RENSSELAER, N.Y. — NYISO on Monday presented another reformulated proposal to enhance its interconnection study processes and align with the new directives set forth in FERC Order 2023.
During the Interconnection Issues Task Force’s first meeting, NYISO said it will adhere to FERC’s proposed study format but introduce some ISO-specific variations, such as a two-phase cluster study, a rolling optional pre-application and an altered customer engagement window with a physical infeasibility screening. The IITF was established to investigate, refine and implement these directives.
NYISO argues that its proposal strikes a balance between FERC’s guidelines and the unique needs of New York’s energy landscape. FERC’s directive accommodates such variations, recognizing that each RTO and ISO faces its own set of challenges and policies.
The most significant difference between NYISO’s and FERC’s proposals lies in the structure of the cluster studies.
Unlike FERC’s single cluster study that is followed by individual facility studies, the ISO uses a two-phase approach in which routine interconnection studies, like the system reliability impact study or system upgrade study, would be conducted in the second phase.
A new window would be initiated every 18 months, sticking to the commission’s overall timeline but incorporating elements from NYISO’s previous interconnection queue changes. There would be a slight overlap between each cluster study window, but the ISO does not expect this to necessitate any rework.
Thinh Nguyen, NYISO senior manager of interconnection projects, explained that the ISO also wants to include several pre-work phases within the study window to “help organize and provide the appropriate information at the start of each phase to developers and” the ISO.
Theoretical timeline of 18-month sequenced cluster studies | NYISO
NYISO would transition directly to the new cluster study process, bypassing a yearlong transitional study. The move aims to minimize the transition impacts and allow the next cohort of projects sufficient time to adapt to the new procedures.
Stakeholders at the IITF meeting were generally receptive to NYISO’s proposals but urged the ISO to ensure clarity in its revisions to avoid future confusion.
Mark Reeder, representing the Alliance for Clean Energy New York, worried about the window overlap and if conducting project feasibility studies at the end of one window when another starts was the best way to go about things.
Sara Keegan, an attorney with NYISO, responded that conducting these studies later has proved more efficient in other RTO and ISOs interconnection studies and the ISO does not think it would cause any issues.
Howard Fromer, who represents Bayonne Energy Center, expressed concern for how Class Year 2021 projects currently seeking interconnection would be affected. NYISO clarified that because these projects finished class year processes, they are now subject to different standards, but it promised further details in the future.
Doreen Saia, an attorney with Greenberg Traurig, inquired about the treatment of new interconnection requests during this transition period, saying the ISO should try and get ahead of this potential issue to avoid “having a whole bunch of requests coming in because [projects] are afraid of missing out.”
NYISO staff assured Saia that new requests would continue to be accepted and promised to provide a clearer timetable soon.
NYISO, along with other RTOs, filed Order 2023 compliance extension requests with FERC, but if its request is denied, then it must file its compliance by Dec. 5. (See NYISO to Ask FERC for Order 2023 Compliance Extension.)
The IITF will reconvene to discuss the proposal in greater detail Oct. 20.
While a lot of progress has been made, getting to a fully decarbonized economy is going to require new technologies, U.S. Energy Secretary Jennifer Granholm said Tuesday at this year’s Hydrogen Americas Summit.
“It is certainly going to be helpful to decarbonize our hardest-to-abate sectors: obviously heavy industry [and] transportation,” Granholm said. “Hydrogen, as you all know, could lead to clean dispatchable baseload electricity; it can provide options for long-duration energy storage and shore up our energy security, especially during supply chain breakdowns.”
Granholm joked that unfortunately she was not at the conference, hosted by the Department of Energy and the Sustainable Energy Council, to make any major announcements, with the industry waiting for word from her department on the applications to build regional “hydrogen hubs” around the country. (See DOE Opens Solicitations for $7B in Hydrogen Hubs Funding.)
While hydrogen is already used in applications ranging from refining oil to rocket fuel, and legacy firms such as Air Products and Air Liquide were well represented at the conference, the hope is for hydrogen to become what Granholm called the “Swiss Army knife” of the clean energy revolution.
The hubs are meant to help start building the future domestic industry by linking together regional supply and demand, which ideally will help provide a foundation for the fuel to become commonplace in global energy supplies.
“We expect these hubs will marry supply and demand so that we can be producing where the offtake is,” Granholm said. “And as I say, we’re very close to announcing those hubs.”
If the Biden administration’s goals for domestic, clean hydrogen production by 2030 are met, the U.S. would produce enough of the fuel to meet the same amount of energy used by every bus and train in the country, Granholm said. The 2040 goal would double that production to 20 million metric tons, while the 2050 goal would have the U.S. produce enough clean hydrogen to meet the equivalent energy demand of every bus, train, ship and plane in the country, she added.
Other countries around the world are ramping up their production of hydrogen, and Granholm said the U.S. would be happy to work with them.
“We need to develop uniform codes, uniform standards, to maximize safety to minimize harmful leakage,” Granholm said. “We need to ensure that emissions analyses are done consistently across regions and that certification measures are rigorous and practical, as well as transparent.”
Countries also need to work together to help create new markets for the fuel and get new sources of demand comfortable with using the fuel, she added.
The government’s plan to help grow hydrogen into a clean energy industry involves focusing first on strategic, high-impact end uses such as “hard to decarbonize” industries, heavy-duty transportation and energy storage, DOE Hydrogen Program Coordinator Sunita Satyapal said.
“Second is laser focus on reducing the cost,” Satyapal said. “Again, it has to be competitive from a market-sustaining perspective. And then third is focused on regional networks. So that’s where the hubs come in: How do we potentially co-locate large-scale production and use?”
As the industry develops, hydrogen will need to be shipped. One idea to do that is over pipelines, but no regulatory regime to site, construct and oversee that infrastructure has been developed. FERC Commissioner Allison Clements told the conference Wednesday that she has asked Congress to come up with a plan to regulate those pipelines.
“You want to have some sort of one-stop shop or coordinated effort at the federal level that allows for the responsible, effective and efficient facilitation of interstate pipelines,” Clements said.
