Rhode Island Gov. Gina Raimondo (D) announced Tuesday a new competitive solicitation to procure up to 600 MW of offshore wind energy.
Raimondo in January signed an executive order committing Rhode Island to meet 100% of its electricity demand with renewables by 2030. The order directed the state Office of Energy Resources to conduct economic and energy market analysis and develop policies and programs such as the OSW RFP.
Raimondo also recently joined with the governors of Connecticut, Maine, Massachusetts and Vermont to issue a joint statement calling for reforms to New England Governors Call for RTO Reform.)
“In the face of global climate change, Rhode Island must drive toward a cleaner, more affordable and reliable clean energy future,” Raimondo said in a statement. “It is critical that we accelerate our adoption of carbon-free resources to power our homes and businesses while creating clean energy jobs. In January I set a nation-leading goal for Rhode Island to meet 100% of its electricity demand with renewables by 2030. Offshore wind will help us achieve that bold but achievable goal while creating jobs and cementing our status as a major hub in the nation’s burgeoning offshore wind industry.”
Rhode Island is home to North America’s first operational OSW farm off Block Island, and the 400-MW Revolution Wind offshore project received state approval in 2019.
The RFP will be developed by National Grid with oversight by the state Office of Energy Resources and is ultimately subject to approval by the Public Utilities Commission.
“Our state, communities and local economies are facing unprecedented challenges as we confront the COVID-19 pandemic, but now more than ever, it’s imperative that we lean into our shared commitments to enable and progress the clean energy transition,” said Terry Sobolewski, president of National Grid Rhode Island. “Expanding large-scale renewables across Rhode Island is crucial to delivering clean, reliable, affordable energy for our customers and future generations.”
A draft RFP will be filed with state regulators this fall. If approved, a final RFP will be issued early next year. Any contracts for OSW projects resulting from the competitive process additionally require separate regulatory approvals.
Goal ‘Within Reach’
“Offshore wind is a vitally-important renewable resource that will help power our decarbonized future — both here in Rhode Island and throughout New England,” said state Energy Commissioner Nicholas Ucci. “Importantly, offshore wind can also help our electric system meet winter peak demand with stability-priced clean electricity, helping temper power price spikes faced by local homes and businesses.”
State OSW targets | States of Massachusetts and Rhode Island
Ucci said the RFP, “coupled with other locally developed, carbon-free resources and a continued commitment to robust, cost-effective energy efficiency,” puts the state’s 100% renewable goal “within reach.”
“I am committed to ensuring that Rhode Island leverages the benefits of market competition to secure cost-competitive renewables and reduce long-term energy costs while fostering clean energy jobs and mitigating greenhouse gas emissions across our economy,” Ucci said.
Rhode Island had 933 MW of renewable energy in its portfolio as of the second quarter of 2020, representing a ninefold increase since 2016. The state target from OSW energy is 1,030 MW, with 430 MW currently selected and the potential addition of 600 MW, which would meet the target.
Added Rhode Island Secretary of Commerce Stefan Pryor: “Among U.S. jurisdictions, Rhode Island is the pioneering state in the offshore wind field. Given its first-in-the-water status, Rhode Island has positioned itself as a premier destination for offshore wind companies, suppliers and related enterprises. Under Governor Raimondo, we are pleased to be pursuing a second significant expansion of our turbine constellation, and we look forward to partnering with the industry and key stakeholders to ensure the success of this expansion.”
Northeast Clean Energy Council President Peter Rothstein said the next 10 years “must be a decade of action” to reduce greenhouse gas emissions by procuring more renewable resources.
“With this announcement, Governor Raimondo recognizes that investments in offshore wind not only move us closer to 100 percent renewable electricity, but also put Rhode Island in a pole position to reap the economic benefits that this industry will deliver,” he said.
MISO board members on Monday gave an initial nod to MISO’s $4 billion 2020 Transmission Expansion Plan (MTEP 20).
In a special Oct. 26 conference call, the four-member System Planning Committee of MISO’s Board of Directors voted unanimously to send MTEP 20 to a full board vote in early December.
Director Mark Johnson said the committee’s voting took place about a month earlier than usual this year to allow more time for the full board of directors to deliberate about the plan.
MTEP 20’s 515 projects include 75 baseline reliability projects, accounting for 18% of the plan’s cost, but they still come in $70 million below MTEP 19’s crop of baseline projects. It also includes 100 generator interconnection projects, representing 15% of costs.
MISO said it’s normal to have boom-and-bust investment years in terms of baseline reliability projects. This year most baseline projects are located within the Central planning region, which account for $372 million.
Executive Director of System Planning Aubrey Johnson said while MTEP 20’s spending tracks closely with the 2019 package, spending on generator interconnection projects increased from $269 million last year to $606 million this year.
MTEP 20 stats | MISO
“We’ve seen an almost three times increase of interconnection projects from this year to last, and we attribute that to clearing out some of the [interconnection queue] backlog,” he said.
MISO’s Planning Advisory Committee approved MTEP 20 in September; however, some members asked that MISO be more specific about the breakdown of projects in its “other” category. (See “Members Endorse MTEP 20,” MISO Planning Advisory Comm. Briefs: Sept. 23, 2020.)
The “other” category includes load growth-based projects, age and condition-based upgrades, and economic, environmental and reliability-driven projects. It usually represents the lion’s share of MTEP spending and this year accounts for $2.8 billion. MISO said 40% of “other” projects are needed for reliability, 36% for age and condition, 21% for load growth and 2% for other local transmission owner needs. RTO executives said some load pockets are experiencing load growth, even if it’s not occurring footprint-wide.
“The old proverbial ‘other’ bucket, I really encourage MISO to refine that. … It’s just a little too nondescript, and I know I’m not the first director to raise this issue with MISO management,” Mark Johnson said.
“More definition would be helpful,” agreed Director Todd Raba.
