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December 15, 2020

MISO, SPP Stakeholders Applaud New Joint Study

MISO and SPP staff last week began putting meat on the bones of their joint transmission study, much to the satisfaction of stakeholders disappointed by years of fruitless combined studies between the two RTOs.

The Joint Targeted Interconnection Queue Study attempts a different approach to identifying — and funding — interregional transmission projects that could solve congestion issues along the MISO-SPP seam. (See MISO, SPP to Conduct Targeted Transmission Study.)

The year-long study will focus on the seam between Nebraska and Kansas in the west and Iowa and Missouri in the east. Staff said the grid is at its capacity for new generator interconnections in that region, making the next iteration of network upgrades too costly for interconnection projects to proceed.

MISO SPP — SPP’s and MISO’s targeted transmission study is focused on the seam between Nebraska and Iowa, and Kansas and Missouri. | *MISO-SPP*

The RTOs hope to find more comprehensive, cost-effective and efficient upgrades than would otherwise be identified in the current interconnection queue process, where upgrades are identified in time sequence by one or the other RTO.

“We see the system in that specific area as getting saturated,” SPP’s Juliano Freitas said during a Dec. 11 teleconference with stakeholders from both RTOs. “We see a lot of problems in our studies related to congestion, voltage and terminal problems. More and more we see the costs going up when we try to interconnect new generation.

“We want solutions where both sides can see the benefits and agree to build,” he said. “We want solutions out of this study that can provide multiple values and eliminate the friction we sometimes have in these processes.”

That suits many stakeholders just fine.

“It’s an understatement to say we’re excited about this,” Omaha Public Power District’s Dan Lenihan said. “We’ve had persistent operational issues on the east area of the Nebraska-Iowa seam. You’d see four or five issues consistently on this seam consistently and persistently showing up as congestion issues. The seam’s planning models haven’t been able to accurately capture those, but this is maybe another avenue to tackle this.”

Clean Grid Alliance’s Natalie McIntire, a ubiquitous presence during MISO transmission discussions, said the joint study is “important work for both regions to do together.”

“We feel the way MISO and SPP has framed this study, to look at all the drivers, is a great way to look at this,” she said. “We’re really hoping that in considering the benefit analysis, you’re not just looking at the economic analysis, but the benefit to reliability and customers.”

Reducing Friction

By trying to resolve congestion issues in just one region, the RTOs’ staff is hopeful of identifying opportunities to eliminate “unnecessary friction” between processes and affected parties in the study and on an ongoing basis. The goal is to find solutions that provide multiple values capable of meeting both the needs of interconnection customers and providing benefits to load in both SPP and MISO.

The RTOs have conducted four coordinated system planning studies since 2014, but have been unable to agree on any projects, generally because of cost-allocation issues.

“We’re approaching this as a way to inform future planning efforts,” said SPP Vice President of Engineering Antoine Lucas. “We’re starting a little bit smaller. We’ll have some takeaways from this that we’ll be able to apply to other processes in the future, either along the seam or in our respective regions.”

“At the end of the day, if all we get out of this is couple of projects, it would be a success,” said Aubrey Johnson, MISO’s executive director of system planning and competitive transmission. “This shouldn’t be a one-time thing. We’ve got more problems out there, not just one area. We will see what we can learn and, in consultation with our stakeholders, improve our processes.”

Lucas and Johnson both said cost allocations will not be a part of this study.

“We want the focus to be on transmission needs without the distraction of what the cost allocation might be at some later point. If we’re able to do that, we can develop some solutions that generate value for y’all,” Lucas said, addressing those listening to the call.

“The main thing is, let’s see where the planning takes us,” Johnson said. “[Benefits] have to be other things than adjusted production costs. [They have] to be things we’ve consistently agreed upon in both RTOs … and bring them in for discussions with stakeholders.”

The RTOs’ engineering staffs will begin working on transmission solutions that enable generator interconnections, then vet those solutions with the stakeholder community, Johnson said. They will use separate 5- and 10-year models under the same principal and process, deploying economic metrics in the benefits analysis.

Executive Agreement

In aligning their interconnection processes, the RTOs hope to reduce or eliminate costly restudies, creating more certainty for transmission customers. Mitigation projects will be tested in a reliability study and “ideally-suited” projects will be sent to economic studies staff for cost-benefit analysis. Projects that don’t pass the cost-benefit test will be re-evaluated or replaced in the reliability study.

Staff promised stakeholders will be frequently updated on the process and be given a chance to provide input. A draft report will be developed in October.

Both RTOs’ CEOs made it clear they stand behind the study by opening the meeting with mutual statements of support.

“We’re committed to making progress,” SPP CEO Barbara Sugg said. “There’s so much opportunity here to leverage the MISO-SPP seam and benefit customers on both sides. We’re encouraging innovation and flexibility to address some of the problems and challenges we’ve seen in the past. We need to think about things differently and not be constrained by history.”

MISO CEO John Bear momentarily dropped off the call when it came time for him to speak.

“We’re trying to find John,” Johnson said.

“I’m frantically trying to find him,” SPP’s Clint Savoy said.

With order restored and Bear properly unmuted, he thanked Sugg for her leadership and for quickly reaching out to him when she was named SPP’s CEO earlier this year. Bear said he discussed the study with his board of directors during MISO’s Board Week.

“We’re committed to improving the work as it is conducted on the seams,” he said. “We know the work on the seams can be critical as we manage electricity in an affordable and efficient manner.”

December 15, 2020

Overheard at Mid-Atlantic Renewable Energy Conference

Infocast’s three-day virtual Mid-Atlantic Renewable Energy Summit featured discussions on state clean energy procurements, the development of offshore wind (OSW), energy efficiency and the decarbonization of the transportation and generation sectors. Recent debates in PJM and FERC were also at the forefront of panel discussions.

Here are some highlights of discussions we heard.

D.C.’s Decarbonization Plan

Tommy Wells, director of the District of Columbia Department of Energy & Environment gave a presentation on the city’s efforts to comply with the D.C. Public Service Commission’s January order calling for 50% renewable resources by 2032 and carbon neutrality by 2050.

Clean energy advocates have warned the order didn’t adequately create a path to achieve the goals, while city officials said the groundwork is there to carry out a successful plan.

Mid-Atlantic Renewable Energy — Tommy Wells, D.C. Dept. of Energy & Environment | *Infocast*

Wells said comprehensive energy plans typically quantify how much energy is being used, where the energy comes from and how much capacity is necessary to retain reliability of the grid.

Wells said D.C.’s plan, Clean Energy DC, is different because it starts with the goals and leaves the path to reach the goals up to interpretation. He said quantifying the goals remains the challenge.

“For a lot of us, the future is somewhat uncertain,” Wells said. “But there are some basic things we do know. We know we’ve made the commitment to do it. We know that there are new technologies that are adding renewable energy. The comprehensive energy plan is the roadmap, and along that roadmap there’s going to be some new routes and changes along the way.”

Wells said the milestones along the way include cutting energy usage in the city by 50% and using 100% renewable electricity by 2032.

D.C. officials are working in partnership with the city’s distribution utility, Potomac Electric Power Co. (Pepco), to add new technologies like battery storage to modernize the grid and give it the flexibility to incorporate intermittent generation, he said.

