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June 28, 2020January 15, 2025

NY Climate Action Council Looks at Deep Decarbonization

New York’s Climate Action Council met Wednesday to lay the groundwork for a scoping plan to help the state achieve its nation-leading clean energy goals despite the massive disruptions caused by the COVID-19 pandemic.

CAC Co-chair Alicia Barton, NYSERDA | New York DPS

“Early on, even as we were in the midst of the economic shutdown that we knew was going to be a challenge for our industry, the state was ready to lead on clean energy,” said CAC Co-chair Alicia Barton, serving her last week as New York State Energy Research and Development Authority chair before returning to private industry in Massachusetts.

Barton noted that the last time the CAC met on March 3, its 22 members talked “about the opportunities New York has to lead the nation and lead the world with the promise of the Climate Leadership and Community Protection Act [CLCPA], with the ambition of that law.”

“Since that time, the pandemic crisis has overtaken and changed so many things, but we still have the opportunity to lead,” Barton said. “We’re in the process of revising the models for an economic recovery that puts clean energy back in the center.”

The CAC’s work is part of a broad effort by regulators, state agencies and NYISO to transition the state’s power sector and entire economy away from fossil fuels and toward renewable energy, with NYSERDA and the Public Service Commission on June 18 having released a white paper on the state’s Clean Energy Standard and how to achieve it.

The CLCPA mandates, among other targets, that 70% of the state’s electricity come from renewable resources by 2030 and that generation be 100% carbon-free by 2040. (See Cuomo Sets New York’s Green Goals for 2020.)

Specific Pathways

The CLCPA also requires the state’s Department of Environmental Conservation to undertake a rulemaking to establish statewide emission limits for 2030 and 2050, and to work with NYSERDA to establish a value of carbon as an evaluation tool for agency decision-making, said DEC Commissioner and CAC Co-chair Basil Seggos, who heads the council’s advisory panel.

“We’re basically setting up the goalposts for the council’s planning,” Seggos said. “We anticipate holding a stakeholder conference in July, and to roll out a public comment position in August.”

Tory Clark, a director at Energy and Environmental Economics (E3), presented a report commissioned by the state on pathways to deep decarbonization, envisioning four main pillars that all require immediate action:

Energy efficiency, conservation and end-use electrification.
Switching to low-carbon fuels.
Decarbonizing the electricity supply.
Negative emissions measures and carbon-capture technologies.

“The most impactful [emission-reduction] measures that we’ve included are methane mitigation and climate-friendly refrigerants,” Clark said. “I’ll note that this is an area in particular where we think there is more room to refine our analysis, both in the detail that we have that reflected the existing emissions, and the measures and policies that can help bend that curve down.”

Anne Reynolds, executive director of the Alliance for Clean Energy New York, noted that the study said the grid will need firm, dispatchable capacity such as bioenergy or hydropower and “wondered whether you assumed that dispatchable capacity, and if so, how much. And if you had that, you’d need less renewables.”

New York net greenhouse gas emissions for selected years by scenario | E3

Upstate and downstate, the study projects 9.5 GW of storage installed by 2050, nearly 25 GW of offshore and onshore wind, and nearly 46 GW of solar.

“The firm, dispatchable capacity is the broad, umbrella term, and probably a mix of technologies will step in and serve that role,” Clark said.

Tory Clark, E3 | New York DPS

“We now model batteries able to store energy for four, maybe eight, hours, but longer-duration storage has not been demonstrated at scale,” Clark said. “But there are many companies working on it, so I would put that in the innovation bucket, where hopefully there’s continued innovation and that would be able to step in and be part of the solution.” The study models today’s technology, but the mix could include using existing generators to combust bioenergy or hydrogen, hydroelectric power, nuclear, carbon capture and storage — all proven technologies that are included in the analysis, she said.

“Since we’re really just talking about these small winter periods [peaks] throughout the year, we have bioenergy capacity [nearly 17 GW in 2050] … just sitting around, but they only run a very small share of the year, just to serve that need,” Clark said. “So, it’s a niche role that in addition to the big players, the wind and solar that are generating throughout the year and providing the majority of the electricity generation for New York, we have this small role for firm dispatchable capacity.”

EVs, Biofuels and Data

Peter Iwanowicz, Environmental Advocates of New York | *New York DPS*

Peter Iwanowicz, executive director of Environmental Advocates of New York, asked whether the study saw electric vehicles playing a role in utility-scale storage.

The study concluded “that EVs have a pretty huge potential to shift load when they charge for up to 12 hours over the course of the day, based on driving patterns and grid technology, so that does play a similar role to some of our battery storage,” Clark said.

National Fuel Gas Distribution President Donna DeCarolis | New York DPS

“I was really pleased to see the inclusion of and discussion around RNG [renewable natural gas] and things like hydrogen blending,” said Donna DeCarolis, president of National Fuel Gas Distribution. “How do we see that being studied as the work of this council progresses?”

IPPNY CEO Gavin Donohue | New York DPS

“The issue of science matters,” said Gavin Donohue, CEO of the Independent Power Producers of New York. “This study is a true, objective study and one that is needed to achieve these herculean goals. Having a kitchen-sink approach to the new technologies is very important. What comes out of the stack is what’s important, not what goes into the stack, from an environmental compliance standpoint.”

On mitigating the growth of emissions, Department of Transportation Commissioner Marie Therese Dominguez highlighted that “New York uses the least energy per capita for transportation purposes than any other state in the nation,” mainly because of the subway system in New York City and the annual $6 billion investment in mass transit statewide.

PSC Chair John B. Rhodes | New York DPS

“The department has also committed more than $1 billion in infrastructure improvements over the last several years to reduce single-vehicle occupancy use and to increase the movement of goods by means other than truck, including strategic investments in seaports and freight rail,” Dominguez said.

PSC Chair John B. Rhodes noted the initiatives to unlock transmission “that are called for by the Accelerated Renewables Growth and Community Benefit Act” enacted in April.

“We’re making progress where it needs to be made and are counting on the council and the [advisory] panel to shape the overall direction,” he said.

June 28, 2020

New Yorkers Plug New Tx Need for Clean Future

Renewable energy experts and grid planners joined government officials Thursday to discuss how to address New York’s outdated transmission system, which can’t move enough clean energy from upstate generation sources to key load centers in and around New York City.

