Hydrogen-powered fuel cell maker Plug Power (NASDAQ:PLUG) sees green hydrogen made from water as the fuel of the future and has announced its plans to become the nation’s largest producer of hydrogen, as well as a builder of fuel cells for cars, trucks and stationery power.
Sanjay Shrestha, Plug Power | Plug Power
“We’re starting construction of three [hydrogen] plants this year: two with the nameplate capacity of 15 tons per day [and] and one with 45 tons per day,” Sanjay Shrestha, Plug Power chief strategy officer, told about 5,000 people who tuned in to the company’s third annual symposium held virtually Thursday.
The company plans to have 70 tons/day of capacity by the end of 2022, 200 by 2023 and “well on our way” to 500 by 2025, produced by 13 plants located across the U.S. on sites close to wind and solar installations, Shrestha said.
Currently less than 2% of the hydrogen used in the U.S. is made through the electrolysis of water and is very expensive. Most hydrogen used in industrial process and oil refining is made from “steam methane reforming,” a high-pressure, high-temperature process that also produces carbon dioxide.
Plug expects demand for green hydrogen to soar as governments and corporations chart new courses to lessen carbon dioxide emissions in efforts to avoid accelerating global climate change. The company thus sees opportunities in transportation and heavy industry, including refineries, where most of the hydrogen made from methane is used today. And it believes its hydrogen-powered fuel cells can serve as clean and quiet backup generators at huge data centers that are already trying to replace diesel generators with massive battery systems.
Shrestha said Plug envisions hydrogen being transported long distance via pipelines. “When we build this first-of-a-kind green hydrogen generation network, this will also help accelerate demand for many new fuel cell applications … because this will actually ensure that hydrogen is going to be available all the time.”
Plug’s planned rise as a major player in hydrogen and fuel cell generation will involve a number of mergers and acquisitions, moves that can make investors nervous. In just the past two weeks, the company announced mergers with or acquisitions of key companies crucial to transforming itself from a maker of small fuel cells for warehouse fork lifts into a global conglomerate producing both hydrogen and much larger fuel cells.
Just hours before the symposium began, the company announced it had signed a “definitive agreement” with Applied Cryo Technologies, a Houston-based maker of technology to transport, store and distribute liquefied hydrogen, as well as other industrial gases, at cryogenic temperatures.
During the symposium, the company unveiled a hydrogen fueled delivery van with a 300-mile range that Renault will begin manufacturing in 2022, using a Plug fuel cell.
Also Thursday, the company announced it had signed a letter of intent for a 50-50 joint venture with Fortescue Future Industries (FFI) to build a large factory in Queensland, Australia, that will “produce large-scale proton exchange membrane (PEM) electrolyzers, with the ability to expand into fuel cell systems and other hydrogen-related refueling and storage infrastructure in the future.
“Plug Power will supply the electrolyzer and fuel cell technology, and FFI will contribute advanced manufacturing capabilities. FFI will be the primary customer of the products manufactured by the joint venture, enabling its ambitions in decarbonizing its operations with stationary power and mobility applications running on green hydrogen,” Plug said in a press release.
On Wednesday, the day before the symposium, Plug announced deals with European aircraft contractor Airbus to study the use of the company’s fuel cells in aviation. Also, it announced that it had signed a “memorandum of understanding” with Phillips 66 “to collaborate on the development of low-carbon hydrogen business opportunities.”
Phillips operates 16 refineries in the U.S. and Europe and uses hydrogen in those operations. It also supplies gasoline to retail and wholesale markets.
Earlier in October, Plug announced it had formed a joint venture with SK E&S, part of South Korea’s SK Group, “designed to accelerate the use of hydrogen as an alternative energy source in Asian markets.”
“The two companies will collaborate to provide hydrogen fuel cell systems, hydrogen fueling stations, electrolyzers and green hydrogen to the Korean and other Asian markets,” Plug said in a release.
Plug Power CEO Andy Marsh | Plug Power
In what appeared to be a videotaped conversation with Plug CEO Andy Marsh, Ji Young Li, a senior vice president with SK, said the company was planning to spend $16.5 billion “to build a hydrogen eco system in South Korea by 2025.”
The company is investing $1.6 billion in the deal with Plug, she said. “And we thought that with [your] capability of integrating things, we thought that there would [a need for] new technologies going forward. We like the flexibility. That’s why we reached out to you.
“And I think the combination of our skill sets will position us in a unique manner. We’ll have all the technology available throughout the value chain starting with electrolyzers and fuel cells and refueling station solutions, and potentially liquid hydrogen as well,” she said.
Marsh concluded the symposium by asserting that “this company is building the green hydrogen highway. … And no one has made as many fuel cells that have to really work.”
Sheep grazing on solar array lands has been a successful approach in agrivoltaics, but the possibilities are growing for pairing solar with beekeeping, crops and even cattle.
Co-developing agricultural practices and solar has an “incredible amount of potential,” Lexie Hain, executive director of the American Solar Grazing Association (ASGA), said Tuesday at the annual Renewable Energy Vermont conference.
“Sheep and solar are absolutely the most predominant agrivoltaic integration in the U.S. and surely globally,” she said, adding that the practice is “straightforward.” The herd’s vegetation maintenance prevents crops from creating shade on solar panels, and the array infrastructure doesn’t need to be modified to accommodate sheep.
Studies show that the sheep that graze at solar sites don’t have to compete for shade, so they drink less water and have lower stress levels, according to Hain. Their grazing activity also benefits local plant species, with one new study pointing to the biodiversity at grazed arrays being higher than mowed arrays, she said.
In the U.S., there are about 12,000 acres of grazed solar, according to Hain, but she said there are other “big, forward thinking” opportunities for agrivoltaics.
The University of Minnesota studied the effects of grazing cattle in the shade of solar PV systems, Hain said. That study concluded that, while more research is needed, agrivoltaics may reduce the stress from heat on dairy cows and increase their wellbeing.
Solar developer Silicon Ranch, which is a Royal Dutch Shell (NYSE:RDS.A) company, received a U.S. Department of Energy grant this year to study cattle and poultry at the company’s arrays, according to Hain.
In particular, she said, the company is studying the necessary modifications of solar panel racking systems to accommodate cattle.
Another area of “meaningful” agrivoltaics research that Hain sees growing is pairing vegetable crops with solar. The University of Arizona (UA), University of Massachusetts and Oregon State University are all engaged in solar and crops research, she said.
A group of universities that includes UA will work on a project funded by a $10 million, four-year U.S. Department of Agriculture grant announced Oct. 6. The “Sustainably Co-locating Agriculture and Photovoltaic Electricity Systems” project will focus on increasing crop yields, productivity and farmer profits with row, specialty and forage crops.
Putting bee colonies on solar array sites has grown from the level of hobbyists to large-scale beekeepers, according to Hain.