Although the grid was one of the greatest engineering feats of the 20th century, Wells said, it needs updating. “Now we need the grid for the 21st century. And the 21st century grid is going to have to do a lot more and be a lot smarter,” he said.

D.C. is looking to wind power to help achieve its renewable goals. Wells said D.C. government facilities get a third of their power from a wind farm in Pennsylvania.

It signed a 20-year agreement with the wind farm, Wells said, which helped pay for the capital costs of construction. He said the deal was a way to use D.C.’s position as a large consumer to put additional renewable resources on the grid.

Wells said one of D.C.’s mandates is to generate 10% of its power needs from solar power contained within the city limits. He said the mandate will be very difficult and expensive to achieve, but it was a requirement laid down by city officials.

Because the city is largely developed and has expensive real estate, Wells said D.C. has had to incentivize the construction of solar projects. He said whenever an electricity purchase is made in the city, there is a “carve out” for a portion of that electricity that is required to be generated from solar. If the carve out can’t be met, the generator must provide an alternative compliance payment to D.C. as a penalty.

Wells said one of the biggest disadvantages against D.C. achieving its renewable goals right now is that electricity is inexpensive throughout the Mid-Atlantic region.

“When power is cheap, it is difficult to get people to really pay attention to the things we want them to do, which is use less power and use more renewables,” Wells said. “But we’re going to get there.”

Delaware’s Renewable Future

Thomas Noyes, principal planner for utility policy at the Delaware Division of Climate, Coastal and Energy, gave a presentation on the First State’s energy landscape.

The state’s Climate Action Plan, which is set to be finalized by early 2021, is expected to propose reducing greenhouse gas emissions through renewables, energy efficiency and electrifying the transportation and building sectors. Gov. John Carney earlier this year proposed updating the state’s renewable portfolio standard (RPS) to 40% by 2035.

Noyes said Delaware’s energy landscape is shaped by its geography of being located on a peninsula, with most of the power flowing north to south and the heaviest concentration of industrial and residential customers located in the northern section of the state.

Delaware does not generate all the electricity it uses, Noyes said, leading to a large portion of its energy imported from out of state. Noyes said most of the power generated in state comes from natural gas plants.

“It’s not an exaggeration to say most of the energy we use is imported through power lines and pipelines,” Noyes said.

The Renewable Energy Portfolio Standards Act, the state law passed in 2005, set Delaware’s RPS at 25% renewables with 3.5% of the renewables coming from solar by 2025. Noyes said the current resource mix stands at 20% renewables and 2.25% from solar.

Noyes said Delmarva Power, which provides power to a large portion of the state, meets its RPS requirements through long- and medium-term contracts and the spot market. Noyes said long-term contracts of at least 20 years are a key part of the state’s strategy of reaching the renewable goals by allowing solar projects of all scales to compete for the right to sell SRECs through 20-year contracts.

Long-term contracts help promote investment in the small- and medium-size solar projects by making it more appealing to investors who know they will have a sure 20-year revenue stream, Noyes said.

“These contracts help us reduce the boom-and-bust cycles that we’ve seen in some other states,” he said. “In a short period, a state may see several large projects built that crowd out the market for small- and medium-size solar installations. We’ve worked very hard to avoid that.”

Most of Delaware’s renewable energy credits (RECs) come from out-of-state wind generation, Noyes said, while most of the solar renewable energy credits (SRECs) come from inside the state. Delaware has more than 6,000 solar PV installations, mostly distributed rooftop sources. Its 130 MW of solar capacity has grown 15-fold in the last decade, he added.

The next big step for renewable energy in Delaware is offshore wind, Noyes said. Gov. Carney formed a working group in 2017 to study opportunities for the development of OSW off the state’s coast. Noyes said Delaware must take into account the transmission of OSW projects slated for development off the Maryland coast, with lines expected to bring power ashore at the Indian River Substation. (See Md. PSC Oks 368 MW in Offshore Wind Projects.)

Noyes said Delaware officials are engaged in discussions with FERC and PJM on how the grid is going to handle the transmission impacts. He said with more connection points along East Coast shorelines, other states are going to have to make adjustments to how they do grid planning because most transmission infrastructure is not found along the coastlines.

As more power comes ashore from OSW, it could partly reverse the geography of the grid in Delaware with electricity primarily flowing from the south to the north, Noyes said.

“If we have more power coming ashore in southern Delaware, we’re going to have to see what we have to do to make adjustments to the grid,” he said.

Maryland Renewables

Maryland officials discussed their efforts to comply with the 2019 Clean Energy Jobs Act (SB 516), which raised the state’s RPS to 50% by 2030, from 25% by 2020. Gov. Larry Hogan’s proposed Clean and Renewable Energy Standard (CARES) would require 100% renewables by 2040.

Ben Grumbles, secretary of the Maryland Department of the Environment, said Hogan created the Governor’s Task Force on Renewable Energy Development and Siting by executive order in 2019 because “good ideas” weren’t making their way through the general assembly, and there was an immediate need to find ways bring stakeholders together.

The task force looked for ways to reduce unacceptable tradeoffs of having to choose between the environment and the economy, Grumbles said, and officials helped to streamline permitting and come up with innovative ideas for promoting renewable resources.

Maryland is one of 30 states with a renewable portfolio standard to increase electricity production from renewable sources. The state currently requires that 50% of electricity sold by utilities come from renewable sources by 2030, including 14.5% from solar as mandated by the Clean Energy Jobs Act.

Grumbles cited an October report, released by Chesapeake Conservancy’s Conservation Innovation Center (CIC), which lays out large-scale opportunities for solar placement on degraded land and underutilized industrial sites; the rooftops of commercial, industrial and residential buildings; and parking lots. (See Report: Urban Land Use Key for Md. Solar Goals.)

The task force estimated that meeting the state’s RPS will require between 7,000 and 35,000 acres of land across the state, Grumbles said. Solar siting is just one of the strategies Maryland is using to ensure that it meets its GHG reduction goals through a push for “homegrown” renewable energy.

“This relentless march towards clean and renewable energy to meet our very ambitious environmental and climate goals is a priority,” Grumbles said. “The need is even greater to couple those ambitious environmental goals with common sense solutions and partnerships for innovation and real collaboration.”

Mary Beth Tung, director of the Maryland Energy Administration, was asked about her agency’s efforts to spur battery storage development.

Tung said battery storage is an interesting subject on the policy side and through its practical attributes and is becoming a more significant part of the grid. Aside from their obvious uses, she said batteries can be used in transmission and stabilizing power supplies in substations.

Maryland has been developing its Solar Canopy Grant Program for installing solar PV over parking lots with electric vehicle charging stations, Tung said, and some of those projects include battery storage.

Tung said her agency is currently working with the state Public Service Commission to determine what storage regulations should be developed to promote their use in the state.

“Storage is one way we’ll be able to even out the renewable curve,” she said. “Renewable resources are intermittent for the most part, and it is a way to get over that hurdle.”

December 15, 2020

Pa. Eyes EE, Renewables for RGGI Funding

Pennsylvania is considering spending some of its carbon credit proceeds on energy efficiency and renewable energy development, a state official told Infocast’s Mid-Atlantic Renewable Energy Summit last week.