MISO executives also briefed the board of directors on the removal of Entergy Louisiana’s nearly $74 million, 27-mile, 230-kV, Waterford-to-Churchill transmission line approved as part of MTEP 16. MISO said the line no longer demonstrates the benefits it once did. Over four years the benefit-cost ratio dropped from 2.3 to about 0.2, according to Entergy. (See “Entergy Cancels MTEP 16 Project,” MISO in Final Stretch of $4B MTEP 20.)
MISO’s agreement to rescind the project ruffled some feathers within the stakeholder community this fall.
MISO Director Nancy Lange asked whether stakeholders disagreed with the decision to withdraw the project or the opaque manner in which the decision was made.
Aubrey Johnson said some stakeholders weren’t comfortable with MISO conducting a withdrawal analysis in the background without notifying them of the study’s process or progress. He said some argued that MISO didn’t provide them time to perform their own no-harm analyses to find out if the project’s removal would negatively impact other subsequently approved MTEP projects.
“For this project, I do not believe the benefits are there. Whether we need other transmission in the area is an ongoing question,” Vice President of System Planning Jennifer Curran said.
“I think the question is, if you’re going to have projects withdraw like this, how do you present that to the stakeholders earlier in the process, if you will,” Aubrey Johnson said. He added that MISO will re-examine its process of monitoring and recommending withdrawal of MTEP approved projects.
New Jersey is moving closer to adopting wide-ranging programs promoting the deployment of electric vehicles and energy storage throughout the state.
The New Jersey Board of Public Utilities held two days of hearings last week to hear comments on Public Service Electric and Gas’ petition to implement the EV and energy storage portion of its Clean Energy Future program. Commenters at the hearing were generally in support of the petition.
The BPU approved the company’s plan last month to commit $1 billion toward energy efficiency investments over the next three years.
Joseph Accardo, vice president of regulatory affairs for PSE&G parent Public Service Enterprise Group, provided an overview of the EV and storage portion, saying the initiatives will bring the benefits of cleaner air, more renewable resources and a more reliable electrical grid through electrification of transportation and “targeted, cutting-edge energy solutions.”
“PSE&G’s electric vehicle filing supports the development of electric vehicle infrastructure and energy storage solutions in New Jersey to benefit customers, meet state goals and spur the state’s green economy,” Accardo said.
PSE&G originally filed its petition with the BPU in October 2018. The objective of the program is to accelerate EV adoption and deployment of storage technology in New Jersey, supporting the goals set forth in the state’s energy master plan, Accardo said. (See NJ Unveils Plan for 100% Clean Energy by 2050.)
The plan calls for the installation of nearly 40,000 EV charging stations across the state. As charging stations have grown in other states at a pace of purchase of vehicles, Accardo said, New Jersey ranks 45th in the country for stations per registered EV. He said PSE&G’s plan emphasizes that the state needs to provide consumers with easy access to charging infrastructure.
For the EV portion of the program, PSE&G is seeking BPU approval to commit up to $261 million in direct investments over a period of six years. It includes a $93 million residential subprogram that will pay for the cost of a home EV charger and installation for EV users, with a cap of $2,000 per installation.
The proposal includes a $39 million mixed-use charging subprogram and a $62 million DC fast-charging subprogram. It also features a $45 million vehicle innovation subprogram to promote EV use, including a $33 million electric school bus project and $12 million to fund other vehicle electrification projects.
Approving the program would initially increase electric rates to customers by about $9.7 million over an 18-month period, PSE&G said, with rate recovery continuing until 2064. A peak revenue requirement would occur in the 2024-2025 time frame.
Storage Component
New Jersey’s Clean Energy Act calls for 600 MW of energy storage by 2021 and 2,000 MW by 2030.
For the storage portion of its program, PSE&G is seeking approval to commit up to $109.4 million in direct investment over a period of six years. It includes subprograms to smooth intermittent solar generation ($13.1 million), resolve forecasted distribution grid overload conditions ($38.6 million), deploy mobile battery storage devices ($20 million), develop microgrids for critical facilities ($25.7 million) and facilitate peak reduction for public sector facilities ($11.9 million).
Approval of the program would increase rates by about $700,000 over an 18-month period. Rate recovery for the program would continue until 2045, with a peak revenue requirement in the 2025-2026 time frame.
Stakeholder Responses
A typical PSE&G residential electric customer would see a $1.24 (0.09%) increase in their annual bill, the company said.
Testimony at the BPU hearing featured several hours of stakeholder comments from across the state, with all parties expressing support for PSE&G’s proposal.
James Sherman, vice president of Climate Change Mitigation Technologies (CCMT), a New Jersey-based developer of medium- and heavy-duty battery electric truck projects, provided testimony on the EV program. Sherman said the possibility exists to make New Jersey “the East Coast center” of the zero-emission, medium-duty truck and bus industry.
Sherman said his company is closely following developments in California’s EV program, especially within the California Energy Commission. (See California Looks to EVs for Grid Resilience.) He said the PSE&G subprogram is consistent with what is happening in California and will accelerate charging infrastructure to deploy more EVs.
The school bus fund and the vehicle innovation portion are also key, Sherman said, providing money for towns and cities to convert to EV fleets. CCMT is working on building an EV bus and truck manufacturing plant in Patterson, he said, with operations to begin in 2021 if sufficient orders and state-level funding are in place. The plant would add 45 new jobs at full production, with 500 trucks and buses being manufactured per year.
Sherman said all the EV programs fit like a puzzle, creating a new clean energy economy in the state.
“When put together, we get advanced, zero-emission vehicle technologies, job creation and, hopefully, increased grid reliability,” Sherman said. “We get school buses made in New Jersey and driven in New Jersey. We get immediate clean air benefits at the community level.”
Shihab Kuran, CEO of Power Edison, a New Jersey-based clean energy solutions company focused on energy storage, said he is in “full support” of PSE&G’s filing, though he called the storage subprogram a “very, very small step” toward increased reliability. He said he would like to see it approved quickly to move on to other programs with “meaningful megawatts” in helping New Jersey meet its goals.
