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.
BOSTON — As part of series of opening keynotes at the American Clean Power Association’s Offshore WINDPOWER 2021 conference, U.S. Secretary of the Interior Deb Haaland announced plans for the Bureau of Ocean Energy Management to potentially hold up to seven new OSW lease sales by 2025 in the Gulf of Maine, New York Bight, Central Atlantic and the Gulf of Mexico, in addition to the Carolinas, California and Oregon.
During a subsequent panel on permitting improvements, BOEM Renewable Energy Program Manager James Bennett said Haaland’s announcement represents “a path forward.”
“It does identify where we’re going and what we’re doing,” Bennett said. “This is not the first time we have attempted to put together and lay out a path forward, but it is the first time that we have been successful in being able to share with the public and specifically identify when lease sales are targeted for the near future.”
Massachusetts has targeted net-zero emissions by 2050, and at least 15 GW of OSW are needed, according to the state’s Decarbonization Roadmap. Energy and Environmental Affairs Secretary Kathleen Theoharides said that forward momentum on new lease areas “is a great, exciting announcement that probably should have received a lot more clapping from this audience.”
“It’s another piece of the puzzle to this whole question,” Theoharides said.
The Federal Permitting Improvement Steering Council (FIPSC) helps fit the puzzle pieces by overseeing interagency coordination and process improvements. With the Biden administration using a whole-of-government approach to deploy 30 GW of OSW by 2030, FIPSC Executive Director Christine Harada said from an efficiency perspective, “there’s a lot of work that we need to do within a very limited amount of time.”
Project uncertainty is challenging some of the agencies regarding how to permit something or how to evaluate the impacts under their statutory mandates, according to Scott Lundin, head of U.S. permitting and environmental affairs at Equinor. For example, Lundin said the Block Island Wind Farm began operations in 2016 with five 6-MW turbines, but General Electric announced that its turbines can now generate 14 MW of power.
“There’s a concern and a risk that alternatives get defined that are not technically, commercially, environmentally feasible,” Lundin said. “I think the opportunity for the developers to help inform and shape perspectives of these different agencies about the value and the need to bring these products to commercial operation is something that we’re very interested in facilitating whenever possible.”
Theoharides on Baker Announcement
After the permitting panel’s conclusion, Theoharides told RTO Insider that the announcement of legislation by Massachusetts Gov. Charlie Baker (R), which would create a $750 million clean energy investment fund and refine the current OSW procurement process, is “significant.”
“What it will open up for us here in Massachusetts is a chance to ensure that not only are we aggressively pursuing our net-zero targets, but we are leading the industry to design the solutions and then to retain those jobs right here in Massachusetts and in the Northeast,” Theoharides said.
The main change to the OSW procurement process would be the transfer of authority to select the winning bidder from state’s electric distribution companies like Eversource and National Grid to the Department of Energy Resources. However, EDCs would remain participants in the evaluation and provide technical advice to the department.
Theoharides said that taking the EDCs “out of the game” of choosing which company will win the bid makes procurements “more efficient” and “more objective process overall.”
Baker’s legislation comes on the heels of a plan by his administration to also direct $900 million in federal aid from the American Rescue Plan Act toward vital energy and environmental initiatives, including $100 million to invest in port infrastructure to support OSW. Theoharides said the $100 million would “kick off” port infrastructure work, and the state would look to leverage additional private investments.
Markey: Politics Hinder Renewable Energy Progress
U.S. Sen. Ed Markey (D-Mass.) said during an interview Thursday that the only thing stopping the progress on renewable energy sources like OSW is “politics and not technology.”
“If we didn’t have political opposition that was in place, the technology would have evolved much more quickly,” Markey said.
The target of 30 GW of OSW by 2030 set earlier this year is “modest,” according to Markey. However, he also thinks political opposition will be funded by the fossil fuel industry, especially at the ballot box.
“The fossil fuel industry is going to try to take the 2024 election, make it a referendum, bring back a gang that is tied to the fossil fuel generation strategy,” Markey said.
