CARMEL, Ind. — MISO this week said it will likely have little firm generating capacity to spare in managing typical summertime peaks this year.
John Harmon, director of market administration, said during a Reliability Subcommittee meeting Tuesday that the RTO is “continuing a trend where it increasingly relies on emergency resources, primarily in the form of load-modifying resources, and imports to manage peak loads.”
He added that MISO could exhaust both its firm resources stack and emergency supplies if it encounters high outages and load in June and July. In August, a high-load, high-outage scenario would leave the grid operator with a slim 500 MW of emergency resources.
MISO expects to have 115 GW of accredited resources in June, 123 GW in July and 121 GW in August to meet respective peak loads of 115 GW, 123 GW and 120 GW. The grid operator projects “sufficient firm resources” to cover the summer forecasts. However, if it falls short of meeting demand even under typical conditions, it can declare emergencies so it can access more than 11 GW of emergency padding from load-modifying resources.
MISO normally experiences a little more than 15 GW in forced generation outages and nearly 22 GW in total outages during the summer months.
The spring months have been uneventful so far. MISO averaged a 71-GW systemwide load in March, peaking at 89 GW on March 20. Natural gas accounted for the biggest slice (38%) of the fuel mix, followed by coal (24%), wind (19%) and nuclear (15%). Average real-time prices fell from $42/MWh last March to $26/MWh.
The RTO called for conservative operations — requesting deferred maintenance on facilities so they could be returned to service — in Indiana, Kentucky and Illinois after an outbreak of tornados and high winds March 31-April 1. It also issued a footprint-wide severe weather alert April 4-5 as a swath of severe thunderstorms moved across the country.
Besides those exceptions, Harmon said, the system “performed as expected.” Load averaged 66 GW during the month, with a 78-GW peak April 4. The month’s real-time prices dropped from a $60/MWh average last year to $26/MWh. April’s fuel mix was natural gas (36%), wind (23%), coal (21%) and nuclear (16%).
MISO recorded an all-time solar generation peak of 2.7 GW on May 4.
General Electric will create an onshore wind turbine assembly line in New York in response to increased demand amid federal incentives, the company announced Tuesday.
The move will entail a $50 million investment in the main steam turbine and generator fabrication building in Schenectady. Approximately 200 new full-time employees will be hired for the operation, which is expected to start production by early fall.
The manufacturing line will assemble the machine head, hub, drive train and other key components of GE’s 6.1-158 turbine, a 6.1-MW low to medium wind-speed platform that has recorded more than 4 million operating hours worldwide. The company has received orders for the model totaling nearly 10 GW of nameplate capacity.
GE Vernova’s 6-MW wind turbines are shown in northern New York. The company announced Tuesday it would create a manufacturing line for the turbines in Schenectady, N.Y. | GE Vernova
The announcement came from GE Vernova, the portfolio of energy businesses that is scheduled for spinoff in early 2024. CEO Scott Strazik said the move was prompted by federal incentives for renewable energy development offered by the Inflation Reduction Act and, more recently, the domestic content guidelines to developers hoping to claim those incentives.
“We applaud the administration for the recent domestic content guidance, which gives us the certainty to move forward on this exciting project, and look forward to supporting additional guidance,” Strazik said in a news release. “We’re proud to expand our American manufacturing footprint and workforce to continue building and innovating energy technology that is cleaner by bringing wind turbine component assembly — and an estimated 200 new jobs — to New York.”
GE made a larger but less definitive announcement earlier this year near Schenectady: It will build two offshore wind component factories along the Hudson River with a combined workforce estimated at 870, but only if it receives sufficient orders for its products through the state’s offshore wind buildout.
Subsequent developments have been promising. All six developers submitting proposals in the latest New York solicitation indicated they would rely on GE as a local supplier. And last week, the IUE-CWA announced what it called a first-of-its-kind agreement with the company to not interfere with labor organizers at the two factories.
IUE-CWA Local 301 is the largest union at GE’s Schenectady campus, though its ranks have diminished greatly over the decades as the company has trimmed its presence in the city where it was born 131 years ago.
“The same GE campus that was established by Thomas Edison and Charles Steinmetz, which helped make GE an international brand, will help power America’s clean energy future and continue the great legacy of this campus for the next generation,” said U.S. Senate Majority Leader Chuck Schumer (D-N.Y.), who has been urging GE for years to bring wind turbine manufacturing operations to Schenectady.
New York state has some of the most ambitious climate-protection goals in the nation, and it hopes to build a green manufacturing sector within its borders as it slashes carbon emissions. It is providing GE Vernova with $2.5 million in tax credits to support the creation and retention of at least 160 jobs.
“We are proud to partner with GE Vernova to realize New York’s vision of [becoming] a leading manufacturing hub for wind technology and to bring us closer to achieving our nation-leading climate goals, securing a better and cleaner future for generations,” Gov. Kathy Hochul (D) said in a news release.
Also on Tuesday, GE Vernova announced the launch of an online marketplace offering more than 100,000 parts and related equipment for both its own and other manufacturers’ onshore wind turbines.
More than 54,000 GE wind turbines are installed worldwide, and the company has claimed the lead in U.S. onshore sales for the past five years.
FERC on Monday approved settlements with two demand response aggregators for allegedly bidding more resources than they could provide to CAISO’s market.
OhmConnect (IN23-6) agreed to pay a fine of $141,094 and disgorge $8,906 to the ISO, while Leapfrog Power (IN23-7) agreed to pay $73,880 and disgorge $46,120. Both companies agreed to heightened compliance monitoring in order to shut down enforcement probes over their DR bidding activities.
Both firms were participating in the California Public Utilities Commission’s Demand Response Auction Mechanism (DRAM) pilot program, in which they contract with load-serving entities to provide a set amount of demand response every month. The program required them to tell the LSE they were working with how much DR they would have available in a month 90 days ahead of time.
Ohm’s allegedly problematic bids happened between January and June 2018, and it made $8,906 more than it should have, while Leapfrog’s came between February and August 2019, and it made $46,120 more than it should have.