“We are far behind other states in the U.S. when it comes to energy storage,” Kuran said. “We have set up our own targets. … But frankly, I don’t see a path for how we can get to 600 MW by 2021. We should have started the work two to three years ago.”
Trenton Mayor Reed Gusciora also spoke in support of the programs. He said his city is made up of dense areas experiencing the pressures of urban environments, including pollution.
Gusciora said the concept of environmental justice is important to the residents of Trenton, leading to “fairness, opportunity and a better quality of life.” Steps have been taken by companies and communities to be more environmentally friendly, he said, but only a small portion can be done on a local level to solve current environmental issues.
The mayor said proposals like PSE&G’s are a step in the right direction, spurring statewide interest in EVs that will lead to better air quality.
“PSE&G’s proposal to deploy nearly 40,000 EV charging stations across the state is the kind of initiative that can deliver public health and environmental and economic benefits to all residents across New Jersey,” Gusciora said.
Discussion of high-tech solutions to climate change and the proliferation of electric vehicles turned to soil amendments and forest management at last week’s California Energy Commission EPIC Symposium.
The annual three-day summit is an expo for the cutting-edge projects funded by the state’s Electric Program Investment Charge (EPIC) to ratepayers. The program awards more than $130 million a year to entrepreneurial efforts to electrify buildings and transportation, and to store renewable energy and enhance grid resilience.
Typically, the summit fills exhibit halls with the latest electric vehicles from the likes of Honda and BMW and packs ballrooms with hundreds of participants. This year’s summit tried to recreate that experience with virtual exhibit halls and a variety of forums in which stakeholders discussed the state’s latest efforts toward decarbonization.
On Wednesday, Wade Crowfoot, secretary of California’s Natural Resources Agency, talked with CEC Chair David Hochschild in an online “fireside chat” about the state’s role in clean energy innovation. Crowfoot said an Oct. 7 order by Gov. Gavin Newsom to better manage the state’s forests and farmlands was a new front in the battle against climate change and wildfires.
More than 4 million acres have burned in California this fire season, one of the worst on record. Smoke blanketed the West and traveled to the Midwest and East Coast. Particulate matter choked Los Angeles and San Francisco, giving California the worst air in the world at times in August and September.
Tens of millions of tons of greenhouse gasses billowed skyward, canceling out the state’s gains in reducing emissions from fossil fuel generation and gas-powered vehicles, Crowfoot said.
“All that smoke that’s going into the air and going into our lungs is obviously finding its way into the atmosphere,” Crowfoot said. “And unfortunately, this catastrophic fire [season] is actually wiping out these emissions savings that we have in all of these other areas. So, smart land management of working forests, for example, will reduce emissions from these catastrophic wildfires.”
Newsom’s order instructs Crowfoot’s agency and other state entities to develop strategies to restore wetlands, manage forests and improve soils, with the goal of sequestering more carbon.
“There’s been an increasing global movement that recognizes the way that we steward land — both our natural areas and our working lands, like farms and ranchlands — actually matters to the global effort to combat climate change,” Crowfoot said. One effort he cited involves recycling organic waste and adding it to farmland, allowing soil to absorb more carbon and retain more water.
The governor’s order was sparse on details, leaving implementation to state agencies. The extent to which the state can direct forest owners to act on the order must still be determined. Millions of acres of the state’s forests are owned by the federal government, logging companies and utilities such as Pacific Gas and Electric. Those forests contain immense stands of dead and dying trees from years of drought and bark beetle infestation. The Creek Fire in the rugged Sierra Nevada foothills near Fresno grew into one of the largest fires ever, at 359,000 acres, by feeding on dead trees in and around the Sierra National Forest.
On its Earth Observatory website, NASA showed the dense concentrations of black carbon fouling the air after a series of lightning-sparked wildfires in mid-August.
Smoke from California wildfires covered the West in August. | NASA Earth Observatory
“Black carbon particulates, commonly called soot … can harm humans and other animals by entering the lungs and bloodstream; it also plays a role in global warming,” NASA said.
Mass Switch to EVs and Electric Heating Needed
Crowfoot called a Newsom order on EV adoption a “huge and bold stroke” toward electrifying transportation. The Sept. 23 order requires all new passenger vehicles sold in the state to be zero-emissions vehicles (ZEVs) by 2035 and provides a much needed market signal to car manufacturers to focus their efforts on EV production, he said.
The transportation sector accounts for more than half of California’s carbon emissions; the order will reduce automobile emissions of GHGs by 35%, the governor’s office said. (See Calif. to Halt Gas-powered Auto Sales by 2035.)
Meeting Newsom’s mandate — and the state’s larger decarbonization goals — will require rapid acceleration of EV sales and charger installations. (See Can California Meet Its EV Mandates?)
Senate Bill 100 requires the state’s load-serving entities to provide retail customers with 100% carbon-free energy by 2045, and an executive order by former Gov. Jerry Brown requires the state to attain carbon neutrality the same year. Brown signed both in September 2018.
To meet the requirements, Southern California Edison estimates that 75% of light-duty vehicles on the road must be EVs by 2045, along with two-thirds of medium-duty vehicles and a third of heavy-duty vehicles, Russell Ragsdale, SCE’s director of asset and engineering strategy, said during a symposium panel on accelerating the integration of renewable energy.
SCE is pushing forward with adoption of EVs through its “charge-ready” programs for light-, medium- and heavy-duty vehicles, Ragsdale said. The utility is “looking to accelerate the adoption [of EVs] across California by enabling access to charging and helping to limit range anxiety,” the fear drivers have of running out of power, he said.
In August, the California Public Utilities Commission gave SCE’s efforts a big boost by authorizing $437 million to fund the installation of 38,000 charging ports for EVs via SCE’s Charge Ready 2 infrastructure program, the largest single-utility EV charging program in the nation. (See CPUC OKs 1.2 GW of Storage by 2021, 38,000 EV Chargers.)
Switching to EVs won’t be enough; Californians must electrify buildings so that 75% of water and space heating will be electric to meet the state’s 2045 decarbonization requirements, Ragsdale said.