Markey introduced a bill in September that would create a 30% investment tax credit for U.S. manufacturers to produce qualified OSW components and dedicated vessels. “We’ve tailored the solutions to the exact needs of the industry to get the policies that fit to reduce the high capital costs that manufacturers face,” Markey said.
BOSTON — To meet the Biden administration’s 30-GW offshore wind goal by 2030, private investment coupled with government-backed financing is needed to spur construction of wind turbine installation vessels (WTIV), which carry a price tag of $500 million.
From the standpoint of the U.S. maritime industry, OSW is a “generational opportunity,” said Jennifer Carpenter, CEO of the American Waterways Operators, during the American Clean Power Association’s Offshore WINDPOWER 2021 conference on Thursday.
Multiple things can be done to “develop the supply of vessels” to serve the lifecycle of an OSW project, “from a survey, all the way on through construction development, eventual decommissioning,” she said.
“The first thing I would say is let’s not make it overly complicated to stimulate supply,” Carpenter said. “We have to focus on demand. It is not surprising that we do not have a fleet of vessels sitting on the proverbial shelf waiting to serve an industry that has not yet existed in this country because we’re doing something new.”
Because the Jones Act enjoys strong bipartisan support in Congress and from President Biden, Carpenter added, it “helps foster the certainty that we need to make investments” in WTIVs and other vessels. The Jones Act can be waived under tightly controlled circumstances, such as national defense, and there are no qualified U.S. vessels to meet that need, according to Carpenter.
Dominion Energy (NYSE: D) is currently constructing a Jones Act-compliant WTIV, which will be completed in 2023. However, U.S. developers will also have to rely on European-flagged jack-up vessels if any steel goes in the water in the near term. There are nine WTIVs available globally that can install turbines greater than 10 MW, and of those, only two of them can install turbines in the 12-MW-plus category. (See US Must Watch Europe’s OSW Supply Constraints, Analyst Says.)
Karl Humberson, director of construction projects for Dominion, said during the conference that he hopes construction of the WTIV provides the OSW industry “a level of certainty” that investments such as this are “going to help everybody else.”
Constructing a WTIV, he said, is not part of Dominion’s core business, but when the company looked at the puzzle pieces for OSW to determine “which ones are missing,” Dominion took “some risks.”
“We’re a little bit different. We are an owner-operator of a wind farm, so we have a little bit of certainty saying there’s a project here that we’re going after,” Humberson said. “That helped us make some decisions related to the WTIV. … We think it is the right way to build offshore wind, and that’s why we made these investments.”
While heavy lift vessels “get a lot of press” because of the significant investment, Troy Patton, COO for Ørsted Offshore North America, said he was struck by how many additional vessels are needed on an OSW project. Construction for a project off the coast Grimsby, England, he said, required upward of 50 vessels to deliver equipment and personnel to the wind farm.
The Title XI Federal Ship Financing Program will pay up to 87.5% of the cost for certain vessel classes and shipyards, according to David Gilmore, director of the Office of Marine Financing at the United States Maritime Administration. That payment can cover the construction of new vessels, reconfiguring vessels and modernization of shipyard facilities. Applicants for this program must meet financial requirements. There are also loan guarantee programs for onshore wind, which could be expanded to OSW projects and a capital construction fund with tax deferrals.
“There’s a lot of opportunity out there,” Humberson said.
The debate over a Western RTO has ramped up this month, with discussions focused on the feasibility of an organized market in the West, its pros and cons, and its potential makeup, including whether California’s participation is necessary for success.
Stakeholders and state regulators weighed those factors at a CAISOforum Wednesday and in an Oregon RTO Advisory Committee meeting Oct. 6. This week’s joint meeting of the Committee on Regional Electric Power Cooperation and the Western Interconnection Regional Advisory Body (CREPC-WIRAB) includes an afternoon of panels devoted to the topic, as well as other panels and presentations by FERC commissioners touching on it.