The two have different business models, with the California-based Ohm focusing on home energy management via customers’ smart meters. It allows residential customers to earn rewards for their energy reductions, which it sells into the markets.
Ohm signed up to provide 109 MW of DR for the 2018 delivery year, but it was not able to sign up enough customers to provide that much, with shortfalls ranging from 32 to 63%.
Leapfrog connects electric vehicle, battery storage, smart thermostat and other flexible technologies to provide DR and enrolls them in the wholesale markets in aggregated portfolios. Leapfrog was a startup and it first bid into the DRAM program in 2018 for 2019 delivery, but it was never able to sign up enough customers to support its bids. Most of the bids it made from February to August exceeded the registered metered load of customers it had signed up, with shortfalls ranging from 54 to 98%.
CAISO’s tariff requires that market participants make bids from resources that are reasonably expected to be available and capable of performing at the levels specified in their bid and to remain so based on all information that is or should have been known to the market participant when their bids were made.
FERC Office of Enforcement staff determined that both Ohm and Leapfrog made a “substantial majority” of their bids when they could not reasonably expect to fulfill them during the relevant periods. In both cases their bids “exceeded the registered metered load of all” their customers.
Both firms stipulated to some facts laid out in the agreement, but neither admitted nor denied the violations that enforcement staff alleged.
Both firms cooperated with the investigations and FERC found that the deals they signed with its staff were fair and equitable resolutions of the matters concerned and are in the public interest because they reflect the allegations’ seriousness and are in line with the regulator’s penalty guidelines.
CAISO will distribute the $55,000 in disgorgements on a pro-rata basis to its network load.
LANSING, Mich. — A Michigan House task force to investigate winter power outages will hold its first hearing June 9, with further sessions expected through the summer.
Rep. Helena Scott (D), chair of the House Energy, Communications and Technology Committee, said the newly formed Energy Reliability, Resilience and Accountability Task Force was created in part to hear from residents across the state who lost power in February and early March, in some cases for more than a week. While the committee held a hearing some months ago about the outages, many people were unable to attend that session in Lansing, Scott said.
The task force’s “Dependable Energy Listening Tour” will include hearings in both the Upper and Lower Peninsula to hear from as many people as possible who were affected by the outages.
Scott also said the task force will also look at how to upgrade the current transmission system by 2035, improving overall state oversight of its grid infrastructure and ensuring it takes less time to restore power after outages.
At the previous hearing, top executives of DTE Energy (NYSE: DTE) and CMS Energy (NYSE: CMS) outlined problems they encountered in trying to restore electric service. Almost 1 million customers were affected, mostly DTE and CMS customers.
The first hearing held by the bipartisan, nine-member task force will be in Lansing at the Anderson House Office Building. A schedule for other hearings has not yet been published.
A group of 14 environmental, climate change and utility activists issued a statement praising the new task force, saying Michigan has relied on coal and other polluting energy sources for too long. “We must begin creating the ‘grid of the future’ now,” the statement said.
Responding to the task force, CMS spokesperson Katie Carey said the utility has as a “top priority” to “strengthen our system in the face of intensifying storms caused by climate change. In order to do that, we file electric distribution plans with the Michigan Public Service Commission which show where we are replacing poles, wires, upgrading substations, undergrounding power lines, increased tree trimming and new technology to benefit customers by having fewer, shorter and less frequent power outages. We will work with this group on the overall goal to continue our efforts to create meaningful, positive change for the planet and for Michigan.”
DTE has also said it is increasing tree trimming and taking other measures to reduce the likelihood of blackouts and reduce the time to takes to restore power.
Washington’s Department of Ecology on Monday issued a water quality certificate for a pumped storage project along the Columbia River, sparking protests from area tribes and some environmental organizations because the location contains sites sacred to the Yakama Nation.
Ecology issued the certification with conditions to ensure the construction and operation of the proposed Goldendale Energy Storage Project meet state water quality requirements.
“Conditions include following specific best practices, requirements for getting future Ecology permits and monitoring and notification requirements,” the agency said in a statement.
Opponents have 30 days to appeal the Ecology Department’s decision.
Boston-based Rye Development is hoping to build Washington’s first pumped storage project for $2 billion in southern Klickitat County near the John Day Dam and commence operation between 2028 and 2030. The project is designed to generate 1,200 MW of energy. (See Wash. Pumped Hydro Project Faces Permitting, Obstacles.)
The project would include two lined 600-acre water reservoirs that are 60 feet deep and separated by 2,100 feet in elevation. One reservoir would be on the river shore, the other atop a cliff adjacent to the Tuolumne Wind Project. An underground pipe would connect the reservoirs, with a subterranean electricity generating station along the channel. Water would flow from the upper reservoir to the lower one to power the four-turbine generator station and would then be pumped back up to the upper reservoir in a closed-loop system.
The water quality certification is one of many approvals needed before the project can be built.
FERC and the U.S. Army Corps of Engineers are reviewing a hydropower license and a permit to fill federally regulated waters, respectively. Under the Clean Water Act, the federal agencies require a water quality certification from the Ecology Department before making their decisions.
FERC also released a draft federal environmental review April 6 and is accepting public comments through June 6.
The pumped storage project would be on private land that Rye Development leases from NSC Smelter, which owns the former site of the Columbia Gorge Aluminum smelter site one mile upstream from the John Day Dam. The site is within a large strip of land in southern Klickitat County that the county has zoned for renewable energy projects.
Tribal and environmental opponents issued a press release protesting against the state certification.
While the project is not on Yakama reservation land, it is on property used for sacred ceremonies, and it has a historical connection to the tribe. The project area includes a longhouse, an ancient village site and other sacred sites. Since 1855, the tribe has had treaty rights to fish and hunt in the area, as well as the right to protect burial grounds and religious sites across a vast area in south central and southeastern Washington.
The Yakama, the Nez Perce Tribe, the Confederated Tribes of Warm Springs and the Confederated Tribes of the Umatilla Indian Reservation oppose the project. This year, the Affiliated Tribes of Northwest Indians, representing 57 tribal governments, and the National Congress of American Indians joined the opposition.