“There are a number of commercial beekeepers in the U.S. and one in Canada who have worked to formalize the process by which beekeeping can be a viable practice to produce a value-added solar honey, and in so doing, gain lands that are accessible 24/7 to them that typically are managed with low or no herbicide use,” she said.
ASGA recently worked with the American Beekeeping Federation to create a solar beekeeping contract.
“We wanted to understand the agricultural viability of this for our solar beekeepers, and we wanted to provide a structure and framework for our solar companies and hosts to understand what the financial expectation and obligation is,” she said.
The contract sets out the basis for which a solar landowner might pay a beekeeper for maintaining an apiary on the solar site. In some cases, co-locating the apiary and solar array would allow the site to qualify as land used in agricultural production under state regulations. The Solar Massachusetts Renewable Target program, for example, offers an additional incentive to solar developers for productive agricultural activity at their projects.
“Most of the states in the Northeast are importers of honey, and this could be another opportunity for value-added production at solar arrays,” Hain said.
Nordic Farm
Vermont entrepreneur Will Raap is using his vision for solar to help Vermont’s ever-shrinking dairy farms. He wants to make his latest project, Nordic Farm, “the most carbon-negative farm in Vermont.”
Part of that vision includes using agrivoltaics to create a profit stream for the dairy farm, which went through bankruptcy four years ago. Raap purchased the farm earlier this year and is planning to build up to 5 MW of ground-mounted solar on marginal, abandoned pastureland and grow berries on the site.
“We’re working with a beverage company, called Shrubbly, to grow aronia, currents and elderberries between the solar panels, which we could harvest for their product,” he said during the conference.
Hinesburg-based Shrubbly produces a sparkling water drink flavored with organic fruit, herbs and spices.
The project team also plans to study the ecosystem benefits of the site, including, for example, carbon sequestration, water retention and pollination.
If Vermont is to realize the emission-reduction targets set by the 2020 Global Warming Solutions Act, Raap estimates the state needs to build between 150 and 300 MW of new solar every year for the next decade. That capacity would require 1,000 to 2,000 acres of land beyond brownfields and the built environment, Raap said.
One solution, he said, could be to repurpose marginal and abandoned farmland that has low or no economic value, especially if the land is on economically stressed dairies.
If Raap can demonstrate how to build multiple income streams with solar and agriculture at Nordic Farm, the project would be a valuable model for other dairies.
“Farmers [can] de-risk their farming situation with diversification in their agriculture, not only to produce more income from renewable energy but to reduce their energy footprint and make them a more carbon-negative farm,” Raap said.
California needs another 1.1 million electric vehicle chargers in public areas to meet its transportation decarbonization goals, but the process for building EV charging facilities is slow and expensive compared with other states, making reaching the goal more difficult, developers said in a workshop last week.
The joint meeting of the California Energy Commission (CEC), the California Public Utilities Commission (CPUC) and the Governor’s Office of Business and Economic Development addressed the need to greatly accelerate the growth of EV charging infrastructure in the next eight years.
The state requires nearly 1.2 million public EV chargers by 2030 to support light-duty EVs and meet its greenhouse gas (GHG) reduction goal and clean energy mandate, the CEC estimates. But only 75,000 chargers are installed in shared, public locations, it said.
“We need a massive scale-up,” CEC Commissioner Patricia Monahan said, adding that “bottom line, we need to move quickly to [build] zero emission vehicle infrastructure.”
Without adequate charging infrastructure, the state will have trouble meeting the goal set by former Gov. Jerry Brown of having 5 million EVs on the road by 2030, and Gov. Gavin Newsom’s executive order that all new passenger vehicles sold in-state must be emission-free by 2035. (See Can California Meet Its EV Mandates? and California Needs Huge Number of EV Chargers.)
Under Senate Bill 100, signed by Brown in 2018, utilities must provide retail customers with 60% renewable energy by 2030 and 100% zero-emissions energy by 2045. The state’s legislatively mandated GHG targets include reducing emissions 40% below 1990 levels by 2030.
Developers said for adequate charging infrastructure to be built, the process of getting new charging sites approved by local planning authorities and connected by utilities needs to speed up.
“In California, a new-service utility interconnection takes an average of 39 weeks or nine months to complete, in our experience, having built more than 200 stations today,” said Matthew Nelson, director of government affairs for Electrify America, the largest network of fast-charging stations in the U.S.
“The utility process for constructing the interconnection, the line extension and dropping the transformer … takes an average of 27 weeks, or more than six months, to complete,” Nelson said. “As a result, building stations in California costs 34% more for the exact same station than it costs us to build the same station in any other states.”
The state has invested vast sums toward charging infrastructure in its effort to reduce emissions and electrify the transportation sector, which is responsible for 40% of GHGs in California, with passenger vehicles accounting for about three-quarters of the total.
The most recent state budget allocated $1.2 billion over three years to promote consumer adoption of ZEVs, including $300 million to close the projected gap through 2025 in light-duty charging and fueling infrastructure. (See Calif. Earmarks $3.9B for ZEVs Through 2024.)
The CPUC and CEC have approved large sums to develop and accelerate charging infrastructure. The CPUC authorized the state’s investor-owned utilities to recover $1.85 billion in costs related to EV charging efforts. And the CEC has provided grants of $100 million per year since 2008 for zero-emission vehicle charging and fueling through its Clean Transportation Program.
Disadvantaged Communities
Installing charging sites in low-income communities and apartment complexes so that EV adoption spreads beyond wealthier residents has been a significant part of those efforts.
“As we increasingly broaden deployment to all segments of society — which we can do, and which we must do — getting infrastructure in place is critical,” CEC Commissioner Clifford Rechtschaffen said.
“We’ve prioritized having equitable access to transportation electrification by directing very significant portions of utility investment to disadvantaged communities,” Rechtschaffen said. “That has a great benefit of reducing pollution burden in those areas that need it the most, and we’ve also focused on underserved areas of the market, where the private sector hasn’t stepped in and where we need ratepayer-funded utility investment.”
Installing chargers in disadvantaged communities has proven slow and frustrating, said Paul Francis, CEO of charging manufacturer and software developer Keep it Green Tech. The company has worked with churches in South Los Angeles and other areas to install fast chargers in their large parking lots for use by parishioners and neighbors.
“What we’re noticing in frontline communities are that tier 3 level [fast-charging] projects — you’re looking at 1,500 kW or more — are a lot more challenging and a lot more stringent when you’re talking about the permitting and interconnection process, and interconnection has a lot to do with the permitting process for us,” Francis said.
“For example, it’s taken almost two years to get someone to come out to one site just to check if a pole can be put in place where there’s no power,” he said. “And see, often what’s happened in the past is these communities, these frontline communities, their local grid was never designed for uptake of this type of power capacity. And even though some aren’t affluent areas … a community sense of urgency pushes [for EV charging].”