For now the focus is on intrastate pipelines, with just 1,600 miles transporting hydrogen compared to 300,000 miles of interstate natural gas pipelines overseen by FERC. But as the industry matures, it will want to connect different states, so some kind of regulatory regime will be needed, Clements said.
Hydrogen molecules (H2) flowing through pipelines will be much smaller than methane molecules (CH4) and thus have an easier time escaping, said Steven Hamburg, the Environmental Defense Fund’s chief scientist.
That is an issue even for green hydrogen, which is produced exclusively by zero-emitting generation, let alone blue hydrogen, produced with natural gas and carbon capture, with the industry having to consider upstream methane emissions, Hamburg said.
“We have to remember that hydrogen is a potent, indirect greenhouse gas,” Hamburg said. “It roughly lasts in the atmosphere … about the same length as methane, and its potency is about half of methane. And unfortunately, we don’t know anything about how much is being emitted currently.”
NASA uses hydrogen for its rockets; Hamburg said that when the fuel is transferred to them, it can lose up to 13% of its volume being blown away in the atmosphere, so ensuring such releases are minimized when it becomes much more commonly used is vital. Measurement technology is only being developed now, and it is needed not just to track the small leaks along its supply chain but also to help avoid any accidents with the volatile gas, Hamburg said.
Hamburg has been deeply involved in EDF’s efforts to track natural gas leakage. When that work began, many doubted that it was actually happening, but with actual measurements, leakage has proved common.
“It’s really important to note when I first started talking with companies about this issue 13 years ago, everyone told me, ‘We wouldn’t waste product; we’re not emitting much methane,’” Hamburg said. “That simply isn’t true. I hear a lot of that from the hydrogen industry. I can’t say it’s not true because we don’t have the measurements. But it is a bit of caution.”
Supply-side vs. Demand-side Policies
The U.S. and EU have come at the problem of making hydrogen a major energy source, and addressing climate change, in the opposite directions, said Michel Heijdra, the Netherlands’ vice minister of climate and energy.
“The U.S. for certain reasons, of course, focuses on subsidies in the value chain, whereas Europe focuses on carbon pricing and setting certain obligations for that offtake,” he added.
Both are spending money to help stand up hydrogen and other decarbonization options, and ultimately Europe will need to focus on cutting the cost of the fuel to get wide adoption, while the supply subsidies alone likely will not be enough to have major industries adopt new fuels and equipment, he added.
The international community also eventually will have to come together to make some standards around hydrogen production so that customers can be sure they are getting what they pay for, said David Hart, partner at consulting firm ERM.
“We’ve learned, I think, from previous areas where we have not done this as well, in biofuels and other jurisdictions where it’s quite easy to game markets by taking a biofuel that’s produced somewhere and moving it,” Hart said. International agreements around hydrogen need to be structured carefully so that such gaming is not easy to do, he added.
High Costs Must be Cut
BP already uses hydrogen at refineries it runs around the world, but it uses traditional “gray” hydrogen, produced by natural gas without any carbon capture, said Vice President Tomeka McLeod.
“There still is quite a big gap between … the cost of gray hydrogen under levelized costs versus what you would see for clean hydrogen … even with the Inflation Reduction Act,” McLeod said.
The price gap narrows for blue hydrogen, but it is still big enough that customers might not see the benefit of switching to green hydrogen.
“A number of the industries that use hydrogen have very thin margins,” McLeod said. “If their customers are not willing to pay a premium, it’s going to be pretty tough to incent them to pay a premium.”
Fueling the electrolysis machines that can make green hydrogen is going to be difficult and expensive, leaving that business to a few firms that can actually deliver on the idea, said Intersect Power CEO Sheldon Kimber. Green hydrogen might need to be directly linked to renewable generation, especially given the difficulties of expanding the transmission grid.
“When you look at the scale of these kind of monster behind-the-meter renewables facilities, which is what we think is going to transpire here … 80% of that is the renewables,” Kimber said. “And so, you make a list of people who may have built a 500-MW-plus renewable facility in the U.S., [and] it’s very small list. You make a list of people who have delivered that in the last few years through the supply chain crisis, financing issues and all of that — that’s a much smaller list.”
Hydrogen in Transportation
While much of the focus on hydrogen recently has been on hard-to-decarbonize industries, many are pursuing its use in transportation — even in the light-duty vehicle segment where electric cars have come to dominate the clean space.
BMW has 25 electric vehicles available to consumers around the globe, but it is also considering adding light-duty hydrogen cars to its portfolio, said company representative Thiemo Schalk.
“There are studies coming from the European Union, and from Germany as well, suggesting that once you are coming close to a huge part of the car market being electrified, the costs for the infrastructure for the charging outlets [are] going to be increasing really, really sharply,” Schalk said.
The costs go up as the grid needs to be bolstered and clean resources are added to the mix to serve the new demand from cars, with estimates that Europe would have to spend $1.5 trillion to go 100% electric, Schalk said. But that comes down significantly if some percentage of the light-duty market is served by hydrogen or another alternative, which some customers will wind up preferring over EVs as well.
Going electric in the heavy-duty sector is more difficult because the current battery designs are too heavy, especially for airplanes, said Airbus Americas Vice President of Research and Technology Amanda Simpson. Airbus sees hydrogen as the main option for decarbonizing air travel and hopes to have a plane using it in service by 2035.
But the company is not yet sure whether that plane would use a hydrogen fuel cell or directly combust the gas in its engines, Simpson added. Getting liquid hydrogen on aircraft and doing it safely is also a focus of those developments, but hydrogen has major advantages over the alternatives.
Biofuels still produce pollutants when combusted, and batteries are just too heavy to have any impact outside of short-haul, local flights, she added.
Hydrogen Generation is Possible, but Expensive
The IRA has supercharged interest in hydrogen, with projects before it being much smaller, said Siemens Energy North America President Richard Voorberg. Before the law, Siemens was working on electrolyzers of about 18 MW, but it has scaled up and has plans for projects above 1 GW.