The state Department of Environmental Protection (DEP) estimates that carbon credit auctions under the Regional Greenhouse Gas Initiative (RGGI) will yield annual revenues of between $179 million and $320 million through 2030 once Pennsylvania joins the 10-state compact. (Virginia will become the 11th state to join in January.)

Pennsylvania RGGI — Allen Landis, Pennsylvania DEP | *Infocast*

Allen Landis, executive director of DEP’s Pennsylvania Energy Development Authority, said state officials intend to spend RGGI auction funds on eliminating air pollution because they are relying on the state Air Pollution Control Act as the legal basis for joining the compact.

He said the state expects energy efficiency to be a “major piece” in the spending plans, adding that efficiency would provide “tremendous dividends” for grid reliability, energy rates and job creation.

Renewable energy development in the state is also likely to receive funding, Landis said, because increasing Pennsylvania’s renewable capacity is essential to meeting Gov. Tom Wolf’s goal of a 26% reduction in statewide greenhouse gas emissions by 2025 while ensuring its electricity sector stays competitive in the long term. (See Pennsylvania Joins US Climate Alliance.)

Wolf, a Democrat, has been battling with the Republican majority legislature over the state’s entrance into RGGI since he signed an executive order in 2019 directing DEP to draft a rulemaking for joining the compact. (See Pennsylvania Governor Signs RGGI Executive Order.)

In September, the General Assembly passed a bill barring the state from joining RGGI or taking any action to control carbon dioxide emissions without legislative approval, but Wolf vetoed it. (See Pa. House Passes Bill Limiting RGGI Entry.)

Landis said the “greenhouse gas abatement” piece of the proposed RGGI regulations include programs ranging from electric vehicle charging stations to curtailing leaking emissions at abandoned oil and gas wells.

Clockwise from top left: Kathleen Robertson, Exelon; Flora Cardoni, PennEnvironment; Allen Landis, Pennsylvania DEP; and Pennsylvania Rep. Chris Rabb (D). | *Infocast*

“The first and most important thing for us right now is to put the process out there, get input, draft out the plan and let people weigh in on it and make sure their voice is heard so everyone can contribute as to how those funds are spent,” Landis said in response to a question from moderator Flora Cardoni, field director at PennEnvironment.

The state Environmental Quality Board is accepting comments until Jan. 14 on the proposed regulations, which were published last month. Comments may be submitted through the eComment system. The board also held a series of virtual public hearings on the regulations.

Protecting Communities

State Rep. Chris Rabb (D) told the conference that regulators and the legislature needs to have a “laser focus on the hot spots” of environmental damage in Pennsylvania and use RGGI funds to correct “egregious” negative impacts on the environment in vulnerable communities. There is not much precedent for doing the type of work laid out in RGGI, he said, which makes it difficult for politicians and regulators to find the right mix for the program to succeed.

Rabb said politicians focus too much effort on “symptom chasing,” especially when they deal with environmental issues: They’re willing to address the symptoms of problems but don’t have the courage to go to the heart of systemic issues that create the problems.

RGGI is not the “universal solution” for all the environmental problems in Pennsylvania, Rabb said, but its goals are a step in the right direction. He said it is important right now for regulators to make sure the direction of the program is “sound” while addressing the needs of communities that will be impacted by the new regulations.

The state has to look at creating opportunities for “regenerative effects” by creating new green jobs and entrepreneurial opportunities for fossil fuel industry workers whose livelihoods are at risk, he said.

“These are frontline communities that we have to take care of,” Rabb said during the Dec. 8 session, which also featured discussion on how the state can further its renewable policies by increasing the goals in the 2004 Alternative Energy Portfolio Standards law. “This is about how we can transition them into a new reality where there are business opportunities and other community-centered efforts that will help make us whole.”

Industry Perspective

Kathleen Robertson, director of strategic initiatives and environmental policy at Exelon, said she appreciated the idea of job training being included in possible uses for RGGI funds. She said she believes an argument can be made that job training can be linked to improving air quality by focusing on careers like oil and gas well abatement, weatherization of buildings and the installation of energy efficiency projects. Weatherization provides opportunities for local workers because the jobs cannot be outsourced to cheaper foreign labor, she said.

Community support will be important as some of the existing generation plants transition or close, Robertson said, pointing to the shuttering of Three Mile Island nuclear plant in central Pennsylvania in 2019. (See Exelon to Close Three Mile Island.) She said the closure of generation plants can be devastating to communities’ tax revenues and employment base.

“Given the amount of money RGGI can raise, I think one of the really good opportunity areas is transitioning both the workers and the communities into the clean energy economy and making sure everyone has a leg up in that,” Robertson said.

Legislative Action

Cardoni asked Rabb how likely Pennsylvania’s legislature is to approve RGGI given the Republican resistance. (See GOP Continues Opposition to Pa. RGGI Plans.)

Rabb said Republican legislators will fight RGGI “tooth and nail” because they don’t want to lose fossil fuel jobs or the industry’s campaign contributions. The lack of limits on campaign donations in Pennsylvania makes it even more difficult to get controversial legislation passed, he said.

The oil and gas industry in Pennsylvania has more lobbyists than there are state legislators, Rabb said, which is an enormous number considering the state has the largest full-time legislative body in the country, with 253 members in the General Assembly. Rabb said the money in campaigns goes beyond partisan politics and is a problem of both Republicans and Democrats.

“The largest industries with the deepest pockets win,” Rabb said. “They win in a very cynical way. They win by influencing incumbents and candidates by cutting very big checks.”

December 15, 2020

ERCOT Board of Directors Briefs: Dec. 8, 2020

ERCOT’s Board of Directors last week approved a package of nearly three dozen revision requests that included the final work of two task forces developing policies and principles for energy storage resources (ESRs) and the real-time co-optimization (RTC) of energy and ancillary services.

Board Chair Craven Crowell called the work a “major milestone” in the development of ERCOT’s Passport Program, which is designed to allow emerging technologies to expand their participation in the market. Staff and stakeholders will spend the next four years aligning the task forces’ work with an upgrade of the Texas grid operator’s energy management system that also incorporates distribution generation resources (DGRs) into its systems.

“That’s a huge win for us, but work still needs to be done to button up some of the details,” chair of ERCOT’s RTC task force Matt Mereness said.

That work will begin in February during the board’s next meeting, when staff will begin updates on Passport’s schedule and status. ERCOT said it will have one of the world’s most sophisticated market designs when the program is completed in 2024.

ERCOT Board of Directors — The Passport Program’s timeline. | *ERCOT*

“I look at what was done there as world class,” said Engie’s Bob Helton, who chairs the Technical Advisory Committee that oversaw the task forces. “I would really like to see other RTOs follow the same process.”

Staff and stakeholders have drafted more than 700 pages of new and/or revised protocols and market rules for ESRs, DGRs and RTC. Now that they are approved, they will be used to draft business requirements for implementation.

ERCOT CEO Bill Magness said Passport represents “the most major changes in our system we’ve seen in a number of years.” The program, which staff expect to cost as much as $55 billion, will touch nearly every single ISO system, as well as those stakeholders use to communicate with ERCOT.

“We are in a good position to start taking on the work in 2021,” Magness said, noting much of what has been accomplished was done with staff and stakeholders working remotely from their homes.

“This is unprecedented how well this has gone,” Public Utility Commission Chair DeAnn Walker said.