Rebates and incentives could help, but often by the time we “finally get someone to come check out if we can do it,” the rebate funds have been exhausted, he said. The state needs to set aside funds specifically for fast-charging projects in underserved communities “so that they can participate in the future as well,” Francis said.
The Honolulu Authority for Rapid Transportation (HART) last week was granted an additional $7 million in legal funds to aid in a dispute with Howard Hughes Corp. (HHC) over a parcel of land needed for a 20-mile light-rail project slated for completion in 2031.
The funds are for an eminent domain dispute between HART and HHC subsidiary Victoria Ward. HART requires a two-acre parcel of HHC-owned land in Honolulu’s Kakaako district for a rail station and guideway for the project.
At a meeting last Thursday, the state’s Project Oversight Committee approved two recommended contract amendments to provide an additional $7 million in legal funds toward the land dispute, now totaling $23.3 million. The amendments provide retainers to law firms Starn O’Toole Marcus & Fisher and Nossaman. Any unused funds will be returned to HART.
HART initiated condemnation proceedings against HHC in December 2017, offering roughly $13.5 million in compensation for the parcel. HHC claimed the land was worth far more, initially demanding more than $100 million and now seeking $200 million, according to slides presented at the meeting.
HHC plans to use the disputed parcel for its mixed-use Ward Village project, which is being developed in part because of the expected increase in property values from the rail project’s construction.
“We certainly hope not to use all of [the funds] if we can get some of the claims eliminated. Hopefully that will make the case go faster, but it’s hard to tell at this time,” HART COO Rick Keene said at the meeting. So far HART has filed 13 court motions in the proceeding and HHC six.
A trial in the proceeding had been set for August 2021; however, the COVID-19 pandemic has delayed the date to May 2022.
HART’s rail project is part of the state’s push to become carbon neutral by 2045. The electrically powered line will draw on renewable energy projects the state is aggressively building and is intended to reduce dependency on imported energy sources. HART estimates that the line will reduce energy demand by 3% annually, the equivalent of 5.9 million gallons of gasoline. It is projected to take 40,000 cars off the road every day.
Global energy technology company Enapter won the Earthshot Prize in the Fix Our Climate category on Sunday for its anion exchange membrane (AEM) electrolyzer that makes green hydrogen from renewable energy.
The company was one of five winners to receive $1 million to advance their innovative climate solutions in the Earthshot prize competition launched by Prince William, Duke of Cambridge, in 2020.
“Each year for the next 10 years, we will award five prizes, one for each Earthshot, to those who are bringing hope for our future, and can protect and restore nature, revive our oceans, clean our air, build a waste free world, and fix our climate,” Prince William said in an opening speech for the award ceremony in London, broadcast by Discovery on Facebook Live.
Vaitea Cowan co-founded Enapter with the team behind the Phi Suea House, a project in Thailand that relies solely on solar and hydrogen for its energy needs.
The company says its invention is the “first scalable electrolyzer that replaces fossil fuels with green hydrogen” and will turn water electrolysis into “a universal and affordable product.”
“Winning this prize is recognition that we are going in the right direction,” Cowan said in an acceptance speech. “It will support us to go into mass production, it will boost us towards our goal of accelerating the access of green hydrogen for everyone, and it will significantly cut fossil fuel use by 2030.”
Build a Waste-free World
The City of Milan, Italy, won the Build a Waste-free World prize for its system that redistributes surplus food to help people in need and reduce greenhouse gas emissions from rotting waste.
Each food waste “hub” can deliver 130 metric tons of food annually to thousands of Milan residents, according to the city.
“The prize means both recognition and also a greater motivation to halve food waste by 2030,” Vice Mayor of Milan Anna Scavuzzo said in an acceptance speech. “Milan already shares food solutions with other cities all around the world, and winning this prize means we can do more for our community, but also help other cities to follow our example.”
Clean Our Air
The Clean Our Air prize went to an India-based company called Takachar, which has a mission of reducing the amount of agricultural waste that farmers burn after harvesting their crops.
The company developed a low cost, smokeless machine for use in rural communities to process and convert agricultural waste into usable products, such as fuels and fertilizers. Co-founder and CEO Vidyut Mohan says farmers can earn extra income by selling the valuable products.
“This award will help us tailor solutions worldwide and help us realize our vision to reduce air pollution, while creating livelihood opportunities for rural communities,” Mohan said in an acceptance speech. “In some parts of the world, air pollution reduces the life expectancy of the population by up to nine years, and we all need to stop ignoring this problem and act now.”
Revive Our Oceans
Best friends and business partners Sam Teicher and Gator Halpern won the Revive Our Oceans prize for their business Coral Vita. The company, which is based in the Bahamas, farms resilient corals and puts them into reefs to help bring back reef ecosystems that are collapsing. The co-founders say that their technique allows them to grow corals 50 times faster than they do in nature.
“This is an idea that Gator and I had while in grad school, and with the Earthshot prize, we will now be able to launch massive coral farms in every nation with reefs around the world and kickstart a restoration economy,” Teicher said in an acceptance speech.
Teicher called on government leaders, industry and media to solve for climate change and habitat destruction, saying, “the best thing to do for reefs is to stop killing them.”
Restore Nature
A program that provides landowners with incentives for protecting and restoring forests earned the Republic of Costa Rica the Restore Nature prize. The Costa Rican Ministry for Environment created the program to reverse an economic model in the country that encouraged farmers and landowners to cut down trees.
“The majesty of our forests is the seed of our developing model,” President of Costa Rica Carlos Alvarado said in an acceptance speech. “We will continue recognizing nature as our most valuable asset for advancing towards a carbon-neutral world.”
The next step for the government, according to Alvarado, is ocean conservation.
Earthshot 2022
Concluding the event, Prince William announced that the 2022 Earthshot award ceremony will be held in the U.S. “For the second year, we need to pass the baton to a country whose leadership is essential for all five of our Earthshots,” he said.
John Kerry, the U.S. Special Presidential Envoy for Climate Change, accepted the invitation in a message during the ceremony.
“The finalists and winners that we’ve recognized this evening remind us that we do have an incredible ability to turn the improbable into reality, if we work together as part of our commitment to repair the planet,” Kerry said.
BOSTON —
The development of marshalling areas is posing a critical infrastructure challenge for the offshore wind industry, hindering state and federal clean energy goals.
As it currently stands, port marshalling area can only meet half of the potential OSW demand, according to an assessment of OSW port infrastructure and deployment methods conducted by energy policy analyst Sara Parkison, a Ph.D. candidate at the University of Delaware.
Parkison presented her findings at the American Clean Power Association’s Offshore WINDPOWER 2021 conference in Boston on Thursday, highlighting the need for “forward-looking port and vessel designs that will allow for more efficient and cost-effective deployment.”
Architectural and engineering advancements in design will be necessary to meet the Biden administration’s plans for deploying 30 GW of OSW by 2030.