“A clean energy future must uphold federal trust and treaty obligations that consider the cultural and health impacts of these projects on sacred sites,” Alyssa Macy of the Warm Springs nation, who is also CEO of Washington Conservation Action, said in a press release from several tribes and environmental organizations. “These parts of our identity — the land, the roots and the water — are a part of our collective history, and we must not erase them.”
“Pumped storage is a critical tool in facilitating our transition to clean energy. However, the current siting of this project reinforces the exploitation of our tribal neighbors and should have been rejected,” said Sept Gernez, acting director of the Washington State chapter of the Sierra Club.
VALLEY FORGE, Pa. — PJM last week offered stakeholders a series of suggestions for how the RTO could overhaul its capacity market in the wake of significant resource failures during the December 2022 winter storm.
The suggestions accompanied a presentation of PJM’s initial lessons learned from Winter Storm Elliott, intended to inform stakeholders as they consider capacity market changes through the critical issue fast path (CIFP) process.
The analysis is a precursor to the RTO’s anticipated July report on the storm’s impact, PJM’s Glen Boyle said during a May 17 CIFP meeting.
Elliott was the latest in a series of events showing that winter comes with significant risk, Boyle said, and PJM is recommending that stakeholders evaluate how it can improve its modeling to better account for the drivers of winter risk — namely, high loads and generation failures.
Citing the widespread failure of capacity resources to perform, despite high penalties under the capacity performance (CP) structure, PJM recommended revising capacity market incentives — including financial risks, strengthening accreditation requirements, increasing the frequency of testing and additional visits to generating sites.
Paul Sotkiewicz, president of E-Cubed Policy Associates, questioned the value of site visits, saying generators in other RTOs that conduct them regularly have told him the staff sent to facilities often don’t understand plant operations.
“Just because you send someone out there, doesn’t mean they know what they’re looking at,” he said.
PJM also found that market participants required education — both during the storm and in the penalty settlement process — on performance assessment intervals (PAIs), including what they are, how they function and where they are laid out in the governing documents.
The storm analysis also revealed instances in which the penalties weren’t aligned with dispatch basepoints, which Boyle said in part reflects a generator’s performance obligation not taking in account the generator’s characteristics, such as ramp rates.
Calpine’s David “Scarp” Scarpignato said many of the rules and procedures under discussion following Elliott were put in place deliberately. By not creating a penalty carve-out for generators’ ramp-rates, he said it was hoped that operators might find ways to start their units faster than their stated capabilities. Creating an exemption for ramp-rates would also risk allowing generators to be excused for hours, which would be unfair to resources that have fast-start capabilities.
“These rules are thought out; this isn’t something that accidentally happened, and I don’t want to lose sight of that,” he said.
PJM was a net exporter of energy throughout much of Winter Storm Elliott, which Boyle said led to increased obligations for capacity resources under the current balancing ratio formula. Many of the complaints filed at FERC seeking relief from penalties during Elliott argued that exporting during a PAI constitutes a tariff violation and effectively puts generators on the hook to provide capacity to resources outside PJM that haven’t paid for the service.
“The way I view exports is that a generator who signed up for a capacity commitment is being paid by PJM load-serving members and they have an obligation for that in exchange for that payment … and if they fail to provide that service, a penalty obligation is appropriate,” said ODEC’s Mike Cocco. “Here you have people outside the PJM system that are not paying these generators.”
PJM is also recommending a reevaluation of how resources whose offers cannot currently be translated into a performance obligation to benchmark performance against during a PAI can be fit into the framework. Those resources are not currently eligible for bonus payments or for excusal from penalties. Boyle said this mainly applies to resources with zero-cost offers.
Given that the current process for penalty excusals requires a large amount of manual work and case-by-case review, PJM also recommends that stakeholders consider options for streamlining the process.
A significant portion of the bonus penalties stemming from Elliott are being distributed to energy efficiency and demand response resources, which PJM said warrants an evaluation of whether their performance matches their reliability contribution.
PJM will continue to investigate poor performance of nonretail behind-the-meter generation (BTMG) during the storm and provide further recommendations on how to either make improvements or alter how those resources participate in the capacity market.
Speaking on behalf of the PJM Public Power Coalition, Customized Energy Solutions’ Carl Johnson said nonretail BTMG is governed by an agreement made prior to the creation of the capacity market and that performance during Elliott demonstrates that arrangement may need to be reconsidered.
Sotkiewicz said the recommendations and issues identified lack a focus on PJM operations during emergency conditions. Changes to market structures will have little impact if accurate forecasts aren’t developed and enough resources committed to maintain reliability, he said.
Morris Schreim, senior adviser for the Maryland Public Service Commission, questioned how improving the incentives for generators to perform would function while gas supply remains an issue, to which PJM’s Mike Bryson said a fuel assurance requirement will likely be part of PJM’s CIFP package.
Clearway Energy Presents CIFP Proposal
Clearway Energy presented a series of proposed changes to CP and the capacity market focused on tying the performance expectations for wind and solar resources to how they typically operate. Under the current methodology, in which resources have a flat obligation for all times and conditions, that expectation would usually be inaccurate, said Autumn Lane Energy’s Pete Fuller, representing Clearway. For solar, he said resources are below their obligation throughout the night and above it during most days.
By tying performance baselines to a renewable resource’s individual engineering characteristics, operators will be incentivized to ensure their facilities are operating at the peak of their capacity during emergencies, with all solar panels cleaned and ball bearings greased.
Fuller said Clearway echoes PJM’s desire for more frequent PAIs to make it easier for generators to evaluate and manage their risk. However, they disagree with PJM’s approach of creating a fixed number of ‘tier 2’ performance assessment intervals. Rather than using an “arbitrary number,” Fuller said additional performance hours should be pegged to system conditions.
“There may be a way to look at approaching a reserve deficiency or approaching stress on the system and defining that numerically,” he said.
Clearway’s approach to performance baselines for wind and solar would continue to calculate a resource’s annual reliability contribution through PJM’s existing effective load carrying capability (ELCC) methodology or a similar system, but would determine its output for purposes of performance assessment intervals on meteorological data and the operational characteristics reflected in its accreditation.