Those major projects are starting to roll out at once and eventually will lead to a backlog as the industry can only do so much at once, Voorberg said.
“The challenge is economics,” Voorberg. “And we don’t see the economics start making sense until probably 2035 at the earliest. So, we think things like decarbonizing industry, steel-manufacturing, chemicals, ammonia, fertilizer, transportation — all those go first [and] pave the way. And then eventually, the high price of hydrogen gets to the right position and then you can burn it in gas turbines for energy production.”
The U.S. solar market saw a 32% drop in new utility-scale megawatts installed across the country in 2022, but it could be heading for a record rebound this year, according to a new report from the Lawrence Berkeley National Laboratory (LBNL).
In the first seven months of 2023, utility-scale solar capacity was up 50% over the same period in 2022, with estimates of total installations hitting 24 GWAC, based on estimates from the Energy Information Administration, the report says.
The report defines “utility-scale” as grid-tied, ground-mounted projects of 5 MWAC or more. In 2022, total installations provided only 12 GWDC of new generation, the report says, citing figures from industry analyst Wood Mackenzie.
Even with the decline, utility-scale solar added the most new megawatts to the U.S. grid, accounting for 27% of new generation versus 22% each for wind and residential rooftop solar.
Those figures reflect the combined impact of evolving technologies and federal and state policies on the utility-scale market.
For example, the report attributes 2022’s decline to the double-whammy of U.S. solar tariffs — which President Joe Biden put on hold for two years in June 2022 — and a slowdown in imports due to the Uyghur Forced Labor Prevention Act (H.R. 6256), passed in December 2021.
The law bans imports from China’s Xinjiang province, where reports had surfaced of minority Uyghurs being used as forced labor. The province provides about 50% of all the world’s polysilicon, a key component of solar panels. Initial implementation of the law resulted in U.S. Customs and Border Protection holding thousands of shipments of solar panels, according to a Reuters report.
Release of the backlog began in March of this year, following a clarification of the rules, according to a subsequent Reuters report.
Looking ahead, the report sees additional market tailwinds, with PPA prices possibly falling as developers take advantage of either the investment tax credit (ITC) or production tax credit (PTC) in the Inflation Reduction Act (IRA). Solar projects previously were limited to the ITC, which the IRA reset at 30%, but the law also makes the PTC available, which in some instances may pencil out better, the report says.
Also, more than half of new utility-scale projects added to the grid through July 2023 are sited in what the IRA defines as “energy communities” eligible for 10% additions to the ITC or PTC. Energy communities, broadly defined, are areas that have been dependent on fossil fuel production and have lost jobs and tax revenue as a result of plant closures.
Projects built with single-axis tracking made up 94% of all new utility-scale solar in 2022, the highest percentage ever. | Lawrence Berkeley National Laboratory
Other trends detailed in the report include:
Almost all new utility-scale projects — 94% — added to the grid in 2022 were installed with single-axis trackers, which adjust panel position to follow the sun to increase solar output. Fixed-tilt projects are increasingly limited to sites with rugged or uneven terrain, such as landfills or brownfields, or with high winds.
Texas and California continued to lead the nation on new utility-scale solar in 2022, adding 2.4 GWAC and 2.1 GWAC respectively.
But the two states also led the nation in overproduction resulting in project curtailments. In Texas, ERCOT reported 2,797 GWh of solar curtailed in 2022, while CAISO curtailed 2,057 GWh.
Hybrid projects with solar and storage are steadily increasing. A record 26 new hybrid plants, totaling 2.2 GWAC were added to the grid last year, but the average duration of storage on these projects fell, from 3.2 hours in 2021 to 2.7 hours in 2022.
Power purchase agreements (PPAs) for utility-scale solar now average $25/MWh, up slightly from a 2019 low of $22/MWh but still competitive with wind and natural gas.
Interconnection And Value
President Joe Biden has set an aggressive target for the U.S. to decarbonize its electric power grid — and run completely on zero-emission energy — by 2035, while cutting emissions economywide 50% to 52% by 2030.
A growing number of reports and analyses are estimating that reaching these goals will require a dramatic ramp-up in solar generation. Released Wednesday, a report from industry consultants ICF sees solar going from 3% of the U.S. energy mix in 2022 to 16% in 2030 and 65% by 2050. The International Energy Agency’s recently updated road map to net zero by 2050 calls for a fourfold increase in solar and wind deployments worldwide.
Based on Wood McKenzie’s numbers, the LBNL sees new utility solar capacity increasing more than fourfold from 12 GW in 2022 to over 50 GW per year.
But here again, getting there will depend on a combination of economic and technical factors, first and foremost how quickly utilities and grid operators can upgrade their systems and processes to speed up interconnection.
The interconnection queues across the U.S. remain jammed with a total of 947 GW of solar, including 351 GW that were added to queues in 2022, according to LBNL. Hybrid solar and storage projects make up 457 GW of the total, the report says.
Western non-RTO queues are largest, with about 250 GW, followed by MISO (more than 200 GW) and PJM (more than 150 GW), according to the report.
interconnection queues at the end of 2022. The non-RTO West, MISO and PJM having the most solar waiting for interconnection. | Lawrence Berkeley National Laboratory
Another factor will be the impact of tariffs on solar panels imported from Cambodia, Malaysia, Thailand and Vietnam, which are scheduled to go back into effect when Biden’s moratorium ends in June 2024. While the IRA has triggered a growing number of announcements of new solar cell and panel plants in the U.S., Abigail Ross Hopper, CEO of the Solar Energy Industries Association, has said it could take three to five years to stand up a complete U.S. supply chain. (See Commerce Dept. to Reimpose Tariffs on SE Asian Solar Manufacturers.)
A possible counterbalance to any future tariffs, solar’s value to the grid is rising, compared to PPA prices, the report says. The market value of solar varies across different RTO and ISO service regions, ranging from $51/MWh in CAISO to $85/MWh in PJM and up to $108/MWh in some non-RTO areas of the Southeast.