The PUC directed ERCOT to add RTC to its market in 2018. The market tool will award ancillary services every five minutes during the operating day, allowing the market to adjust to changing grid conditions. The commission recently opened a rulemaking to implement RTC in the market (51588).

Crowell, Walsh, Pfirrmann Honored

In a virtual sendoff, staff and stakeholders honored Crowell, his vice chair, Judy Walsh, and Karl Pfirrmann for their nine years of service together on the board.

The three unaffiliated directors joined the board in 2012 for the first of three three-year terms. Crowell and Walsh have held their leadership positions ever since; ERCOT bylaws require the chair and vice chair be unaffiliated directors. Pfirrmann chaired the Human Resources and Governance Committee.

“Well, I guess this day had to come,” Magness said in kicking off the honors. “In 2020, we talk about how we miss people, how we miss being in person. Some days, it’s just good to be in sweatpants and not drive anywhere. This really would be a good day to have handshakes and hugs available, to really send our friends off, but words are going to need to do today.”

Staff presented a video with words of praise for Crowell, Walsh and Pfirrmann from the PUC’s three regulators, previous PUC Chairs Donna Nelson and Pat Wood, and fellow directors. In his comments, Commissioner Arthur D’Andrea made the three honorary Texans for life “through the power invested in me” by the state’s Public Utility Regulatory Act. They will all receive state flags flown over the Capitol in recognition of their service and honorary resolutions from the Texas Senate Committee of Business and Commerce.

“I’ve looked at PURA before and I’m not sure [D’Andrea’s power] is in there, but Arthur knows the law, and I trust him,” Magness said.

“I will miss working with Judy and Karl. I’ve always felt a special bond with the two of them,” Crowell said. He thanked Nelson for encouraging him to apply for an ERCOT board position while he was still on the Texas Reliability Entity’s board and ERCOT staff for being some of brightest people in the industry.

Walsh recalled her time on the PUC with Wood, when they helped deregulate the Texas electric industry and usher in “the best wholesale and retail market anywhere.”

“Who would have believed two little ol’ regulators could or would do a thing like that,” Walsh said.

Pfirrmann, who is celebrating 50 years in the industry this month, harkened back to a time when televisions were black and white and Saturday mornings were reserved for “Sky King,” Roy Rogers and Dale Evans.

“Google their names to figure it out,” he said, before referencing Rogers and Evans signature song, “Happy Trails to y’all.”

Members approved in a voice vote former Consolidated Edison CEO Craig Ivey’s nomination to the board’s last remaining open unaffiliated director’s slot. His name has been sent to the PUC for final approval. (See “Con Ed CEO Nominated to Board,” ERCOT Board of Directors Briefs: Oct. 13, 2020.)

“This usually takes a lot longer when we sit down to eat,” Magness said.

The commission in November approved the elections of Michigan Public Service Commissioner Sally Talberg, retired Texas PUC Approves ERCOT Board Members.)

The board and its committees will nominate and elect their chairs and vice chairs during their February meetings.

Record Solar Generation Installed

Magness said ERCOT integrated a record 2,849 MW of utility-scale solar projects over the last 12 months, along with 4,777 MW of wind capacity, despite the COVID-19 pandemic. The ISO also saw 14 days of more than 20 GW of wind energy on the system. It currently has more than 25 GW of installed wind capacity and 3.8 GW of installed solar capacity after having shed more than 5.6 GW of coal generation since 2014.

“There are a lot of changes in the resource mix,” Magness said during his CEO update.

ERCOT is on track to finish the year $28.5 million over budget, driven primarily by shortfalls in the administrative fee ($10.6 million) and interest expense ($15.7 million). The ISO’s expenditures are projected to be $2.6 million over budget.

“The [weather] forecast was about right. It was the [pandemic’s] economic forecast that brought [the administrative fee] down a little bit,” Magness said.

Directors Approve Opposed NPRRs

Helton celebrated the end of three years as TAC’s chair by bringing forward a pair of revision requests that he said were among the “most divisive” he has seen.

“So I’m going out on a high point,” he joked.

Both nodal protocol revision requests (NPRRs) received opposing votes during recent TAC meetings on their way to comfortable endorsements.

The board passed NPRR1055 by an 11-4 margin in a roll call vote, raising similar concerns as did TAC members over staff’s decision to sponsor the measure on behalf of non-opt-in entities (NOIEs). (See “REPs, NOIEs Debate Revision Change,” ERCOT Technical Advisory Committee Briefs: Nov. 18, 2020.)

Two unaffiliated directors and members representing the independent retail electric provider and independent power marketer segments voted against the change.

“This should have been sponsored by the NOIE community because this is an exception for them,” DC Energy’s Seth Cochran said.

The revision gives ERCOT the discretion to accept for good cause NOIEs’ late submissions that they own or control their generation resources serving as a source resource node, or that the resource has a contractual commitment for capacity and/or energy with the NOIE. The attestation allows the ISO to certify congestion-hedging instruments granted to NOIEs.

The change also requires ERCOT to post a market notice by Sept. 1 of each year, reminding NOIEs of the annual deadline.

“We were approached by some of the NOIEs who missed this deadline. … There were issues around timing being coincident with when people were moving to remote work,” Magness said. “We needed to ask the market to approve [NPRR1055] because we don’t have it in the protocols. We don’t think it harms our ability to get the work done in this very limited situation.”

The board approved NPRR945 with only one dissenting vote from Brazos Electric Power Cooperative’s Clifton Karnei. Representing the cooperative market, Karnie sided with fellow sector members that opposed the measure at TAC, saying it could shift transmission costs to entities that cannot shift their load. (See ERCOT Technical Advisory Committee Briefs: Oct. 28, 2020.)

The NPRR removes the “associated load” term that some proponents say has been interpreted in some instances to restrict net-metered private-service arrangements to the same entity that owns the load and generation. The revision requires that entities be behind the same interconnection point.

Board Confirms 2021 TAC Reps

The board confirmed the 2021 TAC representatives, which includes three new members along with 2021’s holdovers: Avangrid Renewables’ Thresa Allen in the independent generator segment; EDF Trading North America’s Kevin Bunch in the independent power marketers segment; and CenterPoint Energy’s Eric Easton in the investor-owned utilities segment.

TAC will choose its leadership when it meets again in January.

The directors also signed off on a pair of measures endorsed last month by TAC: ramp-rate restrictions for the Southern Cross DC tie to clarify ERCOT will curtail schedules when necessary to conform with the system’s ramp capability, and staff’s recommendation to change the methodologies used to compute non-spinning reserve and regulation reserve service in response to incoming solar generation’s additional variability and uncertainty. (See “New Interconnection Process for Sub-10-MW Generator,” ERCOT Technical Advisory Committee Briefs: Nov. 18, 2020.)

In other actions, the board:

approved an adjunct membership for Solar Prime. A corporate member when 2020 began, the solar developer lost its status upon the sale of generation assets but expects to meet membership criteria early next year.
accepted Schellman & Co.’s 2020 system and organization control audit with no testing exceptions.
agreed with the Human Resource and Governance Committee’s recommendation to approve the 2021 ERCOT key performance indicators.