Fuller gave three ways of setting performance obligations under the proposal:
a real-time dynamic baseline with five-minute granularity, which has the advantage of high accuracy;
a baseline set with day-ahead forecasting, which would be less computationally intensive, but less accurate with hourly granularity; and
creating a baseline using known characteristics of resources, such as not giving solar resources an obligation at night.
Monitor Adds Detail to Proposal
Independent Market Monitor Joe Bowring discussed the market clearing process in his CIFP proposal, saying the market clearing process would account for the hourly availability of resources and ensure that generators can cover their net annual avoidable cost.
“The proposal addresses the two functions of the capacity market: ensuring that there is enough energy to meet the load in every hour, and ensuring that generators have the opportunity to cover their avoidable costs — the so-called missing money,” he said.
Under the plan, resources would provide their expected hourly available megawatt profile and PJM would provide the expected hourly load plus reserve margin. The market clearing process would result in a single clearing price for each relevant location and identify the resources needed to reliably meet the load.
During the actual delivery year, if a resource’s energy output matched the modified availability factor in its capacity market offer, it would receive the capacity clearing price in for each hour. If a resource did not perform, it would not be paid. Generators that didn’t fully clear the auction would be eligible for make-whole payments, exactly like the status quo rules.
PJM’s Walter Graf said that since the Monitor’s proposal treats every hour the same, if the grid were to be in emergency conditions and shedding load in one hour, an underperforming capacity resource would receive less than its full capacity revenues; however, it would be able to make that up by overperforming when the grid is not stressed.
“The most fundamental concern I have with this model is that of pricing,” Graf said. “I think what you’re attempting to do in the auction is attempting to identify the least-cost [clearing] resources,” but then compensate every megawatt-hour at the marginal cost of the highest clearing resource. He said he was concerned that the mismatch between value and compensation introduces opportunities for strategic bidding, doesn’t support a competitive equilibrium and doesn’t incentivize resources to offer at their costs, but instead submit a low offer to clear fully.
Bowring said he disagreed with each of the assertions and that PJM’s proposal fails to address the identified issues as fully as the Monitor’s proposal. He pointed out that the current design, and the design favored by PJM, pays a single clearing price for the entire year, based on the marginal cost of the highest clearing resource, which is the same thing as paying the same price in every hour. The Monitor’s proposal, unlike the PJM proposal, does not pay the capacity price to resources that are not available in an hour. Bowring said the proposal recognizes that the PJM energy market provides the required hourly and locational incentives to produce when conditions are tight and prices high. Though he doesn’t believe it’s currently necessary, he said it would be straightforward to add differential penalties to the model.
Calpine’s Scarp questioned why the proposal verifies performance for each hour if each hour is treated the same, suggesting the process could be simplified by using resources’ equivalent forced outage rates (EFORd).
“Why do all this accounting and measure all these things when really you’re only interested in one number at the end of the year,” he said.
Bowring responded that EFORd is not as comprehensive a metric of availability as the proposed Modified Availability Factor. An hourly approach is essential, considering the growing role of intermittent resources, which, unlike thermal resources, are not available in every hour, he said.
Bowring said the hourly approach is preferable to ELCC, which is also based on hourly data, and the hourly approach pays resources only when available. Paying for performance is not possible when using only a simple average approach, he said.
Two recently published reports on the Regional Greenhouse Gas Initiative (RGGI) found that participation in its cap-and-invest auctions produce net economic benefits and that Pennsylvania would see a small change in power prices should it join.
A May 16 report from the Analysis Group found that between 2018 and 2020 auction proceeds generated $669 million in net economic value and nearly 8,000 job-years for the 10 participating states.
“Although the original focus of the RGGI program was to address carbon emissions, we have consistently found that the cap-and-invest program results in a net positive economic impact for participating states,” Paul Hibbard, report co-author, said in an announcement of the report. “Our analysis shows that the regional cap works to limit carbon pollution, and the investment of auction proceeds plus the program’s impacts on the power sector result in overall reductions in electricity usage, additional income for consumers and business owners, and new jobs.”
The Analysis Group report is the fourth in a series of studies evaluating the economic impact of each three-year compliance period for the RGGI auctions. Together they find in its 12-year history, RGGI has yielded $3.8 billion in auction proceeds, which states spent on programs creating $5.7 billion in net economic benefits and 48,000 job-years. The program has also contributed to a 46% reduction in carbon emissions from power generation from 2006 to 2020.
States have used the proceeds from CO2 allowance auctions to fund energy efficiency programs, renewable energy development, education and job training, measures to reduce greenhouse gas emissions and ratepayer relief.
“[Energy efficiency] and [renewable energy] programs reduce net electricity consumption for program participants and lower wholesale electricity prices for everyone in the RGGI region by lowering regional electricity demand,” the report states. “Overall, despite an initial increase in wholesale electricity prices during the compliance period, consumers enjoy net economic gains through the combination of direct program spending and savings associated with EE and RE spending.”
Though it was not the focus of the Analysis Group report, Hibbard said researchers observed that New Jersey has seen economic outcomes in line with it dropping out of RGGI in 2011 and its re-entry in 2020.
“Over the four reports we’ve done, New Jersey has at times been part of it, and when they were participating in RGGI they were achieving significant economic benefits, because New Jersey was taking their money, using it in certain ways, generating jobs within New Jersey and generating an increase in gross state product within New Jersey,” he said. (See NJ To Accelerate RGGI Fund Expenditures.)
Connecticut Department of Energy and Environmental Protection Commissioner Katie Dykes, who is also chair of RGGI Inc., said the report underlines that the benefits of RGGI go beyond its environmental goals.
“Throughout its history, RGGI has delivered numerous benefits to Connecticut and the other participating states, including lower energy bills for our residents and businesses, new jobs in our growing clean energy industries, and reductions in climate-damaging, health-harming pollution,” she said in the report’s announcement.