“Since 2020, rising wholesale energy prices more than compensated for moderate PPA price increases, making solar more competitive than it has ever been across the nation,” the report says.
BOSTON — Massachusetts, Rhode Island and Connecticut have reached an agreement on coordinating the procurement of offshore wind, Massachusetts Gov. Maura Healey (D) announced Wednesday.
Healey touted the benefits of the multi-state agreement at the American Clean Power (ACP) Association’s Offshore WINDPOWER 2023 conference, stressing the importance of regional collaboration and the potential of the agreement to benefit ratepayers.
“Through this agreement, here’s what we’re going to do: Align our procurements to leverage our collective buying power, lower project costs and maximize benefits for ratepayers across the region and increase the efficiencies and reduce project risk for offshore wind developers,” Healey said at the conference.
The Massachusetts governor added the states collectively have the authority to procure up to 6,000 MW of offshore wind capacity. According to the memorandum of understanding (MOU), the state agencies will “work in good faith to ensure that multi-state bids are considered.”
Under the agreement, multi-state bids could be extended to just two of the states, or all three. Each of the states are in various stages of the RFP processes for new procurements. Massachusetts has issued the largest solicitation of the three states at up to 3,600 MW, with proposals due in January. (See Mass. DOER Issues Draft RFP for Region’s Largest OSW Solicitation).
“Regional collaboration through this three-states MOU will not only help in advancing offshore wind projects of large scale by securing cost-effective energy prices for ratepayers — but it also provides a significant opportunity for long-term economic development,” Rhode Island Gov. Dan McKee (D) said in a press release.
The announcement — and the conference that hosted it — come at a crucial time for the region’s offshore wind industry, as supply chain constraints and high interest rates have strained existing power purchase agreements (PPA).
On Monday, Avangrid and two Connecticut electric utilities announced the termination of the PPA for the 804-MW Park City Wind project (Conn. PURA 19-12-18, see Park City Wind to Cancel PPAs, Exit OSW Pipeline). Meanwhile, the Massachusetts Department of Public Utilities approved the termination of the SouthCoast Wind PPA on Friday (Mass. DPU 20-16, 20-17, 20-18) following the termination of the Commonwealth Wind PPA earlier this summer (Mass. DPU 22-70, 22-71, 22-72, see Commonwealth Wind PPA Cancellations OK’d).
Healey doubled down on the importance of offshore wind, calling it “an anchor for our state’s short-term and long-term success,” despite the recent industry challenges.
Several speakers at the conference praised the agreement. Pedro Azagra Blázquez, CEO of Avangrid, said the agreement is necessary and “very important,” in his remarks following Healey’s.
ACP called the agreement “a bold way to drive cost efficiencies for projects across a broad swath of New England while promoting economic growth, enhancing security and driving down energy costs.”
“Procurement at this scale is exactly what industry needs to solve some of its most pressing issues,” said Liz Burdock, CEO of the Business Network for Offshore Wind, in a statement. “Big scale drives real cost reductions, fosters a pipeline large enough for new manufacturing investments and should create enough certainty to entice developers and vessel owners to enter into framework agreements that would unlock capital sitting on the sidelines.”
Throughout the conference, speakers expressed both optimism about the long-term outlook for the industry and the concern that if the current round of procurements fails to produce meaningful results, supply chain issues could push back the in-service dates of the next round of projects into the 2030s. Such a delay could significantly hinder the ability of states to meet their emissions reduction targets.
Bob Grace, president of Sustainable Energy Advantage, called the multi-state agreement “somewhere between a very big deal and not a big deal,” noting that Massachusetts, Connecticut and Rhode Island previously participated in the joint procurement of renewable energy in 2015-16. The joint procurement resulted in a mix of land-based wind and solar projects, selecting proposals totaling 460 MW.
Grace said the experience was extremely unwieldy as each state’s laws and procedures became constraints on their neighbors and was a process that many involved vowed never to repeat. He said the announced offshore wind agreement appears to learn from that experience by coordinating procurements rather than jointly procuring. He added the benefits of the agreement will hinge upon how effectively the states can work together.
“There is no way for the New England states to hit their climate goals without offshore wind,” Grace said.
While many policymakers in the region have pushed to get as much offshore wind in the project pipeline as soon as possible to reduce emissions, Massachusetts Attorney General Andrea Joy Campbell (D) has expressed concern about the size of Massachusetts’ recent solicitation.
In her initial comments on the solicitation, Campbell said timing these procurements during a period of cost increases could leave ratepayers with inflated bills (Mass. D.P.U. 23-42). The state Attorney General recommended capping the maximum procurement at 1,600 MW instead of 3,600 MW, with smaller, more frequent procurements to follow the solicitation.
This strategy “likely would help moderate the pace of offshore wind procurement and protect ratepayers from the volatility in the current market,” Campbell said.
While announcing the states’ agreement, Healey stressed the importance of federal support for offshore wind to keep costs manageable.
“A critical piece of this is how we’re able to maximize federal funding,” Healey said, highlighting the administration’s application for an up-to-$250 million matching grant from the U.S. Department of Energy for transmission upgrades that would help connect offshore wind to the grid.
Healey called on conference attendees to help push the federal government for more support for the offshore wind industry.
“This is a federal administration that has purported to be about a clean energy transition,” Healey said. “Hold them accountable.
The Western Power Pool (WPP) on Monday floated a proposal to revamp transmission planning in the West with the aim of spurring development of the kind of large-scale transmission projects FERC’s Order 1000 process has failed to produce.
The proposal, which WPP laid out in a concept paper, envisions creation of a new group, the Western Transmission Expansion Coalition (WTEC), which would “explore a new approach for West-wide transmission planning that will result in an actionable transmission plan to address regional and interregional needs.”
The paper says that while the region’s current planning processes overseen by NorthernGrid in the Northwest, WestConnect in the Southwest and CAISO comply with FERC requirements, “the legal and regulatory structure upon which they were built is limited and has not resulted in the identification of new transmission solutions that result in transmission builds.