Moreover, California will need huge new amounts of renewable energy, including 80 GW of utility-scale generation and 30 GW of utility-scale storage, plus 30 GW of distributed generation and 10 GW of distributed storage, he said.
“This combination of cleaning the power source and then electrifying these various uses will help us to get the carbon out of our economy,” Ragsdale said.
ISO-NE last week presented its notice of initiation for the Cape Cod Resource Integration Study, which will focus on potential infrastructure to interconnect queued generation and quantify resources that could interconnect with new transmission according to the network capability interconnection standard (NCIS).
Conceptual cluster-enabling transmission upgrades include adding new 345-kV transmission infrastructure between West Barnstable and Bourne, Mass. The study will also identify the number of megawatts that could be interconnected while recognizing the export limitation from Cape Cod from a 2019 economic analysis by the New England States Committee on Electricity (NESCOE).
The Cape Cod Resource Integration Study will focus on the addition of new 345-kV transmission infrastructure between West Barnstable and Bourne, Mass. | ISO-NE
Al McBride, a system planner for ISO-NE, said the RTO had completed several interconnection studies on Cape Cod, most recently a system impact study for the proposed Vineyard Wind 2, which would connect to the 345-kV West Barnstable substation.
The project, which is under evaluation by utilities in Massachusetts, could be either 400 or 800 MW; ISO-NE studied the 800-MW option. It would require network upgrades, including a 345-kV line from West Barnstable to Bourne, a new 345-kV substation at Bourne and a 345/115-kV autotransformer at West Barnstable.
There are also several more interconnection requests in the queue, including 2,948 MW of generation and an elective transmission upgrade, seeking to interconnect to Barnstable/West Barnstable or Bourne.
The conditions used in NCIS system impact studies, described in Planning Procedure 5-6, include peak-load and light-load testing and resources modeled at their nameplate ratings (50 or 0 degrees Fahrenheit, as appropriate). New resources may also dispatch against existing resources under NCIS interfaces modeled at the transfer limit.
One admittedly “curious” stakeholder asked McBride why the RTO is initiating this study now, as potentially eligible projects for this cluster have already had feasibility studies done.
“This isn’t a new realization that there are more megawatts here than can be fully deliverable from the cape,” the stakeholder said.
McBride said there was consideration given to starting the cluster “sooner … but because we were able to complete [the Vineyard Wind 2 study] serially, we did so, and we feel that’s the way that the process is supposed to be implemented.” McBride added that “given our experiences with [Vineyard Wind 2], and what we were seeing on the system, and then our jump ahead into the future through the economic study … all of the conditions became apparent, and so that’s why we’re initiating it now.”
Another stakeholder asked McBride if the peak load for Cape Cod “is different rather than simultaneous with the system peak, how is it going to be handled in this study?”
“Somewhere like the cape, for nine months to approximately a year, you’re going to be experiencing lower loads, and you might use less of these injected megawatts,” McBride said. “And if there are any time constraints, getting megawatts off the cape might add to that. … I don’t have anything necessarily specific that we might add into this study, but it’s something that we’re thinking of, and if we have anything more, we’ll come back” to the committee.
The RTO will accept additional stakeholder feedback on the initial conceptual transmission upgrades until Nov. 20 and present results of the Cape Cod Resource Integration Study within 12 months. However, the economic analysis previously performed by NESCOE and the interconnection studies is expected to speed up this time frame.
After the publication of the final report, the RTO will open the window for eligible projects to proceed to the cluster system impact study (CSIS) phase. Eligible projects must meet CSIS entry requirements to move into the study, including submitting a cluster participation deposit.
Lessons Learned on Order 1000 Competitive Solicitations Process
ISO-NE’s Michael Drzewianowski introduced the RTO’s plans to gather feedback for “lessons learned” on competitive solicitations under FERC Order 1000. The recently completed Boston 2028 transmission solicitation was the RTO’s first-ever request for proposals under Order 1000.
“While the cost of the competitive solicitation was considered a success, the ISO and stakeholders have noted areas that could be improved, and the ISO is taking this formal process to collect and evaluate feedback from stakeholders,” Drzewianowski said.
The RTO ran its initial RFP from December 2019 through July of this year. The process concluded with selecting a $49 million project by utilities National Grid and Eversource Energy, which was the cheapest of the 36 received proposals. (See ISO-NE Chooses Incumbent as Boston RFP Winner.) ISO-NE also promised stakeholders, who challenged its selection process, discussions on what did not work well or could be improved in future RFPs and their execution, including developing a submittal template that will summarize any recommendations and guide Tariff and process changes. Drzewianowski added that the RTO already initiated one-on-one discussions with qualified transmission project sponsors who submitted proposals.
Drzewianowski said if there are issues with the RFP or suggested improvements, he would encourage stakeholders to work through the process. Comments on the draft lessons learned submittal template are due Nov. 2, and the final template will be distributed at the Nov. 6 PAC meeting. Completed templates should then sent to the RTO by Nov. 25, with a discussion of the submittals slated for the Dec. 16 committee meeting.
RTO officials, stakeholders and academics discussed the challenges of operating a grid with increasing renewables and uncertainty at MISO’s three-day Market Symposium last week. Here’s some of what we heard.
Removing Barriers, Accepting Regional Differences
FERC Commissioner Richard Glick, speaking with Richard Doying, MISO’s executive vice president of market and grid strategy, said the commission has done much in the last decade to remove barriers to entry for new technologies, noting its rulemakings in Order 764 (intermittent generation), Order 841 (electric storage), Order 845 (demand response) and Order 2222 (aggregation of distributed energy resources).
Richard Doying, MISO executive vice president for market and grid strategy (left), and FERC Commissioner Richard Glick | MISO
“But there’s more to do, for instance, on hybrid technologies,” he said, noting the commission’s technical conference on the subject in July. (See Hybrid Resource Developers Ask for Uniform Rules.)