But marshalling ports, or large waterside sites with the acreage and weight-carrying capacity needed to assemble, store and deploy OSW wind turbines are difficult to site. Viable land along the East Coast is often already developed as lucrative residential property, Parkison said.
A 1-GW project can use up to 54 acres of space over two years, according to the report.
Other viable areas may not have the overhead access from port to sea to transport 12-MW and 15-MW turbines or channels deep enough for the vessels that carry them out to sea. Much of the remaining undeveloped land is protected for conservation, Parkison said.
Existing marshalling ports in Europe designed for the mass deployment of OSW turbines are much larger than the collection of smaller ports in the U.S. currently designated for the same purpose. The total area of the top three European marshalling ports are three times the size of all U.S. ports.
The U.S. could build a large port like the ones in Europe with the right amount of investment, Parkison said.
“But we need to build where we can, even if it is multiple small ports,” she said.
U.S. ports will also need to develop better ways of storing the components so they use up less room, said Jay Borkland, board chair of the Business Network for Offshore Wind, in a panel discussion.
Tower sections will have to be stored closer together and blades will have to be stacked tighter in the U.S. ports than the European ports, Borkland said.
“There is also a huge need for funding specifically for port development,” he said.
The Biden administration’s 30-GW goal will spur $12 billion in capital investment in OSW annually, including up to $500 million in port upgrades.
Marshalling ports are more likely to qualify for federal funding if developers work with state departments of transportation and improve ports and the efficiency of any freight coming in and out of the area, said Travis Black, team lead of port development and intermodal planning for the Maritime Administration under the U.S. Department of Transportation.
“The executive order for tackling the climate crisis at home and abroad has really extended opportunities for the federal government to use the climate action plan so the states, regions and local governments … can look at the renewable supply chain” for funding opportunities, Black said.
In my last column[1] I discussed the importance of retaining participant funding for generation interconnection — a long-standing foundational principle in all the RTOs. It ensures economic siting of new generation and thus economic deployment of new resources. It is fundamentally fair as new generation benefits from existing transmission “headroom” paid for by others, just as new generation may create new headroom used by others in the future. I also explained how a study by the ICF consultancy, purporting to support the end of participant funding, actually supports the opposite conclusion. Finally, I showed that FERC’s reasoning given in its Advance Notice of Proposed Rulemaking (ANOPR) on transmission planning for ending participant funding had four fatal flaws (RM21-17).
Another Day, Another Study
On the eve of the due date for filing comments on the ANOPR another study appeared. This one also paid for by the renewable energy industry, with the Brattle consultancy the lead author. (See New Tx Study Calls for Holistic Planning Across Regions.)
I will spare you point-by-point commentary on Brattle’s 105 pages (some of which I actually agree with), but I do want to address the study’s focus on a recently released PJM offshore wind analysis. This Brattle study, like the ICF study I previously discussed, does not undercut the case for participant funding. As I explain in (agonizing) detail below, the crux of the matter is that Brattle uses a number for transmitting offshore wind that does not include the cost of delivering the wind to onshore, inland substations.
Into the Weeds!
Brattle says individual PJM interconnection studies of offshore wind show network upgrade[2] costs of $6.4 billion to interconnect 15.5 GWs.[3] Per the math Brattle says this is more than $400/kW to interconnect new offshore wind.
Brattle then contrasts that with a recent, single PJM analysis showing network upgrade costs of $3.2 billion to interconnect 17 GWs.[4] Per the math this is $188/kW to interconnect new offshore wind.
Aha! Brattle says. Studying project interconnections individually costs more than double ($400/kW v. $188/kW) than when using a “proactive region-wide study.” A poster child for “holistic” planning!
Being a glutton for punishment, I waded through the 59 offshore wind interconnection studies posted on the PJM website,[5] and reviewed the PJM analysis and its history.
Let’s Start with New Jersey
The biggest flaw in the Brattle study concerns the New Jersey numbers. There, individual interconnection studies for active (not withdrawn) projects[6] show network upgrade costs of $3.3 billion to interconnect 7.4 GWs. In contrast, the PJM analysis shows network upgrade costs for the three New Jersey transmission owners of $0.4 billion to interconnect 7.6 GWs.
So, you’re thinking, $3.3 billion versus $0.4 billion, this holistic study stuff is amazing! But no. The individual studies bring the offshore wind to coastal substations, while in the PJM analysis PJM assumes (per direction from the New Jersey Board of Public Utilities) that the bulk of the offshore wind will be interconnected at inland substations, shown on the inset map on slide 47 of deck here, where there are lots of high voltage transmission lines and lots of load to absorb generation. Thus, few network upgrades are needed to accommodate injections at the inland substations.
But the rub is that you have to get the offshore wind to these inland substations. The PJM analysis includes zero cost for that.
How much would it cost to move 5.5 GWs[7] inland, with the added cost of using HVDC transmission instead of HVAC transmission? I have no idea, but NREL says HVDC-HVAC converter stations run about $367 million a copy,[8] and it looks like New Jersey would need around six of them. HVDC transmission lines through densely populated New Jersey would be on top of that.
Bottom line, the PJM analysis eliminates almost all network upgrade costs by assuming offshore wind arrives at inland substations at zero cost. This does not mean the PJM analysis is wrong, it means inland injection network upgrade costs cannot be compared with coastal injection network upgrade costs.
Moving On to Virginia/North Carolina
Now that we understand the New Jersey mismatch, the PJM results for other states will make some sense. Starting with Virginia/North Carolina, active individual interconnection studies show upgrade costs of $948 million to interconnect 5.0 GW of offshore wind. That comes to $190/kW.
The single PJM analysis shows transmission owner (Dominion) upgrade costs of $1.9 billion to interconnect 7.8 GWs. That comes to $243/kW — actually more than the individual studies’ cost per kW. So much for the Brattle take.
Virginia/North Carolina Case Study for Averting Customer Disaster
Virginia/North Carolina also gives us a great example of how participant funding can avert customer disaster. The project developer proposing 2.4 GWs of injection on the Birdneck-Landstown circuit originally proposed to inject at the Virginia Beach substation. According to the PJM studies, the former costs $736 million in network upgrades and the latter costs $1.9 billion in network upgrades.[9]
In the absence of participant funding, the developer would have had no reason to change the point of injection (which it did a month after receiving the PJM studies for the initial, high-cost point of injection). Customers would have paid more than $1 billion extra in socialized transmission costs. Not good.
And Delaware and Maryland
For its single analysis PJM assumes all 1.6 GWs are injected at Delmarva’s Indian River substation. The three active interconnection requests for that substation show upgrade costs of $677 million to interconnect 1.1 GWs.[10]The PJM analysis shows transmission owner upgrade costs of $711 million to interconnect the 1.6 GWs.[11]There is a difference in cost per kW but it can’t be meaningful because the Delmarva-only upgrade costs are $180.6 million for the individual studies’ 1.1 GWs, and $53.7 million for the PJM analysis of 1.6 GWs. This isn’t possible for injections at the same substation assuming all else is equal. So idiosyncrasies in modeling, rather than planning fundamentals, must be the difference.