New York transmission — Anne Reynolds, ACE NY | *ACE NY*

“New York will be bringing more and more renewable energy online,” said Alliance for Clean Energy New York (ACE NY) Executive Director Anne Reynolds, who opened the meeting. “This is good news — wind and solar are pollution-free, and 22,000 New Yorkers already work in the renewable electricity industry. But for New York to actually achieve its renewable electricity goals, we need to update the grid, parts of which were built more than half a century ago.”

An estimated 226 people listened in on the virtual town hall co-hosted by the American Council on Renewable Energy and the Solar Energy Industries Association.

ACE NY lobbied the State Legislature for a budget bill that passed in April, the Accelerated Renewables Growth and Community Benefit Act, which aligns state law, bureaucratic practices and policies — including property tax laws — with the clean energy goals outlined in last July’s landmark Climate Leadership and Community Protection Act (CLCPA) (A8429). (See NY Renewable Supporters Push for New Siting Agency.)

The bill directed the Public Service Commission to authorize a study, which it did in May, to identify distribution upgrades, local transmission upgrades and bulk transmission investments needed to meet the state’s clean energy goals (20-E-0197). (See NYPSC Launches Grid Study, Extends Solar Funding.)

“I agree with the premise that we are going to need more transmission if we’re going to meet the goals of the CLCPA, the most aggressive set of climate standards in the entire nation,” said Sen. Kevin Parker, chair of the Senate Energy and Telecommunications Committee.

“Now the hard work has begun, which is how do we actually meet the goals. I very much believe that transmission is going to be really critical in that, and organizations like ACE NY are going to be leading the charge,” Parker said. “This also is happening in a time at which … our economy has been way slowed down, and if we look at where we’re going to produce full-time jobs at a living wage with benefits, the clean energy economy is the next best place to do that.”

However, reduced state revenues stemming from the slowdown means “we have to produce more green using less green,” Parker said.

Additional Buildout

Two things are at the heart of the new climate law, said Ali Zaidi, Gov. Andrew Cuomo’s deputy secretary for energy and environment: “One is dramatic transformation of the grid to 100% clean, and the second is an expansion of that grid to reach more and more sectors of the economy.”

One of the state’s most powerful tools in decarbonizing buildings, industry and transportation is to back out existing sources of energy in those sectors and replace them with electrons generated in a clean way, Zaidi said.

“We have hundreds of miles of power lines that are on their way to being built in this state in the very near term, and we need to bird-dog that progress and make sure it is done on time,” Zaidi said. “It’s critical that we build what we already know we need and what is barely far along in the development process … and use data and analysis to inform where we are going to speed up additional buildout.”

As part of its “Grid in Transition” initiative, ‘Astonishing’ Buildout Needed for Clean NY Grid.)

“Most people know that the interconnection points that can efficiently accommodate large renewable generation projects in upstate New York are becoming much harder to find,” said Bart Franey, director of transmission planning, asset management, systems and data for National Grid.

The constraints are partly because of generation and transmission development being largely siloed from each other, he said.

“New flow patterns across the networks are creating a growing issue of curtailments on renewable energy, and generation development continues to outpace that of transmission,” Franey said. “The result is a suboptimal solution for ratepayers.”

National Grid has been exploring this issue for two years and looking for ways to upgrade what are referred to as “byways” in its transmission network, he said.

National Grid Simmons Station site in Humphrey, Cattaraugus County, N.Y., an example of a “byway” in the company’s transmission network | *National Grid*

The company “has focused on creating upgrades that are available to deliver renewable resources to the bulk, or the highways,” Franey said. “These studies assumed light load conditions with an objective of minimizing curtailments, and it resulted in some really exciting opportunities around optimally sizing upgrades using a [renewable energy credit]-based benefit approach.”

When National Grid analyzed its systems and identified projects, they realized that “in some cases, the least-cost byways solution would in fact be a greenfield project, used specifically to deliver renewables,” Franey said. “We refer to them as collector stations, but they would really be a form of integrated resource planning.”

Developer and Local Insights

“In New York alone, we have a pipeline of over 3 GW of solar and storage in various stages of development and have partnered with Shell Energy for the development of offshore wind, and we have a number of solar projects already online,” said Rodica Donaldson, senior director for commercial transmission and analytics at EDF Renewables North America.

“The transmission risk is important to renewables because if we have high curtailment, which has been identified in the latest [Congestion Assessment and Resource Integration Study] by the New York ISO, that means high risk for us because we cannot be delivered as low-cost energy for loads,” Donaldson said.

The high risk of congestion and curtailment also means that the transmission system is reaching capacity, she said.

“We have curtailment; we have depressed LMPs within that pocket; and those are financial costs for us,” Donaldson said. “As a generator, when we look at developing projects, this risk can challenge the ability to secure financing and even can make the project uneconomic. So, for us, a scenario without transmission investment is a high-risk environment.”

Ryan Piche, Lewis County, N.Y. | *ACE NY*

“We are home to 27,000 residents over 1,200 square miles, so when you talk about room for green energy growth, this is where it is: It’s upstate,” said Ryan Piche, manager of Lewis County in the Adirondacks. “No offense to Sen. Parker, but it’s not in Brooklyn.”

Despite having open space, the needs of the local community in Lewis County and elsewhere are very important, he said.

“We know our community better than anyone, and we need to be the ones who are deciding which areas are prime for growth and which areas need to be preserved,” Piche said. “We’re the ones who understand viewshed and habitats. The ‘solar tsunami’ is a fun little phrase, but think about a tsunami — it can overwhelm you. I think it is important that the local governments draw a line in the sand and understand what is going to be acceptable and what is not.”

June 28, 2020

Study Foresees MISO Solar Eclipsing Wind

MISO’s southern and central regions could surpass the RTO’s wind-heavy northern reaches as the biggest producer of renewable energy as solar generation grows in popularity, new study results indicate.

The findings come out of MISO’s ongoing Renewable Integration Impact Assessment (RIIA), which most recently focused on where new resources could be located when renewables rise to 50% of the RTO’s resource mix. It found distributed and utility-scale solar installations would proliferate in Michigan and Indiana and the footprint’s southern states, while the wind buildout that has so far dominated the North planning region winds down.