MISO has already seen a substantial resource shift since 2005. Future scenarios suggest these trends currently underway will continue into 2030. | MISO
On Tuesday, the commission will hold a technical conference on offshore wind. “I think there’s a lot we can do in terms of transmission development and transmission planning to figure out if there are any barriers to the development of transmission systems that would enable a significant number of offshore wind farms to be developed” on the East Coast, he said.
Glick also commented on the commission’s tradition of letting grid operators in different regions adopt tailored approaches to compliance with FERC’s rulemakings, joking, “I wish I had a dime for every time I hear, ‘Let a thousand flowers bloom.’
“I think it’s important for the commission to continue to allow RTOs … the flexibility they need,” he said. “I would say it’s still important that we have a baseline,” he added. “We need to … make sure that the goal is achieved.”
360-degree Review for RTOs
Lisa Barton, American Electric Power’s executive vice president for utilities, joined MISO Chief Operating Officer Clair Moeller on Wednesday for a discussion about seams coordination and right-sizing infrastructure investments.
Lisa Barton, AEP | MISO
Asked how MISO could improve its seams management, Barton said the RTO should engage in a lessons-learned exercise with its neighboring RTOs and subject itself to a 360-degree review by regulators, industry and other stakeholders: “What are we doing well? What do we need to work on? What … would help move the ball from a seams standpoint?”
Barton said other stakeholders should subject themselves to a similar review. Individual stakeholders “don’t always behave as well as we should either. … We can be self-interested. But this is an industry that must be about the customers. It must be about the communities,” she said.
Decarbonization goals within MISO | MISO
“I think if there’s one thing we know about the future, it’s got to be about decarbonizing. … If we can accelerate the transformation … to electric vehicles, think about what that does for the industry. Think about what that does for the environment. There’s so many good things associated with that.”
Moeller agreed. “There’s something for everybody if we all pull together. … When we wander into the parochial — ‘my interest is more important than everybody else’s interests’ — we tend to get into trouble.”
MISO COO Claire Moeller | MISO
While the industry excels at responding to hurricanes and other crises, Barton said, it needs to become more proactive and shouldn’t worry so much about overbuilding.
“I hear that from economists quite a bit. ‘Well, there might be 5% of capacity in that transmission line that’s not used.’ That’s OK. We shouldn’t be afraid of that,” she said. “What we should be afraid of is having load-shed events [and] not having sufficient resource adequacy. … That’s when you cannot have electric vehicles be a part of your future and a part of the solution.”
“I ask people occasionally, ‘Which mistake would you like to make: the one where you build a little too much a little too early, or the ones where you didn’t build enough?’” Moeller responded. “The ramifications of those two mistakes are dramatically different.”
Moeller said he believes a growing “coalition of the willing” is in favor of an “interstate highway sort of grid” to facilitate the kind of energy transfers that allowed MISO to maintain reliability during its last polar vortex.
“We had a 25% forced outage rate on every resource: coal, gas, demand-side management, wind. You guys in PJM were kind enough to send us 19,000 MW an hour for about six hours, which for us was the difference between load shed and not load shed. …
“I think we need to find a way to value that [resilience] so it shows up in a business case, so we can make the investments we need to make the future safe and affordable,” he added.
Jennifer Curran, MISO | MISO
Jay Caspary, vice president of consulting firm Grid Strategies, had a similar take in a session moderated by Jennifer Curran, MISO vice president of system planning and chief compliance officer, on “Infrastructure as an Enabler.”
“One of the benefits I think we have in the near term is there’s a lot of assets that are reaching their end of life. I think if we started working with our neighbors, we can identify some key [transmission] corridors and target those in our regional and interregional plans and move forward,” Caspary said.
“You know, when [President Dwight] Eisenhower [proposed] the interstate highway system in 1955, it took decades for that to come into fruition. And it had to evolve as things changed, and spurs were added and toll roads [were added] to make the traffic flows efficient around metropolitan areas. I think we need something like that that we can all buy into.”
Macrogrid or Microgrid?
Anjan Bose, Washington State University | MISO
“It’s fashionable in some circles to say the big grid is going to go away. I doubt that that is the case,” said Anjan Bose, regents professor at Washington State University. “As long as there is going to be cheaper generation resources like wind somewhere in the country and a lack of it in other areas, we are going to see the need for transmission. But I do want to emphasize that the microgrid concept — the fact that there are a lot of technologies coming in [at] the edge of the grid — is not going to go away, and it will probably speed up. The question is, how do we work that into planning, and how do we make sure we take advantage of these microgrids?”
Planning Challenges
“The need to plan for extreme events … has always been difficult because of the infrequency at which they occur. So instead, we plan to the standard reliability criteria: N-1 or N-1-1, maybe N-2. And extreme events which may be N-K — where K is a very large number — don’t get that much attention,” said James McCalley, a professor in electrical and computer engineering at Iowa State University. “Yet it is clear that we may be seeing more frequent occurrences of hurricanes, floods, wildfires — and being from Iowa, I’m very sensitive to derecho, the straight-line winds that we had recently here in my state.”
James McCalley, Iowa State University | MISO
Bose questioned whether the kind of probabilistic methods used in planning would be applicable for operations.
“In planning, we tend to take into account the probability of these occurrences. The question in my mind is: Are those same tools good enough in the operations area, or even applicable in the operations area?
“In operations, we are not using probabilistic methods to determine how probable the region is to overload or under-voltages or whatever. We use very deterministic methods, meaning we say, ‘Well, if this happens, then we will be able to survive it. Or if this happens, we’ll really have a problem over in this part of the grid.”
Planning is also more difficult because there are “so many different objectives to be taken care of,” he continued.
“The reliability criteria are getting more difficult to find out what they actually mean. … In California, for example, where we ran out of resources [and were forced into load shedding in August], the question really was: Is the loss of wind an N-1 contingency, and should we be putting that into our studies?”
Although NERC reliability standards currently have no metrics for measuring resilience, “it’s obviously going to come,” with the risk of forest fires, earthquakes and derechos to be considered in some regions, he said. “That has to be translated into mathematics and the tools that we have.”
