This year, to date, the queue has 87 projects totaling 165 MW and has interconnected 27 GW, he said.
For BGE and other Maryland utilities, the process for getting those projects online is “very highly regulated,” Mirabile said, and the state’s Public Service Commission has set up an interconnection working group charged with updating the rules.
The most recent update will go into effect Jan. 1, 2024, when all renewable projects will be required to use smart inverters with settings “that include a volt-var curve instead of a fixed power factor,” said Mirabile, who is a member of the working group. Such updated settings provide a flexible way for inverters to react dynamically to variations in voltage on the system, which can occur as more renewables come online, Mirabile said in an email to RTO Insider.
BGE and four other utilities have submitted the smart inverter settings they will require for projects to the PSC, which approved the proposed settings on Nov. 21.
The working group also has sent recommendations to the commission to reform cost allocation for distribution system upgrades, Mirabile said. Traditionally, when a project requires a distribution system upgrade for interconnection, the project developer carries the full cost.
The working group is proposing a model where the project developer is allocated part of the cost, with the remainder “spread across future interconnecting customers,” he said. If approved, the proposed update would be “a major change in the way we price jobs.”
The Aggregation Work-around
The backed-up interconnection queues at PJM and other RTOs and ISOs across the country are rooted in the wave of renewable projects seeking interconnection on systems that were “set up in such a way to not handle a large influx,” Swern said.
Approved in July, FERC’s Order 2023 (RM22-14) is aimed at pushing grid operators toward some basic structural changes, such as doing cluster studies of projects seeking interconnection rather than on a case-by-case basis and attempting to weed out speculative projects by upping financial requirements for developers. (See FERC Updates Interconnection Queue Process with Order 2023.)
But implementation of the order is on hold as FERC considers multiple requests for a rehearing on the rule.
FERC previously approved reforms PJM had proposed to its interconnection process, similar to Order 2023 — cluster studies and stricter financial requirements — which the RTO rolled out in July. According to Susan Buehler, PJM’s chief communications officer, 40,000 MW of projects have been approved but not yet built.
Bahaa Seireg, senior director of energy storage at the American Clean Power (ACP) Association, said utility-scale energy storage projects are caught in the same slow interconnection queues. While an increasing number of states, including Maryland, have set targets for adding energy storage projects to the grid, Seireg said, it can take five years to work through transmission-level interconnection processes at an RTO or ISO.
In May, Gov. Wes Moore (D) signed a law setting a goal for the state to have 3,000 MW of storage online by the end of 2033.
Seireg sees a possible workaround for the interconnection problem in aggregation that breaks down the traditional divide between distribution and transmission. “Now, you can actually interconnect [solar and storage] to the distribution grid and aggregate resources … add them to distribution substations, aggregate them and bid them into the wholesale market,” he said.
“That allows for some temporary reprieve from PJM,” he said.
Sol Systems sees another “prime opportunity” for getting projects interconnected quickly at municipal utilities and electric cooperatives. These smaller, nonprofit utilities often are unregulated and “have a lot of flexibility in the decisions they make, in the projects they move forward and how costs are allocated,” Swern said.
He also pointed to grid-enhancing technologies — such as advanced conductors and dynamic line ratings — as another option for maximizing the capacity of existing lines. “These are very low-cost solutions that help give grid operators higher granularity to thermal capacity of wires in a very specific location, [which] allows projects to operate … at full bore without being curtailed,” he said.
The Information Gap
But the panelists all see major gaps in the information developers need to site and design projects that can get interconnected as quickly as possible.
“Where we see a major stumbling block for interconnection is the quality of data, the existence of the data and the ability to use that to make informed decisions,” Swern said. In some cases, just figuring out where transformers are located means sending out trucks to map an area, he said.
Some utilities now have online “hosting capacity” maps, showing what lines in their service territories have excess capacity, but Swern said, not all maps are created equal. “Some of them just give you a color-coded map; some of them actually allow you to click on the feeder itself and see what’s the ability to connect [distributed energy resources]; some you can get a load profile … for the past two years,” he said.
At BGE, the best way for a developer to check out the available capacity of distribution lines at a site is to contact Mirabile directly, and he will do a pre-application analysis, he said. It’s reliable but not self-service, he admitted.
Swern sees a more fundamental obstacle to interconnection in the misalignment of “spheres of control … or jurisdiction.” Federal, state, county and local governments all “have specific targets, mandates, goals for deploying renewables or retiring fossil assets … and there isn’t a good way to align all of those different things.”