Consent Agenda Includes 32 Changes

The directors unanimously approved a consent agenda comprised of 20 NPRRs, a change to the Commercial Operations Market Guide (COPMGRR), three revisions to the Nodal Operating Guide (NOGRRs), an Other Binding Document (OBDRR) modification, four revisions to the Planning Guide (PGRRs), one system change request (SCR) and single changes to the Resource Registration Guide (RRGRR) and Verifiable Cost Manual (VCMRR):

NPRR1001: clarifies that ERCOT will issue an “emergency notice” when it is operating in an “emergency condition,” but issuing an “operating condition notice,” “advisory” or “watch” does not mean that ERCOT is operating in an “emergency condition.”
NPRR1007: updates the ERCOT system’s management activities in the protocols to address changes associated with RTC’s implementation.
NPRR1008: updates day-ahead operations in the protocols to address changes associated with RTC’s implementation.
NPRR1009: updates transmission security analysis and reliability unit commitment to address changes associated with RTC’s implementation.
NPRR1010: updates the adjustment period and real-time operations in the protocols to address changes associated with RTC’s implementation.
NPRR1011: updates performance monitoring in the protocols to address changes associated with RTC’s implementation.
NPRR1012: updates settlement and billing in the protocols to address changes associated with RTC’s implementation.
NPRR1013: updates the protected information provisions, definitions and acronyms, market participants’ registration and qualification, and market suspension and restart in the protocols to address changes associated with RTC’s implementation.
NPRR1014: enables ESRs’ integration into the ERCOT core systems as a single-model resource, replacing the existing “combination model” paradigm where ESRs are treated as two resources — a generation resource and a controllable-load resource. This NPRR will be implemented simultaneously with other RTC-related changes and with the upgrade to the ERCOT EMS in 2024.
NPRR1026: establishes rules for and enables self-limiting facilities’ integration into the ERCOT markets and core systems.
NPRR1028: requires qualified scheduling entities to notify ERCOT of physical limitations on their resources’ starting ability that are not modeled in the reliability unit commitment software and excuses compliance with parts of RUC dispatch instructions that violate a notified resource’s physical limitations. The NPRR also establishes a requirement that ERCOT extend a RUC commitment to honor a resource’s minimum run-time limitation when a physical limitation delays its ability to reach its low sustained limit.
NPRR1029: enables DC-coupled resources’ (defined as an ESR type required to follow all rules associated with ESRs in addition to meeting this change’s requirement) integration into ERCOT’s core systems. The NPRR applies to both the current combo model era and the future single model era.
NPRR1031: requires ERCOT to post operations messages informing market participants when load is curtailed because of a transmission problem.
NPRR1032: limits the DC tie schedules used in RUC optimization and settlements to the ties’ physical rating.
NPRR1039: removes the defined term “market information system public area” from the protocols and replaces it with “ERCOT website.”
NPRR1041: adjusts the expiration of the protected information status of wholesale storage load data from 180 days to 60 days, aligning the disclosure of real power consumption and metered generation output to 60 days after each operating day.
NPRR1042: adjusts the planned capacity in the Capacity, Demand and Reserves report to remove previously mothballed or retired generation resources that may be repowered but do not have an owner that intends to operate them.
NPRR1043: clarifies that ESRs’ withdrawn charging load (excluding auxiliary load) will be settled based on the nodal price similar to its injections, even if the ESR does not seek or cannot qualify for wholesale storage load (WSL) treatment by replacing the term “ESR load that is not WSL” with the defined term, “non-WSL ESR charging load.” The latter load will be priced at nodal but, unlike ESRs receiving WSL treatment, will be subject to applicable load ratio share-based charges.
NPRR1046: removes additional uses of “dynamically scheduled resource” to align with NPRR1000.
NPRR1047: consolidates gray-box language related to NPRR973 and NPRR1016.
COPMGRR048: removes the defined term “market information system public area” in the protocols and replaces it with “ERCOT website” and removes references to the “ERCOT market information list.”
NOGRR207: clarifies that ERCOT’s issuance of an “operating condition notice,” “advisory” or “watch” does not mean that ERCOT is operating in an emergency condition.
NOGRR211: updates language related to supplemental ancillary service markets, ancillary service deployment and ancillary service responsibilities and obligations to address changes associated with RTC’s implementation.
NOGRR217: removes the defined term “market information system public area” in the protocols and replaces it with “ERCOT website.”
OBDRR020: updates the methodology for setting maximum shadow prices for network and power balance constraints to address changes associated with RTC’s implementation.
PGRR081: describes how self-limiting facilities will be evaluated in the generation resource interconnection or change request process.
PGRR082: extends the interconnection process to distribution-connected resources and settlement-only generators (SOGs) and clarifies the roles of ERCOT and transmission and/or distribution service providers.
PGRR083: requires a Regional Planning Group (RPG) project number for projects submitted for RPG review and removes the specification of transmission project information tracking information from the Planning Guide.
PGRR084: removes the defined term “market information system public area” in the protocols and replaces it with “ERCOT website.”
RRGRR023: establishes provisions and requirements in the guide for ESRs that are identical to those already in place for generation resources and SOGs.
SCR812: creates an Intermittent Renewable Generation Integration report similar to wind and solar power production integration reports.
VCMRR030: removes the defined term “market information system public area” in the protocols and replaces it with “ERCOT website.”

December 15, 2020

Industry Eager for New Leadership on Tx, Climate

Panelists during last week’s fourth annual gridCONNEXT conference expressed tepid hope that the incoming Biden administration will be able to advance some of the policies they say are needed to integrate the surge of renewables coming online and address climate change.

Tepid because, as many noted, regardless of the results of the Jan. 5 special elections in Georgia that will decide which party controls the Senate, Congress will remain bitterly divided for at least the next two years. Many speakers listed off the issues that the two parties can come to some agreement on, such as energy efficiency, research and development funding, and enhancing grid cybersecurity.

But as they did so, there were notable hints of doubt, or even fatigue, in their voices.

“Can we reconfigure the grid in a way that allows us to take advantage of these [renewable] resources … and take advantage of this changing energy landscape?” posited Tracy Warren, director of the American Council on Renewable Energy’s Macro Grid Initiative, which seeks to expand transmission nationwide, on Dec. 8, the first day of the online conference. (See ‘Macro Grid’ Seeks to Connect Grid’s Regions.)

“I think it is a serious question [of] ‘can we do this?’” she continued. “As many of you know, we’ve been talking about infrastructure for a long time. ‘Infrastructure Week in Washington’ is a punchline to unfunny jokes. Look at what’s happening now: Congress is having difficulty passing a COVID relief bill in the middle of a pandemic.”

renewables transmission — Stitching together the power system’s major regions would allow the U.S. to fully harness its renewable resources, ACORE and other groups argue, citing NREL’s Interconnections Seams Study. | *NREL*

The need for more transmission pervaded nearly every discussion during the conference, regardless of whether it was a panel topic. But past failures of ambitious, interstate transmission providers, such as Clean Line Energy Partners, also frequently came up.

“I was looking over some notes from a transmission conference I spoke at about 12 years ago, and unfortunately the three points haven’t changed,” Jonathan Weisgall, vice president for legislative and regulatory affairs at Berkshire Hathaway Energy, said Wednesday. “I once joked [that] we better hire eighth-graders for our transmission department so they can actually see projects finished before they retire.”