In addition to its economic analysis, the report looked at what states are doing to address potential disparate outcomes for overburdened communities, a discussion that members are undertaking as part of RGGI’s third program review. One proposal under discussion is a “hybrid methodological approach” to evaluate programs’ impacts on those communities. Also under consideration are using RGGI auction funds to conduct air monitoring, providing opportunities and resources for active community participation, spending requirements and tracking both environmental and health outcomes.
“In my view it’s almost certain the public health impact of RGGI is to reduce environmental risks even in overburdened communities,” Hibbard told NetZero Insider. “The reason it’s an issue in the context of RGGI is because some people have pointed out that you can have the program reduce emissions from power plants overall, but the financial signals of a cap-and-trade program might allow an individual power plant to actually operate more. There are some arcane circumstances [in which] that could be the case.”
Devashree Saha, senior associate at World Resources Institute and a member of RGGI’s technical advisory group, said that the report showed avenues for participating states to ensure that the environmental benefits of reducing emissions are spread equally for all residents.
“Even though the electricity sector has made significant progress in reducing emissions in the aggregate, existing policies and the RGGI framework do not fully address the fundamental problem of unequal pollution burden among communities,” she said in the announcement.
Study Finds RGGI Participation Presents Little Impact to Energy Prices
A second study, released May 9 by Resources for the Future and the Kleinman Center for Energy Policy at the University of Pennsylvania, found that joining RGGI in 2023 would have minimal impact on energy prices for Pennsylvania ratepayers. That is, in part, due to an expectation that allowance prices in the 2030 auction would fall from $8.59 to the floor price of $2.26 due to the widespread low-cost abatement opportunities in the state. A 2019 Executive Order issued by former Gov. Tom Wolf would make the state the 12th to join RGGI, however the order’s implementation has been prevented by ongoing lawsuits in state courts. (See Court Blocks Pa. from Joining RGGI.)
If the state were to begin participating in auctions this year, the study finds that 2030 emissions would be cut by 84% relative to 2020 levels, compared to a 49% to 52% decline if the state were not to join. That would amount to a 25-million-ton reduction in emissions to 28 million tons in 2030. The report bases its findings on the state’s proposal that its emissions cap be based on its 2020 emissions of 83 million short tons and decline by 3% annually, which follows the trajectory of the emissions cap in RGGI. An alternative scenario with a stricter cap of reaching zero emissions by 2040 finds similar reductions by 2030.
Retail electricity prices are estimated to increase by about 1% in 2030 under the 3% declining cap scenario and decrease by 0.6% under the scenario with a zero emissions cap in 2040.
“Initially, one might anticipate that introducing a carbon price in the electricity sector would raise the wholesale price (and thus retail price) by the allowance price times the emissions rate of the marginal generator. However, a Pennsylvania generator may not be the marginal generator in PJM,” the report says. “Furthermore, the price may be lower because even in the first year after a carbon price is introduced, there may be an opportunity to change the dispatch order of generation resources, including hydro or battery storage, such that the marginal plant changes to a lower-emissions plant, or for the marginal plant in the regional market to become a plant outside the state.”
While the report focuses on the impact to wholesale electricity prices, it notes that the auction revenues could be invested to the state’s economic benefit, particularly since much of that revenue would be coming from generators located in other states.
“Despite low allowance prices, the state still gains $101 million to $148 million from the auction of emissions allowances in 2030. A large portion of this revenue (71%) comes from the purchase of allowances by generators in other RGGI states,” the report said. “The net effect for Pennsylvania consumers, combining auction proceeds and the change in electricity prices, is slightly negative under the 3% cap and beneficial under the tighter cap. Pennsylvania may decide to direct some or all of this revenue to program-related purposes that could directly reduce electricity bills or accelerate decarbonization.
Most of the reductions are expected to come from emissions reductions from coal generation, which report co-author Angela Pachon, research director at the Kleinman Center, said also accounts for the expected drop in allowance prices in the RGGI auction. Since Pennsylvania has a relatively large share of coal generation relative to other RGGI states, she said there are many more opportunities for abatement. The report was cowritten by Maya Domeshek, research associate at RFF, and Dallas Burtraw, senior fellow at RFF.
The study also finds that current allowance prices are not likely to be representative of the future of RGGI with Pennsylvania’s participation because of volatility in natural gas prices owing to current global instability and risk averse behavior observed in the markets in the past when the state was expected to join.
“New entities enter the program with no market experience or allowance bank. Consequently, every previous emissions market (including markets for sulfur dioxide and nitrogen oxides) has seen initially high levels of demand and temporarily high prices as firms acquire allowances to build up a bank (Burtraw and Keyes 2018). This market behavior is typically followed by a return to expected prices over the longer term as the generation mix has time to adjust,” the report states.
Unlike past studies examining the impact of the state participating in the RGGI auctions, which found that joining would likely lead to increased retirements of fossil fuel generation, the RFF report found that it would likely lead to increased renewable development in the state, in large part because of incentives under the Inflation Reduction Act.
Daniel Stuart, co-author of the Analysis Group report, said the RFF study dovetails with his findings by showing that the impact to energy prices is likely to be outweighed by the benefits derived from programs funded by the auction revenue.
“I did have a chance to review the RFF report. It seemed to be very carefully done, and really the findings are very consistent and complement our study in the sense that they find perhaps positive, perhaps negative, but overall very small impacts on wholesale electricity prices,” he said. “And then what our report demonstrates is that once you raise allowance auction revenue and spend it and reinvest it in local communities, you’re going to experience an economic impact.”
The U.S. Bureau of Ocean Energy Management (BOEM) issued a final environmental impact statement (EIS) Monday for Ocean Wind 1, New Jersey’s first offshore wind project, concluding that the project combined with others will have a “major” impact on scenic and visual factors and on scientific research, but only a “moderate” impact on a host of other issues.
The over 2,300-page report, which will be used as a touchstone by federal and other decision-makers to determine the future of Ørsted’s 1,100-MW Ocean Wind 1 project, said the impact of the project alone on scenic and visual factors such as the “seascape, open ocean, and landscape character and viewers” would be only “moderate.”