The growing sense of urgency is being driven by state decarbonization mandates, resource adequacy problems and state laws requiring utilities to join RTOs. (See Western Utilities to Explore Market Options.)
“There’s been a convergence of interest in these issues like there has never been before, and I think that’s a very, very good thing,” California Public Utilities Commissioner Clifford Rechtschaffen said during CAISO’s forum. “People are really focused on regional markets, the need for robust rules for resource adequacy and shared reliability efforts. How do we achieve clean energy mandates across the West now that more and more states have gone that way?”
Rechtschaffen called it an “opportune time” for regionalization efforts in the West.
The forum was primarily focused on the ISO’s proposal to expand its Western Energy Imbalance Market from an interstate real-time trading platform to an extended day-ahead market (EDAM), a potentially significant step for Western regionalization. But discussion of the EDAM and the Northwest Power Pool’s creation of the interstate Western Resource Adequacy Program (WRAP) led to talk of a Western RTO. (See CAISO Promotes EDAM Effort in Forum.)
“An RTO market is no panacea,” said Tony Braun, an attorney who represents the California Municipal Utilities Association. “For those that are in one, if you want to talk about funding of financial transmission rights by load and other things that are quite controversial, call me offline. We can talk about it. I think people underestimate the obstacles and, even within an RTO structure, the ongoing struggles of operating within that paradigm.”
EDAM, WRAP and the possibility of an RTO are all under consideration, and “I think we just need to tackle them all at the same time,” Braun said.
“I don’t them see as mutually exclusive, but I do see EDAM as low-hanging fruit. There’s so much work that has been put into EDAM … that it would not be prudent to abandon it just because there’s a myriad of other options. We have to walk and chew gum on this at the same time, maybe a couple different flavors of gum.”
State regulators and industry representatives weighed in on EDAM and Western markets. | CAISO
Spencer Gray, executive director of the Northwest & Intermountain Power Producers Coalition (NIPPC), called EDAM a worthwhile initiative but said “it can’t be the end goal of further regionalization.” EDAM and WRAP are incremental approaches that don’t adequately address the clean energy mandates of a growing number of Western states, or the laws that Colorado and Nevada enacted in June requiring transmission owning utilities join an RTO by 2030, he said.
“I don’t dispute that a staged approach to developing regional markets can help us move forward rather than just stalling out,” Gray said. “But I do want to emphasize that we have both statutory and market pressures across the West that hang over this initiative.”
California, New Mexico, Oregon and Washington have 100% clean energy mandates to meet by midcentury, he noted. Nevada established a 100% clean-energy goal it intends to reach by 2050.
“We also have large, sophisticated energy consumers across the West who are committed to going carbon-free, and many of them are convinced, based on actual experience procuring clean power in RTOs, that the model an RTO offers — of not having contract-based transmission anymore, not having pancaked rates, not having balkanized balancing authorities — [is] a better alternative.”
He said he worried the EDAM may be an “incremental step that holds at bay harder conversations about governance and balancing authority consolidation and transmission.”
SPP has been pitching its own RTO in the West. Gray called that a positive move that would allow entities to join an RTO without California having to give up control of CAISO, a state public benefit corporation created by the legislature, with board members appointed by the governor. Prior efforts to turn CAISO into an RTO have fizzled because California lawmakers were unwilling to cede any authority over it to out-of-state interests.
Joining SPP means utilities “can simply sidestep a brick wall of single-state governance that has bedeviled RTO conversations that have revolved around CAISO, so I think collectively we should take both the EDAM initiative seriously, take SPP’s work seriously and try to pick the best course. And we may pick different courses, which is OK. That’s been the experience along many seams in the East between the RTOs.”
Is California Necessary?
Gray’s comments and other discussions taking place in the West suggest industry stakeholders are weighing the need to create a workable RTO rather than an ideal one, forcing the region to consider the “art of the possible,” as Oregon Public Utility Commissioner Letha Tawney put it during a recent meeting of the state’s RTO Advisory Committee, which was charged with helping the state’s Department of Energy prepare a report on the benefits and risks of RTO membership. (See Oregon RTO Committee Ponders Paths to Regionalization.)