“We need some direction; we need some leadership at the federal level,” said Jay Caspary, vice president at Grid Strategies. “I don’t think the existing planning processes, at least at the regional level, are looking out far enough and reflecting what we expect to happen [in] 20, 30, 40 years. They’re more short-term and looking at the reliability problems in the next few years.”

But even that approach, Caspary noted, failed this year during a record heat wave in the Western U.S. that led to rolling blackouts in California. One of the main problems that led to them was the state’s lack of import capability. “There was 12,000 MW of wind in the [Great Plains] that couldn’t get there,” Caspary said. “We need to think differently.”

Weisgall, Caspary and others called for FERC to revisit Order 1000 after President-elect Joe Biden takes office and names a new chairman. They also expressed hope that it would continue to direct the integration of new technologies into RTO markets, similar to Orders 841 and 2222.

“We’ve got to improve the business case for more transmission investment,” Weisgall said. “We’ve got to do that at FERC, in Congress and in the states.” He also called for Congress to designate an agency — either FERC or the Department of Energy — as a single point of contact for transmission planning.

Weisgall noted that Berkshire’s Iowa-based MidAmerican Energy joined MISO, and NV Energy and PacifiCorp the Western Energy Imbalance Market (EIM), without any legislative or regulatory mandates. But despite the EIM’s success, and the expected benefits of its upcoming extended day-ahead market, a full-fledged RTO would provide even more, such as more efficient dispatch of renewables, he said. “Nobody disagrees with that. Nobody disagrees with the goal of trying to minimize the number of seams and maximizing markets. We really do need a full regional market to do that.”

The main problem? “Cali-phobia.”

Weisgall shared the panel with CAISO Board of Governors Chair Angelina Galiteva and NYISO CEO Richard Dewey. He noted that while both represented the U.S.’ two ISOs, NYISO is unlike CAISO in that the latter was formed by California law with a board appointed by the state’s governor. “You’re not going to get to a West-wide RTO if the California governor appoints that board,” requiring a change to state law or even the Federal Power Act, he said. “It’s going to be incredibly difficult” given the political diversity in the West and dysfunction in Washington.

‘Dysfunctional and Unfixable’

Government dysfunction was the main topic of a keynote address on the last day of the conference by John Hofmeister, CEO of Citizens for Affordable Energy and former president of Shell Oil. He took the pessimism about Congress at the conference to the next level.

“The governance of energy [in the U.S.] is broken and dysfunctional and unfixable in its current form,” Hofmeister said. “Twenty years into the 21st century, and we are still stumbling along as a society” in addressing climate change. “Nine presidents, from Richard Nixon to Donald Trump, have failed to fix this problem.”

Hofmeister’s message was less about the urgency of the problem than its magnitude and the inherent inability of the U.S. government to solve it. Two-year election cycles lead Congress to focus only on short-term problems, while the multitude of federal agencies and congressional committees responsible for energy policy each have their own priorities, making it impossible for the government to be “on the same page” about global problems, he argued.

The one system “that sustains us through thick and thin, regardless of election cycle,” has been the Federal Reserve, whose Board of Governors comprises seven members nominated by the president and confirmed by the Senate for staggered 14-year terms. He called for a similar body dedicated to setting policy on climate change, but he acknowledged it was unlikely.

“From my standpoint, I’m less optimistic than I was 10 years ago … that we can [solve climate change] rationally and pragmatically.”

December 15, 2020

Invenergy Renewing Push for Grain Belt Express

Invenergy Vice President for Regulatory Affairs Nicole Luckey last week provided an update on her company’s efforts to win approval of the Grain Belt Express, which the company acquired this year after Clean Line Energy Partners abandoned it in the face of regulatory, legal and political hurdles.

Invenergy is making a revitalized push for the approximately 800-mile HVDC transmission line that would carry 4,000 MW of wind energy from western Kansas through Missouri and Illinois to the Indiana border, Luckey told the Missouri Energy Initiative’s Midwest Energy Policy Series on energy infrastructure and economic development.

She said that because wind and solar resources “require quite a bit of land … we have to build transmission lines to access them.”

The main political obstacle has been the potential use of eminent domain, which has stoked landowner opposition in Missouri. State courts have upheld regulators’ approval of the project and its subsequent sale to Invenergy, though the state legislature introduced a bill this year to block the project’s use of eminent domain.

“The existing infrastructure in these areas, because they’re sparsely populated, just isn’t there, so think of it like building an interstate highway system,” Luckey said. Projects like Grain Belt are needed “to decarbonize our electricity system along the timeline that many investors and customers are pushing their utilities to follow.

“This is not an either-or proposition,” she said.

According to a market analysis done by PA Consulting Group for Invenergy, the $2.3 billion project will enable up to $7 billion in electricity cost savings for the SPP and MISO regions of Kansas and Missouri between 2024 and 2045. The average residential customer would save $50/year, which accounts for the full cost to build the project.

PA’s analysis also found that Grain Belt would lower wholesale power prices in the states’ RTO regions. Around-the-clock power prices in western Kansas would be 38% lower in SPP and 45% lower than prices in Missouri’s MISO region from 2024 to 2039 on an average annual basis during off-peak hours. These pre-project price differences translate to average annual price spreads of $16.81/MWh for Kansas and Missouri’s SPP areas and $22.21/MWh for Missouri’s MISO section.

“It’s no secret that the best wind resource in the United States is located in western Kansas,” Luckey said. “Actually, western Kansas also has a really excellent solar resource, and getting access to the best resource means that you end up significantly lowering the cost of the energy that is produced by your wind or solar project.”

Invenergy Grain Belt Express — Invenergy says the Grain Belt Express will unlock the strong wind and solar energy resources in western Kansas. | *Invenergy*

Missouri Rep. Travis Fitzwater (R) mentioned Grain Belt during a legislative panel and said “getting renewable energy across the state would be fascinating” but that the previous Clean Line project iteration was only going to deliver “a small percentage of the power” to the state.

The Invenergy iteration would deliver 2,500 MW of wind energy to Kansas and Missouri from the line’s 4,000-MW capacity. Previously, 500 MW of the transmission line’s capacity was slated for delivery to Missouri. With increased delivery to Missouri, including an expanded DC-to-AC converter station, Grain Belt would make as much as half or more of its total capacity available to Missouri.

“DC lines are just more efficient at moving large amounts of power long distances. You have fewer line losses than you do with AC lines, which again helps to ensure that you’re delivering energy at the lowest cost,” Luckey said. “There are definitely operational and reliability benefits associated with DC lines, which use a narrower right of way and fewer conductors than comparable AC lines, making more efficient use of transmission corridors and minimizing visual and land-use impacts that I know is a priority to landowners, local county officials and to elected officials in those areas.”

The project, which would stretch across 200 miles in Missouri, reached an agreement with the state’s Joint Municipal Electric Utility Commission to serve 39 cities. Luckey added that Missouri retail customers are expected to save $12.8 million annually on their electricity costs.

“We obviously cannot force our project on anyone. Incumbent utilities are the folks we’re talking to about taking service on the project, but they have to carefully weigh their options; [for example,] does it make more sense for their ratepayers or for reliability for them to have locally sourced projects versus taking power off Grain Belt?” Luckey said. She said Invenergy is engaged in Missouri utilities’ integrated resources planning processes that they go through and “talking to them about how we think the project could fit into their plans for decarbonization.”