Wrapping Up
The Brattle’s study reliance on a PJM analysis to claim that holistic, regional planning yields much less network upgrade costs than individual interconnection studies is unsound. The cost per kW difference that Brattle relies on comes exclusively from New Jersey offshore wind, where the PJM analysis assumes that offshore wind is brought inland at zero cost.
The other states present a mixed picture, as well as a great example of why we don’t want developers to be indifferent to network upgrade costs. Which they would be if participant funding were replaced by socialized transmission cost allocation.
A Postscript on Claimed Benefits for Load
Like the ICF study, the Brattle study claims network upgrades can benefit load, citing a PJM slide about congestion relief, etc. Brattle twice uses the word “substantial” in its characterization of the PJM benefits slide, a word that doesn’t actually appear on the slide.[12]
But more fundamental to the participant funding subject is that there is no reason to think that uneconomic network upgrades provide more load benefits than economic network upgrades, or somehow contribute extra benefits that would outweigh the extra cost to load. And that’s the point.
And a Post-postscript on ‘Holistic’ Planning
It’s a recipe for chaos. Revealing was this passage in a PJM FAQ about the NJBPU solicitation for transmission proposals:[13] “PJM and NJBPU will not provide a numerical weighting or metric for evaluation criteria … Participants are encouraged to provide sufficient responses in their proposal submission to enable PJM and the NJBPU to properly consider all evaluation criteria.”
If I might translate, PJM and the NJBPU won’t say how they will weigh the many evaluation criteria under this “holistic” approach. Instead, project sponsors must guess what PJM and the NJBPU might end up thinking and provide “sufficient responses” for PJM and the NJBPU to “properly consider all evaluation criteria.” If that is the future of transmission planning, we might as well turn everything back to transmission owners’ tender mercies.
[2] Network upgrades upgrade the grid – they do not include the cost of direct connection of the project to the nearest substation or transmission line (aka circuit).
[9] Project queues AE2-122, AE2-123 and AE2-124 for the Birdneck-Landstown circuit, and AE1-065, AE1-066 and AE1-067 for the Virginia Beach substation.
The Energy Bar Association last week once again gathered online, this time for its annual Mid-Year Forum, to discuss carbon capture, environmental justice and electric vehicle infrastructure.
Dan Sutherland, chief counsel for the Cybersecurity and Infrastructure Security Agency, kicked off the two-day event Oct. 12 with a keynote speech and discussion, followed by a panel on cybersecurity risks for the energy industry. (See related story, EBA Panel Discusses Management and Mitigation of Cybersecurity Risks.) But the first day also featured two panels on transmission, with one on FERC’s Advance Notice of Proposed Rulemaking (ANOPR) into planning and cost allocation, and another focusing on interregional coordination and operations.
Here’s some of what we heard.
A New Order Needed?
The first transmission panel focused on FERC’s ANOPR, which sought comments on possible changes to its rules on transmission planning and generator interconnection (RM21-17). Coincidentally, the session took place on the day comments were due; about 170 companies and groups weighed in. (See related story, FERC Tx Inquiry: Consensus on Need for Change, Discord Over Solutions.)
The EBA discussion was a microcosm of the debates that played out through those comments.
Moderator Larry Gasteiger, executive director of WIRES, slyly posed “a simple question” for the panel to answer: Is transmission planning working?
Kari Valley, managing senior corporate counsel for MISO, returned a definitive “yes,” though she admitted that there is room for improvement. “We’re always looking at where we can address the issues being presented today and the issues that we see in the future,” she said, pointing to the RTO’s past success with its Multi-Value Project portfolio and its effort to address the massive influx of renewables with its long-range transmission plan.
Sara Weinberg, senior counsel for Dominion Energy, disagreed. “Fundamentally, the regulatory paradigm that we have in place for both transmission planning and generator interconnection is flawed,” she said. “It’s just antiquated. And it’s obviously not in line with the things that we need to be doing right now to move to a cleaner energy future.”
Weinberg noted that Dominion serves load in both RTO and non-RTO footprints and said transmission planners work reactively, building transmission to interconnect resources that are in interconnection queues, rather than “looking at everything in a holistic fashion.”
Cynthia Bogorad, a partner at Spiegel & McDiarmid, said she would be filing comments later that day for her client, the Transmission Access Policy Study Group (TAPS). Echoing many comments in the FERC docket — not just TAPS’ — Bogorad said that “a more holistic approach, while it sounds good, has its own problems [that] we’re going to have to tackle. One is [that] a one-size-fits-all approach is not going to be the answer.”
Rob Gramlich, president of Grid Strategies and eternal optimist for improved transmission planning policy, was upbeat as he gave a presentation on the history of FERC’s efforts regarding the issue and his organization’s proposal. One of his slides listed the commission’s orders regarding transmission and interconnection: 888 (1996), 2000 (1999), 890 (2007) and 1000 (2011). The last bullet listed “??? (2022?).”
Western Independence and Incrementalism
Jennifer Chen, president of consultancy ReGrid and moderator of the second panel, began by thanking attendees for joining “even though your FERC transmission ANOPR comments are due today before 5 p.m.” Her session also provided a miniature version of recent discussions, in this case those among Western energy organizations and state legislatures. (See related story, Talk of Western RTO Intensifies.)
Clockwise from top left: Jennifer Chen, ReGrid; Sarah Edmonds, PGE; David Patton, Potomac Economics; and C.J. Brown, SPP | EBA
“There’s a lot going on in the West,” acknowledged Sarah Edmonds, director of transmission and market services for Portland General Electric. “It’s very easy at times, especially for an observer from the outside, to ask, ‘Why don’t they just do an RTO? Why do they have to do this very unique, incremental approach?’ … Our last 20-year-plus of history is marked by the tombstones of several failed attempts in the RTO space.”
There are many reasons for these failures, but “it’s fundamentally been about trust and control,” said Edmonds, whose office was adorned with a painting of two horseback riders riding along a dirt trail.
“There’s a deeply ingrained Western culture of self-determination and independence. We have a long tradition of operating our own balancing authority areas … of relying on ourselves and feeling like, ‘We know our systems best, and we know how to flex our systems to keep the lights on for our customers.’”
CAISO’s Western Energy Imbalance Market began eroding utilities’ stubbornness, she said. With Bonneville Power Administration’s entry into the market next year, more than 80% of WECC (which covers the entire Western Interconnection except for Alberta) will be served by the EIM.
Edmonds also spoke about the unique challenges to building transmission in the West, including wide areas of tribal land and endangered species habitat. “There’s a lot of trepidation in Western hearts, minds and wallets about what transmission cost allocation could mean to customers. This is why I think it’s been one of the hardest things to solve.”