“Some of the heavy wind that we were seeing in Minnesota, North Dakota and even Iowa, we’re starting to see a shift,” James Okullo, MISO policy studies engineer, told stakeholders during a teleconference Friday.

The RIIA results are based on trends in MISO’s interconnection queue and load ratios in local resource zones. The Southern Alliance for Clean Energy recently predicted the U.S. Southeast could contain 25 GW of solar capacity by 2023.

MISO solar — Possible resource additions at 50% renewables | *MISO*

Okullo said MISO has generally found that grid needs rise sharply beyond a 30% renewable penetration. Previous results of RIIA have concluded that to operate with a 50% renewables mix, MISO must boost reserve requirements and demand-side management, dramatically increase transmission (including HVDC) and add more technology to lines, including synchronous condensers and transformers. (See MISO Renewable Study Shows More Tx, Tech Needed.)

MISO has been undertaking the study since 2017, which used actual peak load levels at the time and a 2022 power flow model to draw conclusions. The RTO has not yet modeled strategic energy storage additions in addition to the growing renewable share, and Okullo said it would have new RIIA results by August projecting how much energy storage might be needed to help ease the transition.

For now, MISO’s study projects an increasing risk to serving load outside of summer as solar generation gains momentum. A large solar fleet staves off the usual early evening daily peak as the sun still shines, compressing risk to a shorter and steeper time period later in the evening, the RTO said.

The Union of Concerned Scientists’ Sam Gomberg last month said that MISO might be biasing the presentation of RIIA results in terms of what the system could not do rather than what it could. After the RTO presented its last RIIA results last November, many stakeholders walked away with the view it couldn’t possibly operate with more than 40% renewable penetration because of complexity, he said.

“I would encourage you to think hard about the takeaways you communicate and the message you deliver,” Gomberg told staff during a Planning Advisory Committee teleconference May 13.

June 28, 2020

MISO Unveils 1st Proposal to Consolidate Tx Planning

MISO last week floated a proposal that would require network upgrades needed by projects in the generator interconnection queue to reach certain voltage and price levels before they could be tested for the economic benefits needed for cost-sharing eligibility.

But renewable proponents argue the plan wouldn’t do much for developers facing costly upgrades.

MISO transmission planning — Neil Shah, MISO | © *RTO Insider*

The proposal is a starting point for MISO’s effort to coordinate and align studies found in network upgrade planning in the interconnection queue and the RTO’s annual Transmission Expansion Plan (MTEP), Senior Manager of Economic Planning Neil Shah told stakeholders during a Planning Advisory Committee teleconference Wednesday. (See Regulators Not Sold on MISO Tx Planning Sync.)

Under the proposal, a generation project’s needed upgrade would need a minimum rating of 230 kV and cost at least $5 million to be eligible for evaluation as a possible market efficiency project (MEP), the same thresholds set out for MEPs in MISO’s proposed cost allocation plan, currently awaiting Local Projects Axed from MISO Cost Allocation Refile.)

MISO is additionally proposing that costs for a network upgrade submitted for economic evaluation can be spread across a group of interconnecting generation projects as long as they are $50,000/MW or higher. However, the projects necessitating the upgrade would need to have already completed the queue and executed a generator interconnection agreement (GIA) before they could be evaluated.

Shah said a GIA execution would help MISO avoid running economic analyses on projects that haven’t completed all interconnection studies.

“The benefit of this process is that it allows MISO and stakeholders an opportunity to compile and list all [generator interconnection] projects for economic evaluation rather that doing it on an ad hoc basis as interconnection projects come in,” Shah said.

He said MISO is aware that the RTO’s Environmental and Other Stakeholder Groups sector is critical of the proposal, arguing that it wouldn’t give interconnection customers certainty on future cost-sharing as they make their way through the definitive planning phase (DPP) of the queue.

Too Late

Sustainable FERC Project attorney Lauren Azar said the economic evaluation would still come too late for “bona fide” developers saddled with large network upgrades that could show regional economic benefits for others.

“This proposal is not going to solve the problem of generators being scared away by large increases, because by the time a generator interconnection agreement is signed, those customers would have already been scared away by large network upgrade costs,” Azar said. “I don’t think this scratches the itch of the problem we have before us.”

“We’re not going to wait until we have signed GIAs in order to get an economic evaluation. … This really doesn’t solve the problems. If folks get to a signed GIA, it’s likely that they can afford those upgrades,” Clean Grid Alliance’s Natalie McIntire argued.

But Shah said he didn’t think an economic evaluation earlier in the DPP would be feasible. Even if MISO were to figure out the timing issue, it likely wouldn’t make a substantial dent in project withdrawals because affected-system studies with neighboring grid operators — which come later in the interconnection process — also reveal high upgrade costs, he said.

Trust Queue Price Signals?

Stakeholders asked how interconnection customers could gain insight into whether their network upgrades could be economically beneficial.

Shah said it would depend on the customers’ access to tools and modeling — or by hiring of consultants, if they do not have tools to perform their own economic analysis.

“The interconnection queue is working as designed. We’ve got too many interconnection projects interconnecting at places where there isn’t enough transmission. It’s sending that signal to either reinforce the grid or go somewhere with less congestion,” WEC Energy Group’s Chris Plante argued.

Indiana Utility Regulatory Commission staffer Dave Johnston agreed, saying requests for proposals or power purchase agreements could benefit from inclusion of grid upgrade costs.

“We need a big transmission overlay if a lot of people in the footprint wanted to procure resources of those areas,” and that’s not happening, Johnston argued.

Azar said that while price signals are appropriate, network upgrades have never been evaluated for economic benefits, even though project developers are being told to build “backbone” transmission projects.

Apex Clean Energy’s Richard Seide said the 2017 MISO West network upgrade costs were so egregious that nearly all were canceled, even those projects with PPAs approved by state commissions. Of the 27 generation projects that entered the February 2017 MISO West queue cycle, all but two dropped out, hindered by expensive but necessary transmission upgrades to accommodate the projects that cost tens to hundreds of millions of dollars per project.