“The limited nature of regional planning also handicaps the broader West in developing inter-regional transmission solutions. To effectively address the collective needs of the grid for the future, transmission planning must be performed in a more holistic and coordinated manner, such that a plan for transmission expansion solutions can be optimized to meet a broader set of needs,” the paper says.
WPP spokesperson Kevin Langbaum told RTO Insider that participants in “informal” conversations that produced the plan included WPP, BPA, the Pacific Northwest Utilities Conference Committee (PNUCC), the Northwest & Intermountain Power Producers Coalition (NIPPC), the Public Power Council (PPC), PacifiCorp, Idaho Power, Portland General Electric, Snohomish PUD, Puget Sound Energy and clean energy advocacy group Renewable Northwest.
“At the request of leadership from the Bonneville Power Administration (BPA) in response to stakeholders’ urging and supported by leadership of several energy industry entities and utilities, an informal group formed to discuss approaches to address a widely recognized concern that current transmission planning frameworks in the West do not result in sufficient transmission solutions to support the needs of the future energy grid,” the WPP said in describing the proposal.
The concept paper defines an “actionable” transmission plan as one that would “enhance” regional and interregional reliability, “address economic efficiency and help states achieve their respective goals.” In the paper, “regional” refers to the NorthernGrid transmission planning area covering the Pacific Northwest and Intermountain West, where the proposal originated, while “interregional” denotes all three Western U.S. planning areas — CAISO, WestConnect in the Southwest and NorthernGrid — as well as BC Hydro and AESO in Canada.
Beyond the goal of creating an actionable plan that increases grid reliability and efficiency, the effort also would seek to improve “visibility and coordination” of planning across the West and “support” future cost allocation decisions, although the paper makes clear the WTEC “does not intend to formulate or prescribe a cost allocation standard” for projects.
The concept paper does not provide a technical scope for the effort but instead proposes to establish the structure that would define the scope of the effort.
“While this effort is focused on the production of an initial transmission plan, the WTEC envisions that the process could evolve into a durable, long-term function, including periodic updates and refreshed analysis,” WPP said in the paper.
Two Committees And A Task Force
The paper proposes the WTEC be organized into two committees and a task force to address technical matters around transmission planning.
At the top would be a Steering Committee “comprised of senior and executive leadership from diverse entities committed to the study effort” and “responsible for resolving and making major decisions to structure the transmission plan.”
“While the Steering Committee will make decisions informing the transmission plan, it also carries the responsibility to collaborate with other committees organized to support the effort,” the paper states.
The paper proposes the Steering Committee include representatives from NorthernGrid (including BPA and others to be named), CAISO, WestConnect (including WAPA and others), WECC, Canadian province transmission planning, NIPPC, Renewable Northwest, Interwest Energy Alliance, PNUCC, PPC and WPP. The committee also would include a “state” representative to be determined after consultation with the region’s states.
A Regional Engagement Committee (REC) would consist of representatives from various stakeholder sectors and would “be responsible for providing input and feedback on the approach for the transmission plan, as well as providing input on major decisions informing the transmission plan,” according to the paper.
The REC would consist of two members each from: the Steering Committee, federal power marketing agencies, non-federal power marketing organizations, independent power producers, independent transmission developers, public interest groups, ratepayer advocacy organizations, industrial electricity customers, state agencies and tribes. It also would include four members each from investor-owned utilities and consumer-owned utilities.
The paper also proposes a Technical Task Force that would identify transmission study scope and approach, “including but not limited to renewable energy zones, resource expansion, electrification and load data, and scenario development, including extreme event scenarios, phasing of study outcomes and recommendations, data protocols, etc.”
The task force would consist of technical staff from Steering Committee members, Pacific Northwest National Laboratory, the Northwest Power and Conservation Council, WPP, and merchant and independent transmission developers. It also would include an independent consultant with expertise in transmission selected by the Steering Committee.
The concept paper also outlines the intent for “periodic communications and public webinars to provide stakeholders from the public with input and feedback opportunities.”
WPP is seeking feedback on the proposal and has posed a series of questions for stakeholders regarding the proposed participation structure of the WTEC, the composition of its committees and its plans for broader engagement with the region. Comments are due by Oct. 31 and should be sent directly to WPP CEO Sarah Edmonds at sarah.edmonds@westernpowerpool.org.
BOSTON — The clean energy transition will require an all-out push on transmission planning and siting reform, government officials and energy experts told stakeholders on Friday, outlining some of the major challenges and opportunities of the region’s energy transition.
Several speakers at Raab Associates’ New England Electricity Restructuring Roundtable emphasized the importance of interregional and intraregional transmission planning to ensure the grid can handle increased amounts of variable clean energy and higher demand from electrification.
“Transmission planning is vital if we are going to deliver the clean energy transition,” said Mike Calviou, senior vice president for National Grid.
Calviou spoke about his experience working for National Grid in the United Kingdom, which has successfully deployed nearly 14 GW of offshore wind operational capacity, compared to just 48 MW in the U.S. He said the U.K. now is facing congestion issues on the transmission system, hurting both rates and the further deployment of clean energy.
To avoid escalating congestion costs in New England as offshore wind capacity increases, Calviou said the region should focus on anticipatory investment and coordinated planning, instead of the current just-in-time approach.
Maria Robinson, director of the U.S. Department of Energy Grid Deployment Office, outlined some of the federal funding opportunities available for transmissions projects, including the $10.5 billion Grid Resilience and Innovation Partnerships Program and the $2.5 billion Transmission Facilitation Program.
Robinson noted, however, that “throwing money at the problem is not necessarily the way to solve these issues around particular backlogs on the transmission system,” and called for a targeted approach rather than blunt force.
She highlighted the office’s work on National Interest Electric Transmission Corridors, which can increase funding opportunities and streamline the permitting process within designated corridors.
“When it comes to corridors, we’re taking a very different approach than the Obama administration,” Robinson said, noting that the approach of the Obama administration focused on designating “large swaths of land” as corridors. She said the current approach is more targeted, relying on developers and utilities to indicate exactly where corridors would be helpful.