Julian Leslie, National Grid | MISO
Julian Leslie, head of networks for National Grid Electricity System Operator in the U.K., said grid operators need data and input about stakeholders’ visions of the future to ensure they build the right tools for managing operations.
“I never thought working for a transmission system operator [that] I’d be talking to electric vehicle manufacturers or Google [and Amazon] and people like that just to really understand what their direction is, what is their future strategy.”
McCalley called for increasing “the dimensionality of the solution space — that’s a complicated way of saying we need more ways to solve our problems.”
It also means tapping into the control capability of wind. “They have inertia. They have control capability,” McCalley said. “Let’s use it.”
Gathering Data
Growing amounts of wind and solar will increase net-load ramps both in frequency and magnitude. Out-of-market actions taken during emergencies can lead to price suppression, and the absence of price-responsive demand requires MISO set prices administratively during shortages. | MISO
Bose acknowledged complaints that the research community has not been getting the data needed to be able to do proper studies. “But I think [the Department of Energy] and others are now trying to get enough synthetic data on which research can be done, which doesn’t expose [the] sensitivity of actual transmission data.
“The bigger problem in my mind is the power companies getting the data that they need to do their planning work. This is a serious [problem], especially on the Eastern Interconnection where data exchanges have been somewhat limited.
Jay Caspary, Grid Strategies | MISO
“I think this needs to be looked at from an industry point of view and a national security point of view as to how this data can be kept so that everybody — all the power companies — can do legitimate work on the expansion planning. … All the data exchanges that take place today is done by bilateral agreements. This is ridiculous because you know there are 18,000 power companies in the country. So, there need to be agreements that are countrywide. That needs to happen so that this data is available. As to what data is needed, that depends on the tools we have [and] on what we are trying to solve.”
Caspary said the industry is good at sharing operational data. “When it gets to planning data, we share models, but we really don’t get into the actual performance characteristics of the components in the system. I would be particularly interested in the remaining life that’s being projected on assets and how we would … project the availability of those assets and the mean time to failure.”
Current models assume every asset has the same probability of failure, he said. “I just don’t think that’s a very smart way of planning the system.”
Officials from CAISO, NYISO and French grid operator RTE joined MISO on the final day of its Market Symposium on Friday to discuss the challenges of developing data analytics to support system operators’ decision-making.
Elliot Mainzer, who became CAISO’s CEO last month after 18 years at the Bonneville Power Administration, said one of his first actions in his new job was creating a new chief operating officer position.
“We’re integrating our operations and transmission infrastructure and market policy and technical groups under one executive so that we can maximize alignment among those groups and make sure that the technical platform evolves as efficiently across the organization as necessary.”
When BPA started adding wind generation more than a decade ago, it had no tools to address ramping issues and curtailments. The difference between “accommodating” renewables and “integrating” them in the system was developing those tools, he said in a conversation with Todd Ramey, MISO’s chief digital officer.
Todd Ramey, MISO (L) and CAISO CEO Elliott Mainzer | MISO
“If you want to really integrate them as efficiently as possible, you have to take that time to do the design work,” Mainzer said.
BPA introduced intra-hour scheduling, held a competition to find the best wind forecasting provider and aligned its tariff and pricing mechanisms to encourage operators to use the new tools.
David Edelson, NYISO | MISO
He said he learned the need to involve control center operators in the design of the systems from the beginning.
“Something that was very important was, first of all, making sure that the systems were integrated so that folks weren’t running around having to make 12 decisions at the same time. … We just don’t have a lot of room for a lot of friction in the system anymore as we’re trying to meet our resource adequacy requirements.”
Keri Glitch, MISO | MISO
David Edelson, NYISO’s manager of operations performance and analysis, said operators need to make “second-to-second decisions.”
“There’s really little time to interpret data; therefore, that data needs to be presented to control room operators very clearly, in ways that suit their preferences so that they can make quick decisions — generally binary decisions,” he said during a panel discussion moderated by Keri Glitch, MISO’s chief information security officer.
Avoiding False Positives
“They can’t be presented with unnecessarily large volumes of data — large numbers of false alerts — because that’s going to lead to mistrust of the data, as well as hesitations in their response,” Edelson said.
Mykel Kochenderfer, Stanford University | MISO
False positives was also the subject of remarks by Mykel Kochenderfer, a Stanford University associate professor who develops applications for aerospace and automated vehicles. “Many of the challenges are exactly the same” as in the power sector, he said, recalling his work on an aircraft collision avoidance system.
“In this situation, you have imperfect sensor information, so you don’t know exactly the current state of the world. And you also have imperfect information about how the world will evolve: You don’t know the future trajectories of the other aircraft. And you have competing objectives. On one side, you want it to be extremely safe, and on the other side, you want to be efficient. You don’t want to be alerting the pilot constantly to avoid collisions when there’s not a significant threat present.”
The system took about a decade to develop, “and much of that time was just establishing trust that the system will behave correctly in operation,” he said.
For that reason, Kochenderfer said, not all artificial intelligence is suited for mission-critical systems. “A lot of artificial intelligence is just using statistics and optimization together, but it has also come to mean … the use of neural networks.
“Neural networks are incredibly powerful. We’ve had major breakthrough in terms of computer vision applications and natural language processing applications. But in those domains, failure is tolerable. If Alexa doesn’t recognize your question correctly, people won’t be losing power; airplanes won’t be crashing.”
Edelson said the power sector will have to overcome its conservatism to get the most out of advanced analytics.
“We operate the system conservatively, justifiably so, because of its importance. … We apply margins large enough to accommodate fairly infrequent events. [Getting] system operators to rely on more advanced data analytics that allow for the system to be operated leaner will require organizational, cultural changes. That’s going to be a challenge.”
Changes will be required as the grid moves away from the traditional dispatchable thermal resources to much more variable generation, Mainzer said. As “we start running into real resource adequacy challenges … using every megawatt of available supply in the system — both bulk [system] resources and the behind-the-meter and distributed energy resources — is going to become increasingly important,” he said.