More to Come

Shah stressed that the proposal for making interconnection project network upgrades eligible for economic evaluation was just the first step that MISO is considering to align transmission planning processes. He asked stakeholders to consider whether its next step should be changing its annual MTEP model building timeline in order to get more data from the interconnection queue.

Shah added that MISO’s goal is to align the two processes and not disturb them — or the FERC-approved Tariff language that governs them — as much as possible.

“I hope that we don’t make perfect the enemy of the good,” McIntire said, arguing that generator interconnection planning doesn’t need to perfectly conform to the timeline of a year and pointing out that even MTEP studies begin prior to the plan’s approval year. “We don’t need to get too hung up on making this 365 days.”

June 28, 2020

NEI Emphasizes Cooperation with Renewables

Nuclear Energy Institute CEO Maria Korsnick is always upbeat and optimistic about the future of nuclear energy when she makes her annual State of the Industry address, emphasizing plants’ emissions-free nature, high capacity factors and reliability.

Korsnick’s address this year, conducted online as it has been for the last two years, was no different. (See NEI CEO: FirstEnergy Emergency Request a ‘Bridging Strategy’.) But after the usual quick, bright and positive speech and soft question-and-answer with NEI spokeswoman Monica Trauzzi, NEI on Wednesday hosted a panel discussion featuring Union of Concerned Scientists President Ken Kimmell and Renewable Energy Buyers Alliance (REBA) CEO Miranda Ballentine. Both expressed general support for nuclear’s role in a future, zero-carbon generation mix, though both couched it with contingencies.

NEI renewables — NEI CEO Maria Korsnick | *NEI*

In her opening speech, Korsnick positioned nuclear not as a competitor with renewables but as a partner. Though she noted that nuclear provides more than half of all carbon-free generation in the U.S. (as she did last year), “I want to be absolutely clear: We need to develop every source of carbon-free energy that we can. The world is counting on carbon-free resources to complement one another, not just compete. Our choice isn’t between nuclear power or wind and solar. It’s between a status quo of rising emissions from fossil fuels or a low-carbon future from all available sources, including nuclear.”

As evidenced by its name, REBA members — consisting of large corporations such as Facebook, Google and Walmart — have focused their procurement targets on renewable resources, particularly utility-scale wind and solar. But Ballentine said that “there has been a fairly significant transformation in the mindset of large clean-energy buyers, actually quite recently I would say … from goals of 100% renewable energy, to now companies thinking about 24/7/365 zero-carbon power, where renewable energy is one means to that end.”

REBA members “are beginning to think about other forms of zero-carbon power” besides large wind and solar projects, Ballentine continued. She listed geothermal, landfill gas and hydropower, “which is the one that tends to get left out of the discussions so frequently.”

But she said nuclear presents unique concerns for the organization: “What do we do with the waste, how do we handle proliferation, and how do we handle safety? … To the extent that new nuclear [technology] addresses some of those three core challenges of the existing fleet … I think you’re going to start seeing large consumers of power being more interested in the potential role that new nuclear can play.”

Kimmell emphasized “the herculean challenge” of not only using 100% clean energy but electrifying transportation and building heating. “This is a gigantic challenge that implies a pace of expansion of our electric grid in a way that we’ve never come close to doing in history,” he said.

Ballentine agreed. “I would say that many of the members in REBA … have a sense of urgency around the timeline that even 2050 for the power system is too late because there are so many other parts of our economy that are much harder to decarbonize.”

“To meet a challenge like” avoiding permanent climate change, Kimmell said, “all of us need to be prepared to abandon a tribalistic attachment to particular solutions.”

ClearPath Executive Director Rich Powell, who moderated the panel, echoed those sentiments. “I think that lesson of stopping being against the things we’re not specifically for — and eventually becoming for the things we’re not specifically for — is … just a crucial mental frame to adjust [to] as we respond to a challenge this enormous.” ClearPath, formed in 2014, seeks to “develop and advance conservative policies that accelerate clean energy innovation.”

Kimmell warned, however, that UCS’ support for nuclear power was conditioned on maintaining the Nuclear Regulatory Commission’s strict safety regulations for plants. “And I should say this is an area where it’s hard for us to work cooperatively because we don’t support efforts to relax those standards, and to the extent that those standards do get relaxed, we’re going to need to reconsider that criteria” of support, he said.

He also said any financial support through legislation should be reserved for plants that “meet or exceed the NRC’s highest safety standards.” He pointed to UCS’ 2018 report that recommended policies such as a national carbon tax or clean energy standard that would prevent existing nuclear plants from retiring earlier than their expected useful life.

June 28, 2020

ERCOT Technical Advisory Committee Briefs: June 24, 2020

ERCOT’s Technical Advisory Committee last week held its first full working meeting — albeit virtually — since the COVID-19 outbreak, endorsing a raft of revision requests, reviewing the committee’s strategic goals, and receiving updates from the Real-Time Co-Optimization Task Force (RTCTF).

The committee last conducted a full meeting in January. It has held several information sessions since, taking email votes on changes to the grid operator’s protocols and a $219 million transmission project. (See “Corpus Christi Tx Project Gets OK,” ERCOT Technical Advisory Committee Briefs: May 27, 2020.)

Speaking during a webinar the day after the TAC’s meeting Wednesday, ERCOT CEO Bill Magness said staff’s “experimentation” with conducting webinars resulted in a meeting “where the TAC was really able to do everything.” (See related story, Companies Debate When to Bring Back Staff.)

“Yesterday showed us we can do things on a remote basis,” he said. “[Stakeholder] meetings are still happening and still going on. We’re working through a lot of complexities with real-time co-optimization, but those folks aren’t missing a beat so far, knock on wood.”

The committee and the Board of Directors have already approved the use of roll-call votes during their remote meetings and modified other rules and procedures that compensate for the inability to meet in person. ERCOT’s corporate members will convene virtually July 10 to vote on the changes.

In-person meetings will not resume until October, at the earliest — if then.

ERCOT in May extended mandatory work-from-home rules through September. Staff can request “limited periods” of on-site work for “business-critical” task that can’t be completed remotely, but approvals will be limited and must come from executive leadership, human resources or security and facilities.