That could translate into an effort that sidelines California, the region’s most populous state, biggest load center and burgeoning center of cheap solar energy that can be exported to neighboring states during periods of surplus.
A recent state-led study produced by Energy Strategies found that all states in the Western Interconnection would realize the largest amount of savings — about $2 billion a year — from a single market that includes California, with the biggest beneficiaries being Washington, Oregon and California itself. (See Study Shows RTO Could Save West $2B Yearly by 2030.)
But integrating California into such a market is being seen as increasingly problematic as more states look to use RTO membership as one tool in meeting their decarbonization goals on ambitious schedules that will likely outpace the timeline for development.
Speaking during the Oct. 6 meeting of the RTO Advisory Committee, Tawney pointed to the well known governance issues that have hampered CAISO’s regionalization efforts in the past, with many in-state interests reluctant to allow the state to relinquish its direct authority over the appointment of members of the ISO’s Board of Governors. Resistance to changing that governance structure has made membership in an expanded CAISO a nonstarter for regulators in other parts of the West.
But just as problematic, Tawney noted, is California’s approach to resource adequacy, a process managed not by CAISO but by the state’s Energy Commission.
“It is unusual, but not unprecedented, to have your resource adequacy conversation happening in a different place than your RTO,” Tawney said. “CAISO does it that way. ERCOT sort of does it that way. But I think because of how resource adequacy is handled in California, it makes it very difficult to sort of take the California RA model and spread it across the West. And so then we have the rest of the West say, ‘How could we do RA for ourselves in a way that works for us?’”
Momentum toward a Western RTO could build after Colorado and Nevada passed bills requiring utilities in those states to join an RTO, Tawney said. She compared the potential outcome of that legislation to the expansion of the Western EIM, which eventually crowded out trading in the West’s bilateral markets.
“Where does that leave Oregon customers?” Tawney said.
She acknowledged the Energy Strategies study finding that showed that the biggest market footprint would produce the greatest volume of economic benefits for the West.
“The flip of that is there’s more people you have to work with and figure out how to get along with and manage through,” Tawney said. “So, you have to find that sweet spot, from my perspective, between customer benefits and state policy.”
What About BPA?
The situation in the Northwest is further complicated by the presence of the Bonneville Power Administration, which operates about 70% of the region’s high-voltage transmission and manages its extensive network hydroelectric dams.
Speaking at the RTO Advisory Committee meeting, Northwest Energy Coalition policy analyst Fred Heutte noted that BPA’s “integrated system” relies on a contract-based — rather than flow-based — approach to transmission use.
“I think it’s easy to say [that], in an RTO, you can move to a flow-based approach and it’s all going to be great,” Heutte said. “But we have to look at Bonneville as a unique institution with a really important role, and trying to move from a contract-based approach to a flow-based approach, given Bonneville’s integrated approach, is going to be a big issue to have to unravel and kind of piece together how you do that transmission.
“It’s not just a matter of grandfathering rights and that sort of thing,” Heutte said. “The Bonneville system has some unique features that we have to consider in the transition to an RTO process.”
During the RTO Advisory Committee’s first meeting Sept. 21, BPA Manager Ravi Aggarwal encouraged the group to consider a “staged and incremental” approach to developing an RTO, saying the region’s transmission planning, RA and real-time market are already being served by Northern Grid, NWPP and the Western EIM, respectively.
Speaking at the Oct. 6 meeting, Aggarwal clarified that he was not advocating for the long-term persistence of those looser arrangements in lieu of an RTO but thinks they could provide a “pathway” to an organized market, whether West-wide or in a smaller footprint, such as that covered by the NWPP.
“I think we have to be careful about holding out a perfect RTO as a possibility — or maybe an Eastern-style RTO maybe is the way to put it — because we aren’t starting with a blank slate,” Tawney said.