But the cumulative impact of the project, which would erect 98 turbines about 15 miles from Atlantic City, on scenic and visual factors would be “major” once combined with “other ongoing and planned activities” in the area, the EIS said.
There could be 859 turbines installed in the area between 2024 and 2030 if all other planned projects go ahead, the report said. The EIS found the cumulative scenic and visual impact would be “major” even if Ocean Wind 1 did not go ahead.
Because Ocean Wind 1 is the state’s first offshore wind project, the EIS provides a kind of guideline for other, future projects. The BOEM release announcing the EIS said it will issue a decision on the project in the summer.
The EIS evaluates the impact of the project on 18 factors and defines the impact as either major, moderate, minor or negligible. The study also looked at four other scenarios with changes made to mitigate the impact, such as creating a buffer between it and an adjacent project or placing its turbines closer together.
Maddy Urbish, head of government affairs and market strategy in New Jersey for Ørsted, welcomed the release of the EIS.
“Ocean Wind 1 continues to advance through the multiyear federal permitting process, and we’re pleased to reach this latest milestone,” she said. “Ocean Wind 1 anticipates onshore construction beginning in the fall and offshore construction activities ramping up in 2024.”
OSW Progress
The release comes a week after BOEM issued the draft EIS for the 1,510-MW Atlantic Shores project, one of two projects approved by the New Jersey Board of Public Utilities in its second OSW solicitation. The other project, the 1,148-MW Ocean Wind 2, was also developed by Ørsted. (See BOEM Draft EIS Finds Potential Major Impacts from 1st NJ OSW Project.)
BOEM said the release of the EIS for Ocean Wind 1 is part of the agency’s ongoing effort to meet President Joe Biden’s goal of deploying 30 GW of OSW energy capacity by 2030. The agency said it held three public hearings and received 1,389 comment submissions.
“BOEM continues to make progress towards a once-in-a-generation opportunity to build a new clean energy industry in the United States,” BOEM Director Elizabeth Klein said.
The progress in New Jersey is far from assured, however. Offshore wind projects face opposition from the commercial fishing sector, Jersey Shore homeowners, the tourism sector and state business groups concerned at the cost. Two local governments that represent communities through which Ørsted plans to run cables from the offshore generators to the state grid — Cape May County and Ocean City — have sued in state court to overturn the BPU’s approval of easements to allow the cable installation. (See County Contests Tx Easement for NJ’s 1st OSW Project.)
BOEM found Ocean Wind 1 would have only moderate impact in most of the categories studied, among them: recreation and tourism; navigation and vessel traffic; coastal habitats; birds; and water and air quality. It found a negligible to minor impact on land use and coastal infrastructure.
The study found the impact of the Ocean Wind 1 alone on scientific research and surveys would be major, as would the cumulative impact of the project and others nearby, including on National Oceanic and Atmospheric Administration surveys that support commercial fisheries and protected species research programs.
“The entities conducting scientific research and surveys would have to make significant investments to change methodologies to account for areas occupied by offshore energy components, such as [wind turbine generators] and cable routes, that are no longer able to be sampled,” the study said.
Significant Impact on Commercial Fishing, Whales
Similarly, the study found the impact on the commercial and for-hire recreational fishing sectors would be major, both from the project itself and the cumulative impact. In both cases, the impact would be “minor to major on commercial fisheries and minor to moderate on for-hire recreational fishing depending on the fishery or fishing operation.”
Even if Ocean Wind 1 did not go ahead, the commercial fishing sectors would face challenges from busy port use, inflated vessel activity, other offshore development and climate change issues, the EIS says.
If the project goes ahead as planned or with modifications, the factors that would determine the scale of the impact include: number, size and location/orientation of turbines; length and route of inter-array and offshore export cables; number of simultaneous vessels, number of trips and size of vessels, which could affect potential risk for vessel collisions and use of port facilities; and time of year during which construction occurs, which could affect access to fishing areas and availability of targeted fish in the area, thereby reducing catch and fishing revenue.
The study found that the impact on mammals would in general be moderate. But it found the impact of the project alone, and the cumulative impact with other projects, would be moderate to major for North Atlantic right whales.
The impact on the right whale population has emerged as a significant issue in New Jersey after a spate of whale deaths in recent months, with the bodies washing up on the Jersey Shore. Opponents of OSW, and two Republican members of Congress, have suggested the deaths could be linked to preliminary marine studies being conducted for the OSW projects. However, federal and state officials say there is no evidence linking the deaths with the wind projects.
The EIS says right whales are already facing considerable stress factors, including elevated vessel activity and collisions, and the effects of climate change. Because “offshore wind construction, operation and maintenance activities would be conducted with applicant-proposed and agency-required mitigation measures,” the activities are “not anticipated to substantially contribute to the major impacts,” the EIS states.
However, the study added that that “it is unknown whether the population can sufficiently recover from the loss of an individual to maintain the viability of the species.”
In the ongoing congressional wrangling over how to streamline and accelerate permitting for energy projects and transmission, Sen. Tom Carper (D-Del.) has lobbed a new, largely progressive proposal into the mix, with a strong focus on clean energy and environmental justice.
While Republican lawmakers have advocated for a narrow interpretation of environmental impacts in reviews required under the National Environmental Policy Act (NEPA), Carper wants these studies to look at the potentially positive environmental effects of a project, “including greenhouse gas reductions,” according to a summary of the bill. It would require that consideration also be given to indirect and cumulative impacts, as well as the “foreseeable adverse effects of not completing a project.”
NEPA reviews would also have to include “meaningful public involvement opportunities” and community impact reports to address environmental justice concerns, according to the summary. It would also allow a federal agency to require a developer to include a community benefits agreement as part of an environmental review.
Such agreements generally specify certain social and economic benefits, such as jobs and job training, that a community affected by a project will receive.
The bill also calls for $500,000 to be allocated for a feasibility study of setting up a single online permitting portal. An additional $20 million per year for five years would be authorized for the establishment of “linked interagency environmental data collection systems to standardize and facilitate the use of” data across agencies, project sponsors and the public to support environmental reviews.