ERCOT Finds New Corporate HQ Site

Staff discussed with the committee their plans to move into a new office space, assuring members the new digs would not increase the system administrative fee.

Facing a 2022 expiration on its Austin office space it leases for corporate staff and Independent Market Monitor, ERCOT engaged a commercial real estate firm to find a new one. The grid operator’s criteria included at least 35,000 square feet of space, 180 parking spaces, proximity to the city’s airport and hotels, and an option to purchase.

The search resulted in a location within the same MetCenter business park where ERCOT is currently located. The board this month gave staff the go-ahead to execute an agreement with developers, which is expected to be finalized by the end of July, with construction to begin in August.

The grid operator expects the two-story building to be ready for occupancy by the end of next summer. Construction, equipment and furnishing costs are expected to be about $20 million, with ERCOT expecting to break even within 13 years.

ERCOT TAC — Artist rendering of ERCOT’s new corporate headquarters | *ERCOT*

Staff said a lack of meeting space and technology issues are the main reasons they are moving from their home of 20 years. ERCOT supports about 300 stakeholder meetings each year at its MetCenter location.

“With the pandemic, do we even need a MetCenter? The answer is a strong ‘yes,’” said Betty Day, vice president of security and compliance. “The number of meetings is increasing.”

The new building will include two additional meeting rooms among its 5,000 additional square feet of public meeting space. Informal meeting areas, public booths and phone rooms will also be added.

Day said staff have had “multiple” conversations with the board about the plan. During individual meetings with stakeholders last fall, staff “made stakeholders aware this lease was coming up and we would look at alternatives,” she said.

Committee members expressed concern over making a costly real estate decision during a bad economy and encouraged further due diligence. Day said ERCOT felt the project’s costs were “reasonable.”

“We’re where we are,” Magness said during his online panel discussion. “We had to move on making a decision. As long as there’s ERCOT, there’ll be meetings. We’re moving forward with the real estate decision in this strange environment.”

Software Error Results in ‘Minimal’ Market Exposure

Staff said a software error in ERCOT’s credit monitoring and management system resulting from a 2012 protocols change resulted in “minimal” exposure to the market.

Mark Ruane, director of settlements, retail and credit, said errors in a real-time liability forward (RTLF) calculation resulted in a 100% multiplier, rather than the proposed 150% multiplier, being applied to some components of the real-time liability calculation, among other errors.

System limitations kept staff from quantifying the number of instances where an erroneous calculation determined a counterparty’s total potential exposure, Ruane said. He said the error may have resulted in either higher or lower RTLF estimates.

Staff patched the error on June 4 by aligning the calculation with the 2012 Nodal Protocol revision request (NPRR) that reduced the time frame for an operating day’s cash clearing and correspondingly reduced required collateral. ERCOT notified market participants of the error that same day.

Given the chance to ask questions, none of the TAC members did.

RTCTF Continues its Work

ERCOT’s Matt Mereness, chair of the RTCTF, told the TAC that the group met June 22 to consider ancillary services’ deployment and recall. Staff walked the task force through a 44-page slide deck in sharing their view and understanding of the process.

“As we develop the protocols, sometimes it’s hard to see how everything fits together,” Mereness said.

The task force is reviewing 90 of 187 binding document sections. It has reached consensus on 64 sections as it works toward a November deadline to develop real-time co-optimization’s protocols.

TAC Endorses Consent Agenda’s 16 Changes

The committee unanimously approved a 16-item consent agenda in a voice vote that concluded the meeting. Many of the changes were noncontroversial cleanup items; some removed gray-boxed language that is no longer needed. Four other changes were tabled while waiting on related revisions to pass through the stakeholder process.

The changes included six NPRRs, four changes to the Nodal Operating Guide (NOGRR), three revisions to the Planning Guide (PGRRs), a system change request (SCR), and single revisions to the Resource Registration Glossary (RRGRR) and the Verifiable Cost Manual (VCMRR):

NPRR 9 0 3: clarifies the deviations that may occur with day-ahead market delays and adds language requiring ERCOT to issue a market notice for any act or omission to ensure the day-ahead process is successfully completed.
NPRR9 7 3: adds definitions for generator step-up and main power transformer to the Nodal Protocols and clarifies their uses.
NPRR9 8 3: deletes remaining gray-boxed language associated with NPRR257 (Monitoring Programs and Changes to Posting Requirements of Documents Considered CEII).
NPRR9 90: deletes the remaining gray box for NPRR889 (RTF-1 Replace Non-Modeled Generator with Settlement Only Generator) and relocates the defined term “combined cycle train” from “Resource” to “Resource Attribute.”
NPRR 992: ensures the day-ahead liability estimate correctly includes ERCOT contingency reserve service charges and payments, as intended by NPRR863 (Creation of ERCOT Contingency Reserve Service and Revisions to Responsive Reserve).
NPRR 993: clarifies gray-boxed language after the concurrent approval of NPRR902 (ERCOT Critical Energy Infrastructure Information) and NPRR928 (Cybersecurity Incident Notification).
NOGRR 196: clarifies language used by NPRR973-proposed defined terms “generation step-up” and “main power transformer.”
NOGRR20 0: deletes all remaining gray-boxed language associated with NOGRR025 (Monitoring Programs for QSEs, TSPs and ERCOT).
NOGRR20 2: removes language regarding the posting timeline for resources’ megawatt limits when providing responsive reserve service. The requirement is now outlined in the Other Binding Document procedure for calculating individual resources’ limits.
N OG RR 20 5: clarifies gray-boxed language to maintain consistency with revisions adopted from NOGRR197 (Align Responsive Reserve Manual Deployment Requirements with Current Practice) following the November 2019 incorporation of NOGRR191 (Related to NPRR939, Modification to Load Resources Providing RRS to Maintain Minimum PRC on Generators During Scarcity Conditions) into the guide. It also corrects an error in ERCOT’s administrative comments to NOGRR191 that inadvertently changed the language.
PGR R 0 74: clarifies language used by NPRR973-proposed defined terms “generation step-up” and “main power transformer.”
PGR R 078: specifies that data related to the regional transmission plan and special planning studies considered protected information may be posted to the market information system’s certified area for transmission service providers. The change also includes updated resource asset registration form generator data postings to the system.
PGR R 080: aligns the Planning Guide with NERC standard TPL-007-4 (Transmission System Planned Performance for Geomagnetic Disturbance Events) by identifying responsibilities for performing studies needed to complete benchmark and supplemental geomagnetic disturbance vulnerability assessments.
RRGR R 022: clarifies language used by NPRR973-proposed defined terms “generation step-up” and “main power transformer.”
SC R 810: adds logic to ERCOT’s energy management system by removing the flag that indicates to the operator that a unit representing a DC tie does not count toward the 2% criterion for activating transmission constraints.
VCMRR207: removes from the manual and its appendix language regarding the validation rules imposed on ERCOT’s external telemetry and used in the resource-limit calculator. This maintains consistency between the manual and the protocols by aligning energy storage resource-related provisions with NPRR986 (BESTF-2 Energy Storage Resource Energy Offer Curves, Pricing, Dispatch and Mitigation) and its provision that storage resources do not have start-up or minimum-energy costs and sets their mitigated offer cap at the systemwide cap.