“I think it will be both more legally defensible as well as useful to actually get some of these designated,” Robinson said.
Clarke Bruno, CEO of the transmission developer Anbaric, touted the potential benefits of an offshore grid to minimize the onshore impacts of deploying offshore wind at scale. (See Brattle Study Highlights Benefits of Offshore Grid.)
An ocean grid would be “costly, but less costly than the alternatives,” Bruno said.
Permitting and Siting Reform
Government officials from New York and Massachusetts also discussed permitting and siting reform, a topic which has been gaining steam in the commonwealth.
Earlier in the week prior to the conference, Gov. Maura Healey (D) signed an executive order creating a state Commission on Clean Energy Infrastructure Siting and Permitting to make recommendations on permitting and siting reform (See Massachusetts Announces Permitting And Siting Reform Commission.), while top legislators have indicated the topic is a key priority in the current legislative session. (See Checking in on Clean Energy at the Mass. Legislature.)
Houtan Moaveni, executive director of the New York Office of Renewable Energy Siting (ORES), spoke about some of New York’s recent successes in expediting the development of clean energy. The ORES was created by the legislature in 2020, consolidating the state’s siting and environmental review processes for large clean energy infrastructure.
Moaveni said the office has helped usher in the “most rapid pace of renewable energy project approvals in the state’s history.” He emphasized the importance of the preapplication process, creating clear guidelines for project developers and engaging with impacted communities early in the process.
“Building local support for these projects is just as important as getting regulatory approvals,” Moaveni said, adding that he has spent much of his time traveling to meet with communities to understand their needs and ensure local benefits — including discounted electric rates.
“It is possible to streamline and expedite the permitting process for generating facilities without undermining communities and environmental protections,” Moaveni said.
Elizabeth Mahony, commissioner at the Massachusetts Department of Energy Resources, said the newly created permitting and siting commission has “a lot of work to do.”
“Maybe we can take a couple of pages from New York’s playbook — if it’s a good idea, we’ll steal it,” Mahony said in response to Moaveni’s presentation.
Mahony doubled down on the state’s commitment to renewable energy development, singling out solar and offshore wind as key areas of growth. She highlighted a DOER report released in July on the potential for solar development that mapped solar potential across the entire state. The analysis found the state has the potential for about 50 GW of highly rated solar capacity.
“We can be strategic about where we deploy solar and how we deploy it,” Mahony said. “We think that this information… is really a tool that we can use, that municipalities that are facing a lot of permitting issues can use, and certainly that our utilities should be using as they are planning their grid upgrades.”
Another New England offshore wind project has gone off the rails.
Avangrid on Monday announced an agreement with two Connecticut electric distribution companies to terminate power purchase agreements for its Park City Wind proposal (Conn. PURA 19-12-18).
The 804-MW wind farm is “unfinanceable” under the terms agreed on, because of subsequent sharp cost increases, the company said. It hopes to rebid Park City Wind at more favorable terms.
Park City was an important component of Connecticut’s emissions reduction/climate protection planning, and Gov. Ned Lamont (D) expressed disappointment in the turn of events. The move will likely delay the arrival of offshore wind in the state, and almost certainly increase its cost to ratepayers.
It also is the latest in a yearlong series of setbacks for offshore wind in southern New England.
With its steady winds, shallow waters, nearby customer base and deepwater ports, the region had a pioneering role in launching the industry in the U.S. Now it is feeling the blowback as the industry struggles with supply chain constraints and soaring costs.
Avangrid this year negotiated a similar exit from its PPAs in Massachusetts for the Commonwealth Wind project, again because the financial terms were untenable (Mass. DPU 22-70, 22-71, 22-72).
The Shell/Ocean Winds joint venture SouthCoast Wind bailed out of its Massachusetts PPAs for the same reason; state regulators approved the termination agreement Friday (Mass. DPU 20-16, 20-17, 20-18).
Rhode Island’s most recent offshore wind solicitation drew just one bid — the Revolution Wind 2 proposal by Ørsted — and it was rejected as too expensive.
Ørsted still has not made a final investment decision on Revolution Wind 1, although it obtained federal approval for construction and operations in late August. The company is looking for incentives to improve the financials.
Massachusetts utility Eversource Energy is in the late stages of exiting the partnership with Ørsted that has resulted in multiple wind power proposals off the New York and New England coastlines.
Even the two bright spots in New England waters — construction starting this year on the nation’s first two utility-scale offshore wind projects — have not been without hiccups. WBUR reported Monday that Vineyard Wind is behind schedule because of a spate of rough seas and foul weather. Newsday reported Tuesday that South Fork Wind’s schedule is in flux because of issues with availability of a ship needed to complete the work.
New York and New Jersey offshore wind projects are struggling with the same headwinds as these New England projects, but none has progressed beyond threats of cancellations.
Park City Wind
Park City Wind’s exit erases much of Connecticut’s offshore wind pipeline — only 304 MW from Revolution Wind 1 remains.
Connecticut Department of Energy and Environmental Protection Commissioner Katie Dykes told NetZero Insider on Tuesday that Avangrid’s exit was an unwelcome development.
“Over the last several months, DEEP engaged Avangrid, and industry experts, to understand concerns about the economics of Park City Wind and the significant near-term challenges facing offshore wind projects in general,” she said via email. “We hoped to hear proposed solutions to enable the Park City Wind project to move forward while protecting Connecticut’s ratepayers and respecting our state’s commitment, embodied in statute, to conduct competitive procurements. Unfortunately, these discussions failed to materialize in a proposal that met these goals. DEEP is working with the state’s utilities to ensure that bidders into future solicitations — including our upcoming solicitation for offshore wind — are able to deliver completed projects at the prices they offer and face steeper penalties if they do not.”
Charles Rothenberger, climate and energy attorney for environmental advocacy group Save The Sound, said the financial pressures on wind power developers are real. The goal now is to preserve a viable offshore wind program without transferring too much of those pressures to utility ratepayers.