To ensure adequate staff for permitting, the bill would provide $45 million per year, again for five years, “to fund scholarships, fellowships and research at institutions of higher learning relevant to the permitting process.” At the same time, federal agencies would be directed to “conduct human capital planning” and staff up to meet accelerated permitting processes.
In perhaps its most radical proposal, the bill would set up a process under which federal agencies could identify “commercially viable, nationally significant projects” and get them permitted and shovel-ready before opening competitive bidding for “nonfederal project sponsors” to develop them. The permitting process would also resolve any issues that might lead to litigation.
It would also promote development of clean energy projects on brownfield sites and authorize EPA to provide financial assistance to states to hire additional staff with the environmental and legal expertise needed to process them.
In a Thursday press release, Carper, who chairs the Senate Environment and Public Works Committee, said the bill would improve permitting “without undermining our nation’s bedrock environmental protections.”
Pointing to the passage of the Infrastructure Investment and Jobs Act and the Inflation Reduction Act, Carper said, “We need efficient permitting processes that allow our nation to meet our climate goals with the urgency that science demands. The PEER Act would help accelerate clean energy projects and create good-paying jobs across our country while ensuring that communities have a say in infrastructure projects.”
On Monday, Carper announced he will not run for reelection in 2024.
Five other Democratic senators joined Carper as cosponsors of the bill: Brian Schatz (Hawaii), Sheldon Whitehouse (R.I.), Tina Smith (Minn.), Chris Murphy (Conn.) and Alex Padilla (Calif.).
“It would be a huge, missed opportunity to let the transit and clean energy projects in the IRA and the [IIJA] get bogged down in our outdated and unwieldy permitting processes,” Murphy said in the press release. “If it takes a decade to get a permit to build offshore wind, expand passenger rail service or upgrade our electric grid, we won’t ever accomplish our climate goals.”
Opportunity for Bipartisanship
The PEER Act is the latest in a series of bills being offered from both sides of the aisle on the issue of permitting reform, which could become a major bargaining chip as Biden and House Republicans attempt to negotiate a package to raise the debt limit before a potential default.
The House of Representatives’ Limit, Save, Grow Act (H.R. 2811) includes the previously passed Lower Energy Costs Act (H.R. 1), with provisions that would accelerate permitting of fossil fuel projects, but without any mention of clean energy or transmission.
GOP bills sponsored by Sens. John Barrasso (R-Wyo.) and Shelley Moore Capito (R-W.Va.) aim to accelerate fossil fuel permitting or undercut NEPA and the Clean Air and Clean Water acts. Under Capito’s bill, for example, if an agency failed to complete a NEPA review within two years, the project would automatically be considered as meeting all NEPA requirements.
Sen. Joe Manchin (D-W.Va.), chair of the Senate Energy and Natural Resources Committee, reintroduced his Building American Energy Security Act, which drew some bipartisan support in the Senate in December but ultimately failed.
Points of agreement include limiting the time frames for NEPA environmental impact reports to two years, while less intensive environmental assessments would be capped at one year. A limit on litigation could also be part of any compromise: Carper’s bill would provide three years for legal challenges to an approved project — half the six years currently allowed — while Manchin’s would allow for 150 days and Barrasso’s and Capito’s 60 days.
Cross-agency coordination, with one federal agency leading the permitting on any one project and releasing a single environmental impact statement or assessment, also has general bipartisan support, as does expanding the use of programmatic reviews and categorial exclusions.
Programmatic environmental reviews can assess impacts in a specific region or a transmission corridor and then be used for multiple projects within the region or corridor. Categorical exclusions are waivers, finding that a project will have no significant environmental impacts. Carper’s bill would allow one agency to use another’s categorial exclusion after consulting with the other agency and providing an opportunity for public comment.
Flash Points
While Capito and Barrasso have both called for permitting reform to be technology- and project-neutral, their respective bills and H.R. 1 tilt heavily toward fossil fuels. Carper and the White House tilt toward renewables and zero-emission projects, as well as transmission.
Manchin’s bill goes for an all-of-the-above approach, with provisions that the president must draw up a list of 25 geographically and technologically diverse, high-priority energy projects that would also be a high priority for permitting. But his must-have is the completion of one of his own high-priority projects, the Mountain Valley natural gas pipeline.
A major sticking point may be the expanded role Democrats, including Manchin, want FERC to play in federal permitting of transmission projects, which so far the GOP has not supported. Two issues, FERC’s backstop siting authority and cost allocation, are key points in Manchin’s and Carper’s bills, as well as in ongoing debates between states and FERC. (See related story, FERC Backstop Siting Proposal Runs into Opposition from States.)
Manchin’s bill would streamline FERC’s backstop siting authority, which allows the commission to permit transmission projects of national interest in the event a state denies or does not permit such projects within a year. It also calls on the commission “to ensure project costs are allocated to customers that receive proven electricity benefits.”
Carper’s bill provides a more detailed vision of FERC’s role in transmission planning and permitting, including amendments to the Federal Power Act “to allow the United States to proactively plan and build the broad regional grid it needs.”
On cost allocation, Carper’s bill would direct FERC to “account for the full scope of benefits from transmission investments, such as renewable energy transmission and connection, reliability and resiliency improvements, and meeting decarbonization goals,” according to the summary. “Rules must require portfolio-based cost allocation and prioritize interregional cost-benefit considerations over regional ones.”
At a recent ENR hearing and in a Saturday op-ed in The Intelligencer, Manchin urged senators to put politics aside and work toward the difficult but necessary compromises needed for a bipartisan bill. He also said he would be scheduling “more sector-specific energy permitting hearings in the weeks ahead to learn more about the issues these projects face and [that] inform our work.”
But as long as permitting reform is tied to the debt ceiling debate, the possibility of finding more substantive common ground and compromises appears less likely, according to ClearView Energy Partners.