June 26, 2020

‘Astonishing’ Buildout Needed for Clean NY Grid

Meeting New York’s ambitious clean energy goal of having the first grid in the country to reach 100% emissions-free electricity will require an “astonishing” 80 GW of new generation by 2040, NYISO stakeholders heard Monday.

Brattle Group representatives presented the Installed Capacity/Market Issues Working Group their final analysis of the state’s evolution to a zero-emission power system.

The report included three “alternative scenarios” modeling operations and investment in scenarios of increasing electrification for the years 2024, 2030 and 2040, as stakeholders had requested when presented the base case modeling in May. (See NYISO Examines ‘Evolution’ to Zero Emissions.)

“This is a sweeping study of a complete transformation of the system over the next two decades,” Brattle’s Sam Newell said. “By 2030 the system would need about 35 GW of additional wind and solar to meet the 70% renewable goal, and 80 GW relative to today of new wind and solar by 2040 to get to zero carbon.”

Signed into law last July, New York’s Climate Leadership and Community Protection Act (CLCPA) mandates, among other targets, that 70% of the state’s electricity come from renewable resources by 2030 and that generation be 100% carbon-free by 2040. (See Cuomo Sets New York’s Green Goals for 2020.)

“That means adding about 4 GW per year of onshore wind, offshore wind and solar in some combination,” Newell said. “That’s an astonishing pace.”

As part of its “Grid in Transition” initiative, the ISO retained Brattle to simulate the resources that can meet state policy objectives and energy needs in order to inform planning for reliability and market design over the next two decades. (See N.Y. Looks at Grid Transition Modeling, Reliability.)

Three Scenarios

Brattle developed three scenarios to address a range of questions from NYISO and stakeholders, including: an existing technologies case; a increased flexibility case (with expanded interties to Hydro-Québec); and an expanded transmission case (with new lines southbound).

The study is modeling for a 20-year time horizon. Given the amount of uncertainty about what available technologies, costs, and state and market rules will be, the ISO and its stakeholders thought it was important to use alternative scenarios to get a sense of how much the results change under different assumptions, said Brattle Senior Associate Roger Lueken.

“One thing to stress is that there is a lot of uncertainty in the study both in terms of the setup and the results,” Lueken said. “Of course, there’s a lot more scenarios that we could look at, but these were the three that it sounded like were of most interest.”

The study compares each of the scenarios to the high electrification case and to the base case results, he said.

In addition to the CLCPA, a key public policy driving decarbonization of the grid is the Regional Greenhouse Gas Initiative, the Northeast regional cap-and-trade program that had an average 2019 price of $5.40/ton of carbon dioxide, which is expected to reach $12.60/ton by 2030.

The study also considers the zero-emissions credit (ZEC) program for payments to New York nuclear plants, which expires March 2029, and the Department of Environmental Conservation rule to reduce NOx emissions from peaking plants, whereby peakers built before 1986 will most likely retire instead of retrofitting to meet emissions requirements.

The state’s new emissions regulations go into effect May 1, 2023, and generator compliance plans were due March 2. (See NY DEC Kicks off Peaker Emissions Limits Hearings.)

Through the Looking Glass

The existing technologies case for 2040 gives high-level insights into a large overbuild of renewables (+80 GW from current levels) and storage (+27 GW) to meet load in all hours, with large curtailments of 221 TWh, or 50% of projected generation.

New York grid — The existing technologies case for 2040 gives high-level insights of a large overbuild of renewables (+80 GW) and storage (+27 GW) to meet load in all hours. | *The Brattle Group*

In addition, retirement of gas plants by 2040 causes unforced capacity reserve margins to fall below planning reserve margins, and load falls by 50 TWh without in-state renewable natural gas production.

“In the second case — increased flexibility — we model expanded interties to Hydro-Québec as being able to provide flexibility, and we model more flexible load on the system,” Lueken said.

Lueken said “there are many different ways load can be flexible,” but Brattle chose to focus on two.

“The first is controlled electric vehicle charging, so people with EVs can control at what time of day they charge,” he said. The second is controllable heating and air conditioning loads, with the study assuming that buildings are outfitted with smart thermostats or types of HVAC that allow occupants to vary their thermostat point in order to shift their load from hour to hour.

“The third case is an expanded transmission case where we model transmission along key corridors from upstate New York into downstate New York, and between Zone J [New York City] and Zone K [Long Island],” Lueken said.

The New York Public Service Commission in May authorized a study to identify distribution upgrades, local transmission upgrades and bulk transmission investments needed to meet the state’s clean energy goals (20-E-0197). (See NYPSC Launches Grid Study, Extends Solar Funding.)

The third case is designed to show how the amount of transmission affects what types of resources are built and where they’re added.

Brattle made three specific updates to the scenario. The first update was increasing transmission from zones A through E (Western to Central New York), and to zones G, H and I (Central and Lower Hudson) by 2,000 MW, and more than doubled the base case transfer limit from 1,900 MW to 3,900 MW, Lueken said.

“The second update was increasing transmission from zones G, H and I into the Zone J by 2,000 MW, upping the transfer limit in the base case from 3,900 MW to 5,900 MW. Both of those upgrades were unidirectional, so we only increased the flow limit in the downstate direction,” Lueken said.