David Patton — whose firm Potomac Economics serves as market monitor for ERCOT, ISO-NE, MISO and NYISO — said his primary concern was that grid operators “don’t fully use the transmission that we have today.” Many transmission owners don’t use ambient-adjusted or dynamic line ratings to increase capacity as conditions change and “don’t provide appropriate emergency ratings, which basically means that the system can be more congested than it needs to be, and it can cause you to believe that high-voltage transmission is more valuable than it actually is.”
But “in certain places, especially places [where] the wind is just exploding” — such as SPP, whose director of systems operations, C.J. Brown, nodded along as Patton spoke — “high-voltage facilities are going to be the most economical,” Patton said.
Brown responded by quoting MISO CEO John Bear: “‘If you like renewables, you better like transmission.’”
SPP’s Strategic Planning Committee last week approved a task force’s recommended framework to manage DC tie revenue-requirement recovery as part of the grid operator’s proposed RTO West.
The DC Tie Task Force’s proposed market efficiency use (MEU) mechanism would compensate DC ties for their market use and be applied to DC-tie market dispatch beyond network and point-to-point use. The group said that would ensure their market use is properly compensated for and does not adversely affect the DC tie’s host zone.
The task force also said SPP staff should continue to engage with Western parties and its membership to fully develop an MEU rate and applicability details before April 15 and suggested a DC tie congestion-hedging task force develop a final proposal for a congestion-hedging methodology.
Tom Christensen, Basin Electric | SPP
Basin Electric Power Cooperative’s Tom Christensen was the lone SPC member to vote against the task force’s motion, citing concerns with continued congestion and increased maintenance costs for the 200-MW DC tie in Rapid City, S.D., that Basin co-owns with Black Hills Power and Light.
“With significant use, we expect maintenance costs to increase,” he said. “Our most significant concern … is that whatever approach is selected needs to provide an incentive for other entities to join the SPP West effort and for other DC ties to be constructed. Without that, the benefits to both East and West will be unnecessarily constrained. We encourage a more holistic, broader view of what we consider a very substantial opportunity.”
SPP would be the first RTO to consolidate two balancing authorities DC ties with its Western membership. A Brattle Group study found that RTO West would produce $49 million in annual savings for current and new members. Western utilities would receive $25 million a year in adjusted production cost savings and revenue from off-system sales. Members in the Eastern Interconnection would benefit from $24 million in savings because of the market’s expansion, transmission network and generation fleet.
Assuming FERC approval of Tariff changes, SPP expects RTO West to become a reality in 2024. The gird operator already manages the Western Energy Imbalance Service market, which launched in February, for eight participants.
‘Custom’ Cost Allocation Coming?
SPP Engineering Vice President Antoine Lucas told the committee that the grid operator’s joint targeted interconnection queue (JTIQ) project with MISO will involve a custom cost-allocation approach “designed to fit this study and process.” The mechanism will also help the staffs overcome some of the hurdles they have faced in trying to work together on interregional projects.
Lucas said one rubric being discussed is how to allocate portions of different loads and how to allocate generation to the various generators involved in the process. (See MISO, SPP: Economics Secondary in Joint IC Planning.)
Separating cost allocation from the rest of the JTIQ work will help the project remain on track, Lucas said. A draft report will be drafted later this month.
Renewable developers are commending the JTIQ project, NextEra Energy Resources’ Matt Pawlowski said in speaking for the community.
“It’s evident from the last meeting that you’re working hard together to come up with solutions,” he said. “There’s potential to get a lot of these projects built and it will unlock a lot of value for folks. We continue to strive for more certainty on the cost and the schedule, as we do for all interconnection schedule, so we know what we’re signing up for. The closer we get to that, the more projects we’ll build.”
Competitive Upgrade Changes
The committee approved a task force’s recommendation to amend a business practice that the group said will improve the volume and quality of submissions in SPP’s competitive transmission-upgrade process.
The Transmission Owner Selection Process Task Force modified Business Practice 7650’s language so that its criteria for detailed project proposals clarify that they are equivalent to a transmission project in the recommended portfolio. The submitted projects will need to reduce thermal loading below 100% or improve the per-unit voltage values between 0.9/unit and 1.05/unit and also be within 50% of congestion mitigation for each economic need solved.
SPC also agreed with the task force’s proposal to require incentive points be considered by the industry expert panel (IEP) responsible for grading and selecting the transmission owner to build a competitive project. That is a policy change from the current practice of not placing any parameters on the IEP. The task force did retain tariff language allowing the panel to recommend a project besides the one with the highest score.
“We feel the incentive points are an integral part of the process,” said American Electric Power’s Brian Johnson, the task force’s chair.
Altenbaumer Ends Chairmanship
Board of Directors Chair Larry Altenbaumer ended his two-year term as the SPC’s chair on a high note, ending the meeting just three minutes short of its scheduled end time.
“I couldn’t be more excited about SPP’s future, and I look forward to working with all of you in other formats in the future,” he said before the meeting adjourned.
Altenbaumer will be replaced by Director Mark Crisson.
The SPC will also need to replace Evergy’s Kevin Noblet and Nebraska Public Power District’s Traci Bender next year. Noblet is leaving Evergy, and Bender’s term has ended.
Staff, Members Call for More Coordination with Gas Industry
SPP staff told stakeholders last week they are searching for ways to urge change in the energy industries following February’s disastrous winter storm, when natural gas curtailments led to the RTO’s first rolling outages in its 75-year history.
Several members urged the grid operator to focus on the gas curtailments they said were the root cause of the generation outages during the storm, an opinion shared by FERC and NERC in the draft report of the joint inquiry into the storm and its impacts. (See FERC, NERC Share Findings on February Winter Storm.)
“You can argue all day long whether the curtailments started happening before the outages started. … Seventy percent of firm gas was curtailed. That to me is the root cause,” Southwestern Public Service’s (SPS) Bill Grant said during the Oct. 11-12 Markets and Operations Policy Committee meeting.
“I know we need to look at all this other stuff, but we should do so without being told. That’s common practice,” he said. “The main focus should be on [gas-electric] coordination and domestic [gas] contracts.”
Mike Wise, whose Golden Spread Electric Cooperative sits in West Texas along with SPS, said most of the co-op’s problems occurred because of ERCOT’s problems. The Texas grid operator lost more than half of its thermal generation because of curtailments and freeze-offs of natural gas facilities, which led to ripple effects elsewhere.
“The real issue is electric reliability in ERCOT is impacting others besides ERCOT,” Wise said. “We have firm transportation arrangements with our pipeline providers. They said they were available and ready to go. It was the fuel-processing plants on interruptible rates and fuel suppliers that were on ERCOT outages [that failed]. It was the other pieces of the gas infrastructure feeding into [the pipelines] that forced them to declare force majeure. We need to complete that analysis.”
“Duly noted,” SPP COO Lanny Nickell said. “We did notice there was some increase in generation outages due to fuel issues before we had to shed load. We can sure dig into that information.”