“Given the really substantial financial commitments these companies already have made … what it tells me is this was not simple gamesmanship on the part of the industry, if anybody thought that,” he told NetZero Insider.
Rothenberger added that the inflation adjustment mechanism included in the next solicitation should go both ways and require developers to refinance at a lower cost when interest rates decrease.
Avangrid addressed the situation in a statement Monday.
“One year ago, Avangrid was the first offshore wind developer in the United States to make public the unprecedented economic headwinds facing the industry, including record inflation, supply chain disruptions and sharp interest rate hikes, the aggregate impact of which rendered the Park City Wind project unfinanceable under its existing contracts.”
The company said it, stakeholders, and state and federal officials were unable to find common ground to preserve the PPAs.
Park City Wind LLC’s termination agreements with Eversource and United Illuminating Co. call for a combined $16.08 million in payments to the two utilities. That is substantially less than the termination penalties negotiated by SouthCoast ($60 million) and Commonwealth ($48 million) in Massachusetts.
Other Developments
In this challenging financial environment, offshore wind development in New England continues.
South Fork and Vineyard have said they plan to generate their first power this year.
Connecticut is preparing to issue a request for proposals for up to 1,196 MW of offshore wind — potentially larger than Park City, but not vastly larger. The solicitation had been scheduled tentatively for September.
The developers of SouthCoast and Commonwealth plan to bid into the latest (and largest) Massachusetts offshore wind solicitation, announced in August. As it ranks the bids on a points-based system, the state may penalize the two companies for bailing out on their previous agreements.
The Environmental Protection Agency issued its final preconstruction permit to Revolution Wind 1 on Thursday.
Rhode Island issued a Strategic Plan for Offshore Wind Jobs & Investment. Numerous offshore wind lease areas are clustered south of the Ocean State; state and business leaders hope to establish Rhode Island as an onshore hub for the offshore industry as it grows.
Rhode Island is taking another swing at drawing electricity from the industry as well. Gov. Dan McKee last week announced that the state’s largest electric utility, Rhode Island Energy, will issue a request for proposals this month for up to 1,200 MW of offshore wind capacity.
Each person quoted in the announcement stressed the word “affordability” — the issue that torpedoed the previous offshore wind solicitation.
“Rhode Island has big clean energy aspirations, and Rhode Island Energy is committed to helping achieve them,” said utility President Dave Bonenberger. “This new procurement can help advance the state’s clean energy goals and support achievement of Rhode Island’s emissions-reduction targets. We look forward to seeing how offshore wind developers can balance those goals with affordability and wider economic benefits for the state.”
A new toolkit from the National Association of State Energy Officials (NASEO) and the National Association of Regulatory Utility Commissioners (NARUC) aims to help state regulators grapple with cybersecurity concerns with distributed solar resources that “have not been fully addressed.”
The toolkit was produced by the Cybersecurity Advisory Team for State Solar (CATSS), which NARUC and NASEO launched in June 2020 with the U.S. Department of Energy’s Solar Energy Technologies Office. (See NARUC, NASEO Launch Solar Cybersecurity Resource.) CATSS includes experts on digital security, the electric grid and photovoltaic technologies, with leadership drawn from state-level policymakers and regulators and additional support from the federal government and private sector.
CATSS’ focus is on distributed solar because, as the document states, “less attention has been given” to it from cybersecurity efforts than to “legacy assets and bulk power” despite the “significant forecasted growth” of distributed energy resources as part of the overall generation mix. This attention deficit is particularly concerning because DERs rely on remote communication tools to a degree that traditional resources do not, meaning a successful cyberattack could lead to serious consequences.
“As the leaders in state energy policy and program development in support of their governors’ and legislators’ cybersecurity and DER goals, state energy offices are increasingly engaged in cybersecurity actions,” said NASEO President David Terry in a statement. “This toolkit will help states achieve their energy and resilience goals by creating more cyber-secure distributed energy resources.”
The kit comprises 10 tools divided into two areas of focus. The first is education and risk awareness to inform state energy officials and public utility commissions of the underlying issues around distributed solar and other DERs.
The category includes four documents. Photovoltaic solar engineering and system overview covers the components of a local solar panel network and their communication with each other and grid controllers. The Standards quick guide provides relevant standards from regulators like FERC and NERC, along with industry groups such as the Institute of Electrical and Electronics Engineers.
Assessing solar cybersecurity is a list of discussion prompts for energy officials and commissions to discuss cybersecurity issues with utilities. The final tool in the section, Hypothetical solar cyberattack scenarios and impacts, discusses “approachable, plausible scenarios of cyberattacks affecting [solar] assets and interconnected infrastructure.”
In the second set, NARUC and NASEO provide practical actions to address cyber threats. The Decision support tool for solar energy cybersecurity policy and regulation includes a probable risk assessment to help users understand the risks and ownership of a solar network’s physical assets. Next, the Case studies and model guidance tool assists states with forming working groups, a “critical first step to establishing state cybersecurity programs.”
In Cybersecurity and the solar workforce, the writers suggest competencies and skillsets that should be looked for in solar-related cybersecurity professionals, along with tactics that energy offices and commissions can use to encourage good hiring practices. Cybersecurity considerations for state procurement of solar assets offers sample language for procurement agreements, contracts and grants, as well as models for setting up state solar cybersecurity practices.
Exercise design guidance for solar cybersecurity provides recommendations for designing energy emergency exercises, drills and other solar cybersecurity-focused simulations. Finally, the last tool approaches the cybersecurity issue from the perspective of state legislatures, offering example bills for “states seeking legislative options to help mitigate these risks.”
The Texas Supreme Court has agreed to review a lower court’s invalidation of the Public Utility Commission’s emergency pricing orders during the deadly 2021 winter storm, potentially placing billions of dollars of transactions at stake.
The state’s high court granted the PUC’s petition for review Friday and set oral arguments for Jan. 30, 2024 (23-0231).
The commission in March asked the court to review the decision, reverse the judgment and either dismiss the case or rule in the PUC’s favor. It said the orders it issued expired years ago and therefore cannot be voided, and said the commissioners made “split-second decisions” necessary to help correct a market failure. (See Texas PUC Appeals Court’s Decision on Uri Transactions.)