‘Trash in/Trash Out’
Anthony Papavasiliou, associate professor in the Department of Mathematical Engineering at the Catholic University of Louvain in Belgium, talked about the “trash in/trash out” challenge in estimating the need for system reserves.
Anthony Papavasiliou, Université catholique de Louvain | MISO
“One of the reasons why … stochastic unit commitment is difficult is that you need to create reasonable inputs, the scenarios: Which resource should be outaged? Which forecast error should we consider? Building that input so that you get a meaningful answer from the optimization itself can be as difficult an exercise as actually solving the optimization problem that gives you the answer.”
Kochenderfer said early AI applications sometimes failed because they did not properly account for uncertainty.
Antoine Marot, RTE | MISO
“Another potential pitfall is using overly complicated methods. … We should definitely strive to test out the simplest possible ones first and then only use more complicated methods if we can justify that complexity in terms of performance on well defined metrics.”
Some complexity can’t be avoided, however, said Antoine Marot, AI team lead for RTE, the French transmission system operator.
“There’s been a lot of research for the last 10 years about how do we endure more uncertainties in the system. How do we go beyond [the] N-1 deterministic role [to] considering more probabilities?” he said. “Since we have a lot more risk and uncertainties to assess …. the thing we’d like to do for sure is speed up the computation of the simulations.”
NEPOOL’s Reliability Committee failed to endorse cost overruns on Eversource Energy’s Greater Boston Transmission Project during the committee’s monthly meeting Oct. 20.
The proposal won 60% support, below the 66.7% needed for a recommendation to the PC.
The project’s cost increased by $191 million (33%), primarily because of the underground Wakefield-Woburn, Mystic-Woburn and Sudbury-Hudson lines. Those three lines will cost an additional $147 million, which brings their total to $352 million.
The need to underground the 115-kV Sudbury-Hudson, initially proposed as an overhead line, accounts for an increase to $91 million, which is more than double the original cost of $45.3 million. Eversource was unable to secure property leasing rights from the Massachusetts Bay Transportation Authority (MBTA) for an overhead line. The project has an in-service date of December 2023.
Eversource performed an updated alternative analysis and found that a new 9-mile, 115-kV underground transmission line within an MBTA right of way was the “most cost-effective and constructible alternative.” The two alternatives analyzed — a new 10.3-mile, 115-kV underground transmission line entirely in roadways ($110.4 million), or multiple upgrades to convert a 14.5-mile, 69-kV line to 115 kV, reconductor 11.6 miles of other 115-kV lines and upgrade seven substations ($116.1 million) — had higher costs.
Hydro‑Québec transmission substation
The Wakefield-Woburn and Mystic-Woburn lines increased to a combined $260.6 million from $160.2 million, representing more than half of the total cost increase. Eversource said additional restrictions on the design and construction required a realignment of underground work within roadways to avoid interference with existing utilities. Restrictions on work hours and the number of crews also increased the construction bids, the company said.
The remaining 30 parts of the project saw an additional 12% increase in cost to $411 million from $367 million. However, these transmission cost allocations were previously supported by the RC and approved by ISO-NE.
RC Supports Proposed Revision to ISO-NE/NYISO Coordination Agreement
The RC voted in support of the RTO’s proposed revisions to its Coordination Agreement (CA) with NYISO to eliminate the need to make a FERC filing when the grid operators update their description of shared interconnection facilities.
The grid operators share interconnections at NY/NE Northern AC Interconnection (comprising the PV-20, K7, K6, E205W, 393, 690/FV and 398 interties), the Northport-Norwalk Harbor Cable and the Cross-Sound Cable Interconnection (CSC).
ISO-NE and NYISO will update the detailed list of interconnection facilities on their respective websites rather than maintaining it in Schedule A of the CA, which requires a FERC filing any time changes are made to it. The addition or removal of an interconnection would still go through the grid operators’ respective stakeholder processes and filed with FERC.
ISO-NE and NYISO have agreed to add the “+/-” notation to the CSC Intertie, which is in the list of interconnections within the list of interconnection facilities that will be posted on both websites. ISO-NE will use “its best efforts” to notify the RC within one week following the posting of any revision to the listing of interconnections. If an RC member identifies and reports a perceived error, the RTO will contact NYISO and discuss the concern. The posting will be modified if they agree a change is warranted. ISO-NE will notify the RC member and explain why the change is not justified as well. Entities can also subscribe to the ISO-NE webpage to receive immediate notices of the revision of posted documents.
The Participants Committee will vote on the CA revisions at its Nov. 5 meeting. ISO-NE and NYISO expect to file the revised CA by the end of the year with an effective date in early 2021.
ICR and Related Values for ARAs Recommended by Vote
The RC voted to recommend that the PC support ISO-NE’s proposed installed capacity requirement (ICR) and related values for Forward Capacity Auction 12’s three annual reconfiguration auctions (ARAs) to be conducted in 2021.
The committee approved net ICRs of 32,925 MW for 2021/22 (ARA 3), 32,765 MW for 2022/23 (ARA 2) and 32,980 MW for 2023/24 (ARA 1). The committee also approved a 958-MW value for the Hydro-Québec interconnection capability credit for ARA 3, with the amount rising to 969 MW for ARA 2 and down to 941 MW for ARA 1.
The PC will vote on the ICR and related values on Nov. 5, with a FERC filing expected by Nov. 30.
ERCOT staff have begun issuing price corrections and resettling 25 operating days affected by two market errors earlier this year.
The Board of Directors approved the price corrections earlier this month, as the errors were not caught in time by staff to resettle the operating days on their own. Staff are working with stakeholders to better define “significance,” the only threshold required to take pricing errors to the board. (See “Board Approves 2 Sets of Price Corrections,” ERCOT Board of Directors Briefs: Oct. 13, 2020.)