“Both sides have rolled out rhetorical postures that we regard as nonstarters,” ClearView said in a recent rundown of the permitting bills now in play. “A bigger challenge may be the limited overlap between both sides’ maximalist aspirations, as this leaves little room for a consensus mini-deal before the early June debt ceiling [deadline]. …
“If permitting reform were inevitable, its proponents would not be looking for a ‘must-pass’ bill like the debt ceiling, and if its momentum were insurmountable, it would not require a forcing event like imminent default to propel it.”
BOSTON — Massachusetts legislators and climate advocates called for a billion-dollar fine on the country’s largest carbon-polluting companies at a meeting of the legislature’s Joint Committee on Environment and Natural Resources on Wednesday.
The committee took public testimony on 44 bills from both houses concerning climate and energy policy. A large portion of the testimony focused on several bills that would fund and support climate resilience.
Prior to the hearing, climate activists rallied in front of the Statehouse in favor of Senate Bill 481 and House Bill 3581, which would create a “climate change superfund” by imposing fines on the largest carbon-emitting companies in the country based on their proportional shares of historic emissions. The fine would impact entities responsible for more than 1 billion tons of carbon-equivalent emissions and is designed to generate $75 billion over 25 years.
The fund would support projects such as seawalls, stormwater management upgrades, adaptation improvements to transportation and grid infrastructure, ecological restoration projects, and cleanup projects after storms.
“The question now is who is going to pay for the damage caused by climate change,” said Jon Grossman of SEIU local 509, which represents nearly 20,000 educators and service workers in the state. “If we don’t take appropriate action, this will come to a significant cost to taxpayers and also a significant cost to Massachusetts residents who rely on public services. …
“As we in the labor movement know, when we look around, we can see that there is money out there, and it seems that the folks that caused this crisis have a lot of it; fossil fuel companies are among the most profitable in the world,” Grossman added.
Similar legislation was proposed in 2021 by Democrats at the federal level and has been introduced at the state level this year in New York and Maryland. Representatives for groups, including the Massachusetts Youth Climate Council, Communities Responding to Extreme Weather, Massachusetts Climate Action Network, 350 Massachusetts, Elders Climate Action and the Mass Power Forward coalition, spoke in favor of the bills, highlighting the responsibility of major fossil fuel companies in driving the climate crisis and blocking climate action.
“It is well documented that at least Exxon hired scientists more than 30 years ago to study the effects of their product, found it was detrimental to all living species and then lied about it,” said Cabell Eames, political director of the Better Future Project. “The level of deceit is of epic proportions, and at this point to allow the fossil fuel industry to continue business as usual without holding them accountable is enabling an industry that has proven criminal in its wanton fraud and disregard for the human race.”
Activists from the Massachusetts Youth Climate Coalition call on the committee to advance Senate Bill 481, which would impose a fee on the state’s largest climate polluters. | Mass. Joint Committee on Energy and Natural Resources
Another bill focused on addressing climate fallout, filed as House Bill 750 and Senate Bill 472, would fund climate resilience projects by imposing a fee on property insurance, which advocates said would avoid financial burdens for low-income residents. Representatives of the Conservation Law Foundation, the Nature Conservancy, Mass Audubon, the North Central Climate Change Coalition and My Brother’s Table spoke in favor of the bill.
“While the funding proposed in this bill is only a small portion of what’s needed, its aim … is to turbocharge programs in Massachusetts that support, enhance and supplement climate adaptation and mitigation programs that have equitable goals and outcomes,” said Sam Anderson of Mass Audubon.
Advocates also testified in support of a bill that would open the door for advanced research into nature-based solutions to dealing with climate effects.
Representatives of the University of Massachusetts Boston, Boston Harbor Now and the Boston Children’s Museum spoke in favor of House Bill 3581 and Senate Bill 458, which would ease regulatory hurdles for research and demonstration projects looking at nature-based mitigation approaches to rising sea levels and severe storms. These could include projects mimicking natural coastal marshes, dunes and bluffs.
“These nature-based systems can offer many advantages over concrete sea walls, such as decreasing erosion, not increasing it. They are less expensive to construct, and they also provide many environmental and social co-benefits that promote social justice and equity,” said Paul Kirshen, professor of climate adaptation in the School for the Environment at UMass Boston.
Lawmakers and advocates also testified in support of a variety of bills focusing on ocean acidification, carbon sequestration in marine ecosystems, increasing staffing of climate agencies in rural municipalities and mitigation of ecosystem impacts from offshore wind development.
Addressing Embodied Carbon Emissions
Climate advocates also spoke to the committee about the importance of addressing the lifecycle emissions associated with building materials, from concrete to petroleum-based insulation. Frequently referred to as embodied carbon, these emissions account for about 11% of global emissions, according to data from the Global Alliance for Buildings and Construction and the International Energy Agency.
“When it comes to embodied carbon, we’re really talking about the elephant in the room,” said Logan Malik of the Massachusetts Climate Action Network. “In order for us to build and decarbonize our buildings holistically, we have to incorporate embodied carbon. But at the same time … very, very little is being done in our state to actually do that.”
House Bill 764 would establish an expert advisory board on embodied carbon, commission a report to inform additional legislative action, incorporate embodied carbon into the state’s stretch code and require the Department of Energy Resources to issue recommendations for reducing embodied carbon emissions.
Banning Fossil Fuel Extraction
Legislators also presented bills to the committee that would ban fracking and offshore drilling in the state, citing climate, environmental and public health concerns.
Rep. Carmine Gentile (D), who sponsored House Bill 815 to ban all forms of fracking in the state, highlighted the risks of groundwater contamination, as well as the link between fracking and children born with congenital heart defects.
“There’s no fracking at the moment in Massachusetts, but there’s a real potential of future oil and gas development that could take place in the Hartford Basin, which stretches into Western Massachusetts,” Gentile said.
Meanwhile, Senate Bill 464 would ban offshore drilling infrastructure, exploration and development in Massachusetts state waters, along with any onshore infrastructure to support offshore drilling. Sen. Julian Cyr (D), the bill’s sponsor, said that while the Biden administration does not plan on opening up the East Coast for offshore drilling, “the threat of an administration that would open up the Eastern Seaboard to coastal drilling is very real.”