The third update was applied bidirectionally, assuming that the transmission lines between zones J and K increase by 1,000 MW, so that an additional 1,000 MW can flow from J to K and vise-versa, he said.

In response to a question about assumed costs for the transmission buildout, Lueken said “we did not compare the cost of building the increased interties to Hydro-Québec to the benefits; we simply reasonably assumed that they occurred and checked what happens to the resulting resource mix. The same is true here — we don’t make assumptions about what these upgrades cost, and we don’t compare the benefits of these upgrades to some estimate of what they might cost.”

Merits a Closer Look

The study’s main point is that the projected renewable needs for 2030 are in line with the technical potential for renewables in New York, but projected needs for 2040 will possibly exceed that potential, Lueken said.

He reiterated his cautionary note about the uncertainty around what the actual limits are, especially the estimates from the Department of Public Service, the New York State Energy Research and Development Authority and the National Renewable Energy Laboratory.

“One thing that might be worth further study by the Iabs or by the state or someone is getting a better sense of what these limits really are, and how that might influence the types of resources that are built,” Lueken said. “This is most obvious looking at solar, where for the amount of potential the limits range from 7 GW to 50 GW to almost 1,000 GW.”

Newell wrapped up the presentation by emphasizing Lueken’s last point: “The one area for further study is how do these needs relate to resource potential, including how much offshore wind you can get without transmission being built to access whatever lease sites are developed.”

“In any case, we’re talking about massive amounts of intermittent resources that are difficult to rate properly in terms of capacity,” Newell said. “Their intermittency is accounted for in installed capacity reserves studies, but they’ve become such a big part of the system, it’s worth taking a closer look at how you look at multiple years of wind and solar data, and more robustly incorporate that into the analysis, and extend that to resource accreditation.”

June 26, 2020

Mankato Sale Approved over Public Citizen Concerns

FERC on Wednesday approved the purchase of the Mankato natural gas plant in Minnesota by a specially created subsidiary of Southwest Generation, despite concerns about the company’s links to a JPMorgan Chase investment fund (EC20-54).

Denver-based Southwest Generation Operating Co. formed subsidiary SWG Minnesota Holdings for the sole purpose of acquiring the 760-MW Mankato Energy Center for $680 million.

Through a series of parent company arrangements, JPMorgan’s Infrastructure Investment Fund (IIF) holds 100% of the voting securities of Southwest Generation Operating Co.’s parent company. IIF is controlled by three private owners using a slightly different company name. Those owners also own about 29 MW worth of small generating facilities in MISO.

Consumer interest group Public Citizen had questioned JPMorgan’s involvement with the sale, asking the commission to require the company to more clearly explain its involvement with its subsidiary investment fund.

“Determining IIF’s affiliation with JPMorgan Chase and Co. in the Mankato transaction is vital for establishing whether the Mankato transaction is in the public interest, as failing to address affiliation threatens harm to competition, rates and regulation,” Public Citizen said.

Mankato sale — Mankato Energy Center | *Southern Co.*

But FERC said the new owners are affiliated with just 0.4% of the generation capacity in MISO, a “de minimis amount.” The commission declined to require SWG Minnesota Holdings to conduct an analysis to prove no harmful effects on competition.

The commission also said that “treating J.P. Morgan Investment as an affiliate of SWG Minnesota Holdings would not change the ultimate result of the commission’s analysis of the effects of the proposed transaction on competition, rates, regulation or cross-subsidization.”

Xcel Energy purchased Mankato from Southern Co. for $650 million in January. The quick turnaround will net the utility $30 million, two-thirds of which it promised will be earmarked for corporate giving and COVID-19 relief in its eight-state territory.

Mankato will continue to provide energy to Xcel through long-term contracts.

June 26, 2020

IMM Issues 5 Recs in MISO State of the Market Report

MISO’s Independent Market Monitor issued five new recommendations in its annual State of the Market report released Wednesday, focusing on the RTO’s management of flows across its seams, dynamic transmission line ratings and whether energy efficiency should be considered a capacity resource.

But IMM David Patton also used presentation time before the MISO Board of Directors’ Markets Committee to issue a warning on the deteriorating condition of the RTO’s reserve margins.

MISO Executive Director of Market Strategy and Design Scott Wright said the new recommendations this year concentrate on seams and efficient use of the transmission system. Three recommendations offer advice on how to manage flows between neighboring RTOs, where the Monitor suggests:

Using new testing criteria for defining market-to-market constraints. Patton said the rules for determining flowgates have not been overhauled since 2004 and could use an update that places more emphasis on how much available flow relief a non-monitoring RTO can provide.
Improving the relief request software used in market-to-market coordination. Patton said MISO’s current relief request software does not always request enough relief from the non-monitoring RTO because it doesn’t consider shadow price differences between the RTOs.
Clearing coordinated transaction scheduling transactions with PJM every five minutes based on the most recent five-minute prices, not forecasts. The Monitor said “persistent forecasting errors by MISO and PJM have likely hindered” use of coordinated transaction scheduling. Instead, Patton said the most recent five-minute prices are a more accurate forecast of the prices over the next five minutes.

Patton’s two other recommendations include MISO developing the capabilities to apply dynamic transmission line ratings from transmission owners and disqualifying all energy efficiency resources from the capacity auction.

Most MISO TOs don’t adjust line ratings to reflect ambient temperatures and wind speeds, Patton said. He said a “broad adoption” of ambient-adjusted ratings could have reduced congestion costs by $150 million in 2018 and 2019.

Patton also said if all TOs provided short-term emergency ratings, which tend to be about 10% higher than normal ratings, MISO might have saved as much as $114 million in congestion over the past two years.

“The ratings transmission owners provide tend to be overly conservative,” Patton said. “If you calculate how much we could save by rating transmission lines more efficiently, it would be something like $265 million.”

MISO State of the Market — MISO IMM David Patton | © *RTO Insider*

Further, Patton said more efficient line ratings on just the top 25 constraints could achieve two-thirds of that estimated savings alone.

“Hopefully over the next year, we’ll see some progress,” he said, adding that effectively managing congestion can save MISO more than developing a new, big-ticket market product.