Grain Belt has gained regulatory approval in Kansas and Indiana, but Illinois’ previous approval was overturned by the courts. Invenergy will seek approvals for expanded delivery to Kansas and Missouri and begin the first phase of project construction before Illinois regulatory approval, which Luckey said the company will pursue next year.

“Engineering design and environmental field studies are ongoing so that we can hopefully begin site work in mid-2022 and bring the project online by the end of 2024,” Luckey said.

December 15, 2020

Hydrogen for FCEVs Gets Big Boost in California

The California Energy Commission allocated up to $116 million on Wednesday to install fueling stations for hydrogen-powered fuel cell electric vehicles with the goal of having 200 stations supporting 230,000 vehicles in the next decade.

The grants to three companies — Iwatani Corp. of America, FirstElement Fuel and Equilon Enterprises — could bring the total to 179 stations in the coming years, the CEC said.

Building hydrogen fueling infrastructure will help solve the “chicken-and-egg problem” of increasing the number hydrogen-powered vehicles, Commissioner Patty Monahan said. Hydrogen-powered cars from makers such as Toyota have been slow to arrive, but that is partly due to a lack of fueling infrastructure.

“What we’re seeing in California right now is, ‘Well, here’s your chicken, where’s the egg?’” Monahan said. “We want to see more fuel cell vehicles on the road.”

“We’ve got the infrastructure,” she said. “Now … show us the vehicles.”

Even with the new funding, hydrogen fueling stations and fuel cell electric vehicles likely will continue to make up only a small part of the state’s bid to get rid of polluting cars and trucks. California already has hundreds of thousands of plug-in electric vehicles and thousands of high-speed chargers available.

The state is aiming to have 5 million EVs on the road by 2030, requiring hundreds of thousands additional chargers in workplaces and public spaces such as shopping centers. (See California Needs Huge Number of EV Chargers.)

hydrogen fuel cell vehicles — | *Toyota USA*

The CEC said, however, that the hydrogen stations will help meet Gov. Gavin Newsom’s order that all new passenger vehicles sold in the state must be zero-emissions vehicles by 2035.

Currently 45 hydrogen stations exist, mainly in Southern California, and 16 more are in development, the agency said. The grants will help build 111 new stations, bringing the total to 172. Seven more stations are under development using only private funds.

The $116 million, to be distributed in batches as the grantees meet specific milestones, will be paired with $131 million in private matching funds.

The new stations will also serve medium- and heavy-duty vehicles, potentially a big advance in reducing emissions, Monahan said.

Hydrogen fuel cell vehicles, which use oxygen and hydrogen to create electricity, have the advantage of being able to be fueled quickly on the road, much like gasoline-powered vehicles. But the expense of making hydrogen, which requires large amounts of electricity, and the difficulty of obtaining the rare and pricey vehicles, has thwarted widespread adoption.

Monahan said that could change if nations, including China and members of the European Union, support a “global scale-up.”

“We need a global transition to fuel cell electric vehicles to really be able to drive down costs and build up scale,” she said. “We’re trying to show in California how to do it.”

December 15, 2020

California Lithium Extraction Plan Advances

A proposal to extract lithium for battery production from geothermal wells in California moved forward Wednesday when the state’s Energy Commission named most of the members of a new blue-ribbon panel to address the plan.

Energy commissioners said the idea of having a “Lithium Valley” in far Southern California could promote the state’s goals of adopting utility-scale battery storage and electric vehicles while reversing the fortunes of the imperiled Salton Sea and its surrounding communities.

Created by a state statute earlier this year, the Blue Ribbon Commission on Lithium Extraction in California, commonly called the Lithium Valley Commission, is intended to foster that plan.

“I am really excited about this,” CEC Commissioner Karen Douglas said. “We have a real opportunity to put Lithium Valley … on the map in a way that also supports local economic development and is the most environmentally positive way of getting bulk amounts of lithium … that I know of.”

Most lithium for lithium-ion batteries comes from South America, Australia and China. Hard-rock mining, which pollutes water, and evaporation ponds, which are depleting the scarce supply of water in Chile’s Atacama Desert, are the main methods of obtaining lithium today.

The Salton Sea, a vast lake created accidentally in 1905 by a levee breach, is drying up and becoming more saline. Rotting fish carcasses line its shores. Dust storms blow toxins from a century of agricultural runoff. Imperial County, which encompasses the proposed area of lithium development, is among the state’s poorest regions.

California Lithium Extraction — The Salton Sea is drying up, but some see a potential windfall in lithium extraction for batteries. | *University of California*

Geothermal energy is abundant, however, and the existing generating stations and surrounding areas are potential sources of lithium. Geothermal brine — subterranean waters awash in minerals and naturally heated to 500 degrees Fahrenheit — contain huge amounts of lithium. The problem is extracting it in bulk at competitive prices.

“It’s not alchemy,” said Jonathan Weisgall, a new blue-ribbon panel member and vice president of legislative and regulatory affairs at Berkshire Hathaway Energy, which hopes to be a major player in the field. “The lithium is there. We’ve recovered it in the laboratory. The question is, can it be done in a commercial way? That’s what this commission needs to promote to get California on the global map for lithium production.”

Efforts to extract lithium have sputtered and died before, but a bill enacted this year, AB 1657, established the Lithium Valley Commission to explore the possibilities and report to the state by October 2022. The 14-person commission — nine of whom are CEC-appointed members — consists of representatives from lithium extraction firms, EV makers, local tribes, utilities and environmental groups. Five other members are appointed by the California Public Utilities Commission, the governor, lawmakers and the secretary of the state’s Natural Resources Agency.

“The Lithium Valley Commission is charged with reviewing, investigating and analyzing certain issues and potential incentives regarding lithium extraction and use in California, and to consult, when feasible, with the United States Environmental Protection Agency and the United States Department of Energy in performing these tasks,” the CEC said in its background memorandum.

Gov. Gavin Newsom’s order for all new cars sold in California to be zero-emission vehicles by 2035 is expected to give the EV market a huge boost, while the state’s mandate to rely on 100% clean energy by 2045 will require thousands of megawatts of batteries to store solar and wind energy for later use.

The CEC devoted $14 million earlier this year to lithium extraction innovation projects, Chair David Hochschild noted.

The new commission “dovetails beautifully with what’s happening in the energy storage and electric vehicle markets,” Hochschild said. “We are going to see a tenfold increase in the amount of energy storage coming online in California in the next year and electric vehicles, of course. Everyone is seeing what’s going on. … There’s just incredible momentum, and so demand for lithium is going to grow at a healthy clip.”

December 15, 2020

SPP Stakeholders Dig into WEIS Market Study

SPP last week offered stakeholders a deep dive into a Brattle Group analysis of the RTO’s Western regional market that projects $49 million in annual savings for current and new members.

According to the study, utilities participating as full RTO members in SPP’s Western Energy Imbalance Service (WEIS) market, scheduled to launch in February, would receive $25 million a year in adjusted production cost (APC) savings and revenue from off-system sales. Members in the RTO’s Eastern Interconnection footprint will benefit from $24 million in savings because of the market’s expansion, transmission network and generation fleet.

Brattle said SPP’s expanded RTO footprint will allow market participants to sell power into Arizona, New Mexico, Utah and elsewhere in the Western Interconnection while only paying a single wheeling fee, “which creates opportunity for increased market sales.”