The RTO in July released a comprehensive report on its response to the storm’s effects that said a lack of fuel supplies led to generation’s unavailability and was “the largest contributing factor to the severity of the winter weather event’s impacts … exacerbated by record wintertime energy consumption and a rapid reduction of energy imports.” (See “Grid Operator Releases Report on Performance During Winter Storm,” SPP Board of Directors/Members Committee Briefs: July 26-27.)
Among the report’s 22 recommendations are two aimed at improving fuel assurance: evaluate and, if necessary, advocate for improvements in gas industry polices to assure supplies are “readily and affordably” available during extreme events; and developing policies to improve gas-electric coordination to improve emergency response.
“There’s not a lot we can do about it but talk about it and advocate as best we can,” Nickell said. “We can make sure our facilities are hardened and do everything we can, but if the gas doesn’t show up, there’s nothing we can do about that.”
“If you would have asked everybody in January if they felt like they were ready for the winter, everybody would have said, ‘Yes, we feel good,’” Grant said. “But even when you’re in good communications with the suppliers, you can’t stop them from declaring force majeure. You could still have 70% curtailments on firm gas deliveries … and we can’t do a thing about it.”
SPP in August followed up on the report by surveying its generator owners and operators to learn about their plans for having available fuel supplies for the upcoming winter. The survey generated 60 responses, reflecting 85% of the RTO’s nameplate capacity and including 52 spreadsheets with unit-specific information. It revealed that 68% of the respondents already have plans and process in place.
The survey’s data will only be used for planning purposes and itself does not have any compliance implications, Nickell said.
“It feels to me we’re going to be in better shape this upcoming winter than we were last winter,” he said. “If the upcoming winter is worse than the last one, that may be a moot point. That’s about all we can do with the information we have right now.”
Nickell said the newly constituted Improved Resource Availability Task Force will have an opportunity to weigh in. The task force, under the Regional State Committee, has already met four times in tackling the Tier 1 recommendations from the winter-storm review related to fuel assurance and resource planning and availability.
The group is chaired by Arkansas Public Service Commission Chair Ted Thomas, with Golden Spread’s Natasha Henderson as vice chair. They are joined by five regulatory commissioners and staff and five member representatives. The conference calls have drawn more than 70 dial-ins each time, Nickell said.
“What we’ve done gives us a head start with the FERC-NERC recommendations,” he said.
Midwest Energy’s Bill Dowling noted that FERC lacks the jurisdiction to impose reliability standards on its own and said that work should reside with the North American Energy Standards Board (NAESB), which has jurisdiction over both the gas and electricity industries.
“They’ve been in a slumber for decades on these types of issues. That needs to be addressed,” Dowling said.
Michael Desselle, SPP’s chief compliance and administrative officer and a member of the NAESB board, advised the MOPC to “stay tuned.”
“We will put in a standards request, and [NAESB] won’t have the option not to do anything,” he said. “If they choose to, they will be on the record for not doing anything.”
MOPC Chair Denise Buffington, of Evergy, said an education session on NAESB would be scheduled for the committee’s next meeting.
“We need to be cautious about getting into the gas business,” she said. “We need a little more research on the lines of jurisdiction between what FERC does and what NAESB does.”
MOPC Approves SCRIPT Report
The MOPC endorsed the Strategic and Creative Re-engineering of Integrated Planning Team’s (SCRIPT) report, but only after declining to endorse the team’s 46 recommendations over questions of project oversight and demand on staff. Members approved the endorsement motion with 97% approval.
The Board of Directors formed the SCRIPT last year and directed it to recommend broad changes to the RTO’s transmission planning processes that would better meet customer needs and resolve concerns about transmission investment amid rapid industry changes. The team came up with 35 recommendations and 11 sub-recommendations for business practices, policies and tariff revisions to consolidate planning processes, improve services processes, optimize SPP’s transmission network, improve decision quality, facilitate beneficial interregional energy transfers and improve cost sharing.
“There’s a lot of recommendations built into the report,” said Grant, the lone member to vote against the motion during the MOPC meeting and Wednesday’s Strategic Planning Committee call. “Some of them are good to implement, but if I endorse the recommendations, then it will be misinterpreted that I support those recommendations. There are a couple we don’t support and will not support. That being said, I think there’s a lot of good work and a lot of good work that needs to happen.”
“I still have concerns about resources on both sides. I don’t hear these are mandates,” Oklahoma Gas and Electric’s Usha Turner said. She noted staff and members will have their hands full responding to FERC’s Advanced Notice of Proposed Rulemaking on transmission planning and cost allocation (RM21-17), the winter weather report and implementing SPP’s new strategic plan.
“What do we reshuffle? What do we throw out?” Turner asked.
“The proof in the pudding will be what we get out of the end with cost allocation,” American Electric Power’s Richard Ross said.
Nickell said he will work with Directors Mark Crisson, who also chairs the SCRIPT, and Bronwen Bastone to coordinate the work going forward. The board could designate an existing stakeholder group or commission a new one to oversee the team’s implementation.
Central to the SCRIPT’s work are the overarching consolidation policy recommendations. During a MOPC education session last month, Nickell told members that that the new consolidated transmission planning process will save $3 million to $4 million annually in administrative cost savings once it is in place. SPP currently incurs about $28.5 million in annual costs for its planning processes. (See SPP: Consolidating Tx Planning Could Yield Big Savings.)
Staff said the improved processes should also lead to more optimal transmission, equitable cost-sharing, timely outcomes, increased certainty and greater transmission value.
The board will consider the recommendations during next week’s meeting. If approved, staff and stakeholder groups will either perform additional assessments to determine future action or work to implement policy direction through further design and process development.
“This will require some group, somewhere,” Crisson told the SPC on Wednesday. “The industry environment is rapidly changing around us, and we need to be able to respond to that.”
“These are good concepts. If we don’t get started, we’re not going to finish,” board Chair Larry Altenbaumer said. “No one should view that everything else is grinding to a halt and we’re moving forward full barrel. The challenge of leadership is with the board.”
SPP Asks for Z2 Rehearing
General Counsel Paul Suskie told the committee that a recent U.S. appeals court decision denying petitions by SPP and OG&E to review a FERC order on transmission upgrade costs lays out a clear path forward in finally resolving Attachment Z2’s never-ending saga.
The D.C. Circuit Court of Appeals ruled in August that FERC was correct in reversing a retroactive waiver it had granted SPP over collecting transmission upgrade costs under the tariff’s Attachment Z2 (20-1062). The commission had granted the waiver so that it could invoice transmission service customers for Z2 credit payment obligations for 2008-2016 (ER16-1341) but reversed course in 2019. FERC said its original decision was prohibited by the filed-rate doctrine and the rule against retroactive ratemaking. (See DC Circuit Upholds FERC Ruling on SPP Z2 Saga.)
“The ruling helps define the future of Z2,” Suskie said.