Staff began issuing market notices with the final resettlements last week, two days at a time. The grid operator released tables with the resettled amounts for the June 8-9, June 10-11, June 12 and 15 and June 16-17 day-ahead operating days.
Dave Maggio, ERCOT | ERCOT
In an email to RTO Insider, Dave Maggio, ERCOT’s director of market design and analytics, said the resettlement tables are intended to provide a “market-wide net change in dollars broken out by different components of settlement.”
As an example, he said, the June 10 price correction addresses the effect on market participants that had day-ahead energy sales for that day. A net amount of approximately $5,000 will be redistributed to those participants.
“It’s worth noting that the same market participant is likely to be involved in multiple components of settlement,” Maggio said. “For example, an individual market participant may be receiving additional dollars for day-ahead energy sales and may owe additional dollars for day-ahead real-time obligations that were purchased.
“When it comes down to it, the resettlement is really just a shuffling of dollars around between market participants,” Maggio said.
RTC Group’s Protocol Work Completed
Staff said a stakeholder group working on revision requests needed to implement real-time co-optimization (RTC) has completed its review process by reaching consensus on all proposed protocol changes.
The revision requests will be finalized and posted with urgent status before going before several stakeholder groups, culminating in the Technical Advisory Committee and Board of Directors meetings in November and December, respectively. The TAC and the board will be asked to endorse and approve 11 change requests.
The Real-Time Co-optimization Task Force has met 33 times since April 2019, first developing key principles and then protocols. The Texas Public Utility Commission in 2019 directed ERCOT to add RTC, a market tool that procures energy and ancillary services every five minutes to find the most cost-effective solution for both requirements. The grid operator plans to go live with the tool in 2024. (See ERCOT Stakeholders Dig into Real-Time Co-optimization.)
ERCOT OKs Petra Nova’s Mothballing
ERCOT has approved the mothballing of NRG’s Petra Nova plant, part of the world’s largest carbon-capture facility. | NRG Energy
ERCOT said on Oct. 20 that a reliability analysis has determined NRG Energy’s Petra Nova Power Unit 1 is not needed to support the transmission system and can be mothballed as requested.
NRG last month sent the grid operator a notification of suspension of operations (NSO) that indicated it intended to place the resource in seasonal mothballs, effective Dec. 20. The unit will be available to the market June 1 to Sept. 30. (See NRG to Mothball Petra Nova CCS Plant.)
Petra Nova has a summer capacity of 71 MW. It was retrofitted at a cost of $1 billion to capture carbon from one of NRG’s nearby W.A. Parish Generating Station coal-fired units. Industry analysts don’t expect the plant to return to operation until oil prices stay consistently above $50 or $60/barrel.
ERCOT’s protocols require it to perform the reliability analysis before approving an NSO.
Voting is underway through 8 p.m. Nov. 4 to fill nine spots on NERC’s Standards Committee that are slated to open at the end of the year, following a nomination period that closed Oct. 15. (See NERC Seeks Nominations for SC Vacancies.)
Committee members — apart from the chair and vice chair — are elected from each of 10 industry segments to serve two-year terms. Each segment nominates two representatives, with terms staggered so that half of the membership is replaced each year.
NERC received only one nomination for the following segments, so they will run unopposed. Appendix 3B of NERC’s Rules of Procedure (ROP) requires each nominee to receive at least one vote before taking their seat:
Segment 1, Transmission Owners: Troy Brumfield, American Transmission Co.;
Segment 3, Load-serving Entities: Linn Oelker, LG&E and KU;
Segment 4, Transmission-dependent Utilities: Barry Lawson, National Rural Electric Cooperative Association;
Segment 5, Electric Generators: James Howell, Southern Co.;
Segment 7, Large Electricity End Users: Venona Greaff, Occidental Chemical;
Segment 8, Small Electricity End Users: Philip Winston, unaffiliated (formerly with Southern Co.); and
Segment 9, Federal, State and Provincial Regulatory or Other Government Entities: Kimberly Jones, North Carolina Utilities Commission.
Four of the nominees — Yeung, Oelker, Lawson and Greaff — are already serving on the committee. Of the remaining new members, Brumfield would replace Dominion Energy’s Sean Bodkin; Howell would replace William Winters of Consolidated Edison; and Winston would take over from independent member David Kiguel. The Segment 9 seat is currently vacant.
The Segment 7 seat will be vacant through December 2021. NERC sought an additional nomination to fill this position, but because only Greaff was nominated, the position will remain open for another year. Segment 6 (Electricity Brokers, Aggregators and Marketers) will see a competitive election, with current member Rebecca Moore Darrah of ACES Power challenged by Justin Welty, senior manager of NERC reliability standards at NextEra Energy.
Members of each segment will be sent emails with a link to vote for their respective election. Each registered ballot body in an industry segment may cast one vote per position being filled. Proxies are allowed, but members must designate their proxies via email to NERC prior to voting.
Canadian Nominees Still Lacking
Segment 10 (Regional Reliability Organizations and Regional Entities) will use an “alternate election procedure” as allowed in the ROP to choose its nominee, according to an announcement. No details about the procedure were provided; NERC’s only requirements for such actions are that the process be ratified by at least two-thirds of the registered entities in the segment in which it will be applied and that it be approved by NERC’s Board of Trustees.
The status of Canadian representation on the committee is also not clear at this time. Currently, only two representatives from Canada serve on the committee: the independent David Kiguel and Robert Blohm of Keen Resources. While Blohm will remain on the committee through December 2021, Kiguel is planning to step down at the end of the year.
This means that Blohm is set to be the country’s sole representative on the committee in 2021, which is not permitted because of a requirement that the committee have at least two Canadian members. Under the ROP, if the regular election does not result in enough Canadian representation, the Canadian candidate who receives “the next highest percentage of votes within their respective segment(s)” will be named as an additional member to serve until the following year’s election.
It is not clear what happens if none of the segments nominates a suitable candidate. However, with Segment 10 the only division yet to submit a nominee and none of the other candidates qualifying, the committee may have to consider more options soon.