SPP WEIS — SPP’s expanded RTO footprint | *SPP*

The study analyzed the benefits of WEIS market utilities and the SPP RTO interacting across the DC ties in two future scenarios: an expanded RTO and the WEIS market. It looked far enough in the future to assume recently announced renewable energy projects would be energized, staff said during the Dec. 9 call.

The expanded RTO study integrated WEIS utilities into SPP RTO over the DC ties, with a unified Tariff for the entire footprint and optimized day-ahead and real-time DC ties. Brattle found extending SPP RTO to the WEIS footprint would reduce APC by $33 million/year and generate over $16 million/year of additional wheeling revenues. WEIS members would experience an APC reduction of $8.5 million/year and receive the $16 million/year of additional wheeling revenues; current SPP members would receive an APC reduction of $24.2 million/year.

An increase in market sales, mostly sold off-system to neighboring entities in the WECC, would account for much of the APC reduction, the consulting firm said.

Under the WEIS scenario, Brattle staff allowed coordinated real-time trading over the four DC ties in the WEIS footprint. Increased flows of low-cost power from SPP into the WEIS footprint would reduce APC by $16.1 million/year in the combined footprint; $9 million/year would accrue to WEIS members and $7.1 million/year to current SPP members.

The cheaper power would allow WEIS members to reduce production from higher-cost resources. SPP members would benefit from making more sales across the DC ties, and WEIS members would be able to substitute high-cost production for lower-cost purchases from SPP.

Basin Electric Power Cooperative, Deseret Power Electric Cooperative, the Municipal Energy Agency of Nebraska, Tri-State Generation and Transmission Association, the Western Area Power Administration and the Wyoming Municipal Power Agency (WMPA) will participate in the WEIS contract. With the exception of the WMPA, the utilities have said they are interested in placing their Western Interconnection facilities under the terms and conditions of SPP’s Tariff and becoming RTO members. (See Western Utilities Eye RTO Membership in SPP.)

Also last week, WEIS market participants briefly discussed a list of service flow constraints (SFCs) that raised concerns with SPP’s Market Monitoring Unit.

Staff told the Western Market Working Group (WMWG) during its meeting Dec. 10 that a list of SFCs, to be posted online, will only include the constraint’s name, its rating limit and the shadow price. The data will be a direct output from the economic dispatch engine.

The Western Market Executive Committee remanded a revision request back to the WMWG when the MMU said it would be difficult to post “on-the-fly” SFCs in real time. (See “WMEC Approves 6 WRRs,” SPP WEIS Stakeholders OK Final Test.)

December 15, 2020

NEPOOL Markets Committee Briefs: Dec. 8, 2020

ISO-NE’s summer wholesale market costs totaled $1.48 billion, a 15% decrease from a year earlier because of lower energy and capacity costs, according to the quarterly markets report released by the RTO’s Internal Market Monitor.

Average day-ahead and real-time Hub LMPs were $22.50 and $22.52/MWh, respectively, coinciding with lower natural gas prices. The average natural gas price was $1.62/MMBtu (or $12.64/MWh assuming a 7,800 Btu/kWh heat rate), 25% lower than the summer 2019 price of $2.17/MMBtu (or $16.93/MWh).

Capacity market costs decreased by 19% to $603 million, down by $143 million from last summer. The first quarter of the FCA 11 capacity commitment period saw clearing prices of $5.30/kW-month for Rest-of-System, compared to the higher FCA 10 price of $7.03/kW-month.

NEPOOL Markets Committee — ISO-NE’s summer wholesale market costs decreased from the previous summer because of lower energy and capacity costs. | *ISO-NE*

Gross real-time reserve payments totaled $4.4 million, a 67% increase from the same period a year ago, driven by redispatch to maintain reserves during tight system conditions. That led to larger 10-minute non-spinning reserve and 30-minute operating reserve payments, which respectively rose by $847,000 and $437,000. The average non-zero spinning reserve price decreased relative to summer 2019 from $9.81 to $6.96/MWh. The frequency of non-zero spinning reserve prices increased to 506 hours from 365 hours.

Total regulation payments were up 11% to $6.4 million compared to the previous summer with the increase reflecting higher regulation capacity requirements, along with an increase in service-offer costs. Net commitment period compensation (NCPC) costs totaled $7 million, up by 4% over last summer, but still represented less than 1% of the total energy costs, consistent with the historical range.

Economic payments made up 81% ($5.6 million) of the total, a 46% increase from 2019 steered by real-time commitments made because of generator trips and load forecast error. Local reliability payments fell by 60% to $900,000, with most occurring in the day-ahead market and going to generators in Maine and northeastern Massachusetts to support planned transmission outages.

DNE Wind Generator Must Offer Compliance

As a special topic, the IMM also reviewed day-ahead offers and clearing of wind generators affected by the June 2019 must-offer requirements for do-not-exceed (DNE) dispatchable capacity market resources. ISO-NE now requires DNE dispatchable generators with capacity supply obligations to offer the full hourly amount of expected real-time generation into the day-ahead market.

A rise in day-ahead offers from DNE resources has translated to increased clearing for those generators, leading to the “small impact” of virtual supply clearing at wind generator nodes as virtual offers have historically filled the gap left by under-clearing wind generators in the day-ahead market.

Overall, wind generation offer behavior is consistent with Tariff requirements, the Monitor found. DNE wind generators increased the quantity of energy offered in the day-ahead market and offers reasonably reflected the expected level of peak real-time production but overestimate potential output in off-peak hours.

Since June 2019, cleared offers have averaged 70% of real-time production compared with 41% previously. Cleared virtual supply at wind nodes has decreased from 25% to 18% of real-time wind production, the Monitor said.

Order 2222 Compliance Discussion Begins

In September, FERC issued a long-awaited order requiring RTOs and ISOs to open their markets to distributed energy resource aggregations. (See FERC Open RTO Markets to DER Aggregation.) ISO-NE has now started the discussion on compliance with Order 2222.

The RTO’s Henry Yoshimura presented the 11 key compliance directives outlined in the order and the process schedule that concludes with a FERC filing on July 19, 2021.

The first order of business is collecting perspectives and feedback from stakeholders by Dec. 22, which ISO-NE will review and discuss early next year with interested entities directly affected by compliance requirements. The RTO will then develop a high-level proposed approach vetted through the NEPOOL process, including drafting and discussing Tariff changes and conceptual amendments and concluding with votes in various committees starting in June.

MC Actions

The committee voted to adopt changes to the NEPOOL Generation Information System (GIS) and GIS Operating Rules related to improvements to third-party meter reader uploads and reflect the addition of “Clean Existing Generation” to the Massachusetts Clean Energy Standard.

At its October meeting, the MC agreed to direct the GIS Operating Rules Working Group to consider changes requested by the Massachusetts Department of Environmental Protection, which revised its regulations to include a requirement that retail load-serving entities subject to the standard have a certain percentage of energy from “clean existing generation units.” (See “GIS Working Group to Consider Massachusetts ‘Clean Generation’ Changes” in NEPOOL Markets Committee Briefs: Oct. 6-8, 2020.)

The committee also re-elected Vice Chair Bill Fowler, president of Sigma Consultants, to continue his role in 2021.