SPP and OG&E on Oct. 12 filed a joint request with the D.C. Circuit for an en banc rehearing, with a decision expected between November and February. If the request is denied and there are no further appeals, the RTO expects to receive a refund order from FERC for $138.5 million in credit payment obligations.
Suskie said SPP would then have to resettle Z2 credit obligations from September 2015 on, amounting to about $371 million.
SPP has a compliance filing pending at FERC, where five other dockets involve litigation over the Z2 process, filed by OG&E (EL19-77), EDF Renewables (EL19-75), Western Farmers Electric Cooperative, (EL19-93), Cimarron Windpower (EL10-96) and Kansas Electric Power Cooperative (EL17-21).
The grid operator expects to make additional filings at FERC clarifying how it will handle the refunds. “Much, much more to come in the future,” Suskie said.
“I would like to say I’m looking forward to it,” said Chair Buffington, who led a Z2 task force several years ago. “I’ll bite my tongue because I know how complicated it is.”
ITP Mitigation Plan Successful
SPP’s mitigation plan to get the 2021 Integrated Transmission Planning (ITP) study back on track has been a success, chopping 40 days off the delayed scheduled, staff told members.
The study was to be shared with the MOPC and board in October but will now be presented in January. The 2021 ITP report will be posted in mid-December.
Eliminating model builds and assessments has helped SPP reduce the ITP 2021’s delayed schedule. | SPP
The mitigation activities, approved by both governance groups in July, include waiving requirements to build and assess power-flow models during the 2021 reliability needs assessment; modifying the 2021 scope to allow schedule adjustments within the study; and extending the 20-year assessment’s due date to 2023. (See “Tx Planning Mitigation Gets OK,” SPP Markets and Operations Policy Committee Briefs: July 12-13, 2021.)
“The 20-year assessment is on pause. It’s very important to SPP, but it will be unpaused after we focus on the 2021 ITP,” SPP’s Casey Cathey said.
Staff will eventually be diverted back to the 20-year assessment as they continue to grapple with three studies at the same time.
Annual VRL Analysis Approved
The committee approved the Market Working Group’s recommendation to approve the 2020-2021 annual violation relaxation limits (VRLs) analysis. Staff are not proposing any changes to the VRLs, saying the analysis showed no operating constraint sensitivity that reduced both the cost and the number of breaches and that the current VRL blocks provide a proper balance between economics and reliability.
AEP’s Ross, who chairs the MWG, suggesting adding language that a Market Monitoring Unit revision request (RR414) pursue possible VRL adjustments for extreme weather events and that it “come to fruition” before making additional changes. Ross agreed to pull his language after additional discussion, saying he was sensitive to concerns about additional studies being necessary “before we start monkeying around with the VRLs.”
The annual VRL analysis passed with 92% overall approval.
Members also approved the Supply Adequacy Working Group’s proposed RR462 that implements a process that includes a methodology for prioritizing and allocating the available effective load-carrying capability for standalone energy storage resources (ESRs) that qualify as capacity in the SPP balancing authority. The accreditation policy would be the first implemented by SPP for ESRs.
GOTF Nears its Sunset
Members approved four recommendations from the Generator Outage Task Force (GOTF) addressing outage-scheduling practices and concerns over how to reliably schedule outages.
Pointing to the changing resource mix’s effect on performing maintenance on conventional resources, staff secretary Kathryn Dial said the task force recommended revising the generation assessment process (GAP), used to help ensure balancing authority capacity adequacy in scheduling outages, be changed from a short-term GAP to generate hourly maintenance margin values.
The GOTF’s recommendations also include revising outage-coordination methodology by changing the outage/derate reporting threshold from 25 MW to 10 MW; allowing forced outages to have up to seven days of maximum lead time to align with NERC’s generating availability data system; and updating the cause codes.
The committee also endorsed the group’s request to be sunset, a move that thrilled Ross. Always eager to see the number of stakeholder groups reduced, Ross said he would send a gold star to Dial, who promised to have it framed.
The task force was created after SPP declared a Level 1 energy emergency alert and called for conservative operations 10 times in 2019. The grid operator attributed six of the 10 operations events to generation outages.
Tariff Updated with Admin Fee’s Cap
CFO Tom Dunn had the line of the meeting as he sought to explain a revision request (RR463) on the consent agenda that updates tariff language in Schedule 1-A to reflect the recently approved increase to the cap on recoverable costs. The Members Committee and board approved the change from 43 cents/MWh to 46.5 cents/MWh in July, but members wanted to ensure SPP wouldn’t take advantage of the increase. (See “Admin Fee Cap Bumped 8.1%,” SPP Board of Directors/Members Committee Briefs: July 26-27.)
Dunn said the cap’s increase does not mean an increase to SPP’s costs but is a “look out into the future.” He said staff believe the cap is “valid into 2026.”
“The tariff language change … doesn’t mean we’ll hit the number every year. Will you do everything you can to keep it low?” Chair Buffington asked.
“Tom’s life is easier when members are happy with the rate,” Dunn said.
And Dunn’s life did indeed get easier when the committee placed RR463 back on the consent agenda.
RCAR Hybrid Approach OK’d
RR463 was one of four items MOPC members pulled off the consent agenda for further discussion, eventually returning three to the agenda. RR461, which proposes a new hybrid approach for the regional cost allocation review (RCAR), was voted on separately and passed with 94% overall approval. The consent agenda passed with 97% approval.
The Regional Allocation Review Task Force recommends using real market data for facilities that have been in service for more than two years and a more theoretical, study-based approach for those approved projects that are still under construction or have not been in service for at least two years, effective with the 2022 RCAR.
The consent agenda included:
RR456: clarifies that ESRs co-located or integrated with generating resources may register as a single resource and can use the market storage resource (MSR) model if desired.
RR453: adds language to clarify which rounds or stages electrically equivalent settlement locations can be nominated during the auction revenue rights allocation process.
RR459: updates the tariff to replace a reference to MSRs’ loss factor with ERSes’ loss factor.
RR475: corrects the production version of the Integrated Marketplace’s protocols to remove market participants’ financial harm from an incorrect calculation because of overlapping revision requests.
RR460: updates the minimum transmission design standards for competitive upgrades.
RR464: updates Attachment W’s index of grandfathered agreements with changes identified during the annual review.
RR466: cleans up the transmission owner selection process’ governing documents to more accurately capture their intent and execution.
RR454: modifies business practices to increase the deadline for issuing notifications to construct from 15 business days to 45 calendar days.
RR458: adds additional generator interconnection change to reduce and ultimately clear the queue backlog as part of the SCRIPT process.
RR467: revises the tariff’s Attachment AQ by reducing the waiting period for preliminary study results of new load additions to adding a rolling submission and response window and posting delivery point network studies once the new or modified load is confirmed.
Sanjay Shrestha, Plug Power | Plug Power
Plug Power CEO Andy Marsh | Plug Power