The PUC filed its petition shortly after the 3rd Court of Appeals reversed two commission orders to keep the market’s wholesale prices at the $9,000/MWh cap during Winter Storm Uri. The court found the commission’s actions “entirely” eliminated competition and were contrary to state law. It remanded the case for “further proceedings consistent” with its ruling.
The actions resulted in $16 billion of market transactions that ERCOT’s Independent Market Monitor said were incorrectly priced during the 33 hours that followed once the grid operator stopped shedding firm load. The PUC declined to re-price the transactions. (See “Monitor: $16B ERCOT Overcharge,” ERCOT Board Cuts Ties with Magness.)
Some of the $16 billion balance has since been securitized and some participants have been paying off debts they now might not even owe. Other transactions have been settled outside ERCOT and can’t be undone, according to legal expertise.
Luminant Energy, Vistra’s generating subsidiary, filed the appeal with the 3rd Court and has been joined by Exelon. They say the commission exceeded its authority in allowing the high prices while the ERCOT grid was trying to find generation after more than 50 GW of resources were knocked offline by the storm.
Calpine, Talen Energy and TexGen Power are among the generators that support the PUC’s position.
Battery energy storage systems (BESS) may be vulnerable to the same systemic performance problems seen in several disturbances in solar generators and other inverter-based resources (IBR) over the past few years, according to a joint report released by NERC and WECC on Monday.
The 2022 California Battery Energy Storage System Disturbances report concerns two events that occurred in Southern California last year and resulted in the loss of significant amounts of BESS in the region. According to NERC and WECC, they are the first major grid events to involve battery facilities and demonstrate why grid planners “need to consider these systems in the same light as any other” IBR.
The first event began just after 6 p.m. Pacific Time on March 9, when a generator circuit breaker at a natural gas-fired simple-cycle facility in Riverside County, Calif., suffered an internal failure, causing a generator bus fault. Generator units relayed and disconnected the natural gas generators, which were producing 694 MW, and the fault was cleared after about 4.5 cycles.
At the same time, IBRs at several facilities unexpectedly reduced output by a collective 408 MW. 124 MW of this reduction was attributed to BESS. As a result, the total generation loss topped out at 1,102 MW and system frequency dropped to 59.916 Hz. In response, CAISO raised regulating unit output, and frequency returned to normal in three minutes.
The second event began at 3:06 p.m. PT when a B-phase-to-ground fault occurred on a 220 kV bus at a new BESS plant that was still undergoing testing. While the fault was cleared normally in about four cycles, it caused a further unexpected reduction of output from multiple IBRs — including both battery and solar facilities — totaling 498 MW. CAISO again raised regulating unit output to assist in the recovery from the frequency nadir of 59.924 Hz, and frequency returned to normal in one and a half minutes.
Three BESS facilities were involved in both events: a 66-MW facility containing 29 inverters, a 250-MW facility with 88 inverters, and a 70-MW hybrid solar and BESS facility with 13 battery inverters. In addition, the April event involved an additional BESS unit rated for 115 MW and containing 45 inverters.
Causes of Reduction Unclear
NERC and WECC identified inverter AC overcurrent tripping and unbalanced AC current tripping as the cause of reduction for two of the battery facilities involved in the March event. The reduction in the third battery plant was caused by DC bus voltage undervoltage for two of the 13 inverters involved. Investigators have been unable to determine the reason the remaining 11 inverters tripped.
Determining the reason for reduction in the April event was more difficult because of incomplete data from three of the four BESS facilities involved. However, investigators concluded that in one of the plants — which suffered reductions in both events — inverters tripped due to a mix of AC overcurrent tripping, unbalanced AC current tripping, DC bus unbalance, half bus DC voltage max, DC bus overvoltage and high AC voltage.
According to records, five inverters tripped in the plant that was involved in only the April event. Three tripped because of unbalanced AC current protection; the cause of the other trips is still unknown. However, the report suggested record quality may still be an issue because the output of the five inverters that tripped “does not add up to the total 26 MW lost.”
The cause of tripping could not be determined for the remaining two plants because of faulty recording at one facility and a lack of metering data for the other, which is part of a multiphase project for which data at individual plants was not available.
NERC and WECC recommendations for utilities include checking for causes of tripping identified in both this and previous IBR incident reports. Generator owners should even check for causes of tripping in incidents that did not involve BESS facilities; the ERO explained that “causes … associated with solar PV resources” had been found in the most recent incident as well.
The report also warned that transmission owners and GOs should assess BESS ride-through performance during the interconnection process, while transmission planners and planning coordinators should also “conduct ride-through performance assessments … and confirm that installed equipment, performance and capabilities match those in the studied models.” NERC plans to assess the quality of performance modeling for the affected facilities.
Finally, NERC and WECC warned that the lack of data on the incident made deep analysis of the event challenging. The report noted that none of the facilities involved met CAISO’s 10-millisecond recording data resolution requirements. Other “significant data quality issues” included a lack of individual facility metering, inconsistency between BESS data and CAISO data, and the tendency of monitors at several facilities to freeze recording at the onset of the fault.
IBR Issues Continuing
While the March and April events are the first significant disturbances on record involving battery facilities, the ERO has long been familiar with the sometimes-unexpected behavior of other IBRs like wind and solar generators. Just last month, NERC and WECC released a joint report on a Utah event in which nine solar facilities lost a total of 921 MW of generation. (See NERC Utah Event Report Underlines Ongoing IBR Issues.) Previous reports have detailed multiple similar events in California and Texas. (See NERC, WECC Repeat Solar Performance Warnings.)
“These events are the first faint signal that the systemic performance issues we have identified with other inverter-based technologies may very likely apply here as well,” Ryan Quint, NERC’s director of engineering and security integration, said in a statement. “Battery … systems will play a critical role during the energy transition; therefore, it is imperative that we design, study, commission and operate them in a manner that supports [grid] reliability.”