Patton also said allowing energy efficiency resources to offer into the MISO Planning Resource Auction (PRA) makes little sense.

“Funneling an additional subsidy to pay for LED lightbulbs is an inefficiency,” Patton said, adding that capacity payments for energy efficiencies don’t make sense because entities with installed energy efficiency are already saving on retail bills.

He also said capacity payments for energy efficiency owners further offset the bills that contain, ironically, the cost of serving them, including energy, ancillary services, and capacity, transmission and distribution costs.

“When they purchase energy-efficient equipment, the electric bill savings include all of these elements. There’s just an array of problems,” Patton said of energy efficiency receiving funding through MISO’s capacity market. “The quantities are growing rapidly and in key tight locations like Michigan.”

Last year, Patton produced six new market recommendations as part of his 2018 report, among them clarifying the criteria for calling emergencies, procuring operating reserves on the Midwest-to-South regional transfer limit and lowering the generator shift factor cutoff for transmission constraints with limited relief. (See MISO Monitor Poses 6 New Market Recommendations.) MISO has yet to issue proposals on any of the 2018 recommendations, though it is working on new capacity accreditation requirements that could address two of the six recommendations. The RTO also discussed possible improvements to the logging and documenting of emergency procedures with the Monitor last year.

Markets Competitive, but Trouble Brewing

Patton also reported that offers into the MISO markets throughout 2019 were highly competitive.

“The prices were about as competitive as they could be. The MISO markets always performed very competitively,” Patton told board members.

Real-time prices for the year averaged just $26/MWh in the footprint, driven by cheap natural gas and a 2% decrease in average load, while a cooler year overall brought lower demand, he said.

By the IMM’s count, 3.3 GW of resources retired in MISO last year. Of those megawatts, almost 90% were coal generation. Patton said more than 4.5 GW of new capacity entered MISO over the same time, including nearly 2 GW of natural gas capacity in MISO South and more than 2 GW of less dependable nameplate wind capacity.

“Nuclear and coal resources are under a tremendous amount of pressure, mainly because gas prices are so low,” Patton said.

Patton predicted a continued gradual loss of coal resources in MISO, making the need for reliable capacity resources more pressing. He said the retirements make MISO’s possible rethink of its capacity resource accreditation even more crucial. Capacity accreditation must be doled out according to resource’s ability to serve capacity reliably, he said.

“It’s likely to be one of the most unpopular proposals among participants, since it’ll look like we’re taking capacity credits away. It’ll be a heavy lift because it’ll look hostile — or at least adverse to their interests — to participants,” Patton said.

“What’s striking about this [report] is the theme of a resource mix in transition,” Wright said.

The Monitor also reserved space in the report to decry the continued use of a vertical demand curve and advocate for a sloped demand curve in the PRA.

Save for a high zonal price in Lower Michigan in this year’s capacity auction, the PRA produces prices that are “close to zero and generally represent less than 2% of the revenue needed to support investment in new peaking resources,” Patton said. “These prices have really hammered the merchant generation and forces them into retirement … or selling capacity outside the footprint.”

Addressing its board earlier this month, MISO said there was a “lack of assurance that the existing resource adequacy construct will … promote participant investments that ensure sufficient resources are available to meet load in all time periods.”

According to MISO’s Tariff, the RTO’s leadership has 120 days, until Oct. 16, to make a public response to Patton’s recommendations.

June 26, 2020

MISO Planning Advisory Committee Briefs: June 24, 2020

MISO has temporarily backed off requiring load-serving entities to provide the location and capacity values of distributed energy resources for its planning models.

Planning Modeling Manager Amanda Schiro said the requirement for LSEs to provide counts of inverter-based DERs on distribution systems has been downgraded to a request for 2021.

Schiro said this year’s request is only intended to allow MISO to get a better handle on DER siting. She said the RTO is only in a “data-gathering mode” to possibly introduce future modeling improvements that better capture DERs.

MISO wants LSEs to provide more explicit DER estimates for transmission planning models by 2022.

MISO Planning Advisory Committee — Rooftop solar in Indianapolis | © *RTO Insider*

DERs are registered in the capacity market but not represented in the RTO’s planning models, Schiro said. She said DER integration into reliability planning and operations and market systems will soon necessitate a modeling change.

Summer peak load continues to drop slightly every year, and DERs could play a role in that, Schiro said.

“We want to plan for the situation we’re going to find ourselves in,” she said.

For now, MISO needs more information to decide how to represent DER in modeling, Director of Planning Jeff Webb said.

“We’re trying to just get an understanding of what’s out there,” he said, agreeing with stakeholders that MISO must engage in more discussion with LSEs before it adopts a new approach for better estimating DER in planning models.

Some LSE representatives have expressed skepticism over MISO’s DER modeling goals.

WEC Energy Group’s Chris Plante said many LSEs already include in their forecasts any DERs they have insights into. He also said it might be impossible for MISO to locate all DERs.

“In some cases, it might not be practical to model some DERs because some might be behind the customers’ meter, and we have nothing to do with it,” Plante said.

MTEP Transfers Under Study

MISO has defined the transmission transfers it will study in its 2020 Transmission Expansion Plan (MTEP 20) to determine the system’s capability for handling various transfer scenarios.

The RTO is studying nine transfers under the MTEP 20 voltage stability analysis, which seeks to find future “soft spots” that might cause contingencies on the system. Three of the transfer scenarios will focus on transfer paths from Minnesota to areas in Wisconsin and Illinois, while two others focus on exports into the Downstream of Gypsy area near New Orleans from other Entergy territories.

The analysis also includes:

Minnesota and North Dakota’s exports into Manitoba Hydro territory;
Indiana and southern Michigan’s exports to the St. Louis area;
exports from Iowa into the MISO Central planning region of Indiana, Illinois, western Kentucky and eastern Missouri; and
MISO South to the West of the Atchafalaya Basin load pocket straddling Texas and Louisiana.

Additionally, MISO is studying five transfers under its NERC-required transfer study, used to determine the ability of the MISO system to handle possible power transfers across the footprint:

MISO’s South Region to SPP;
Ontario’s Independent Electricity System Operator to MISO’s East planning region;
MISO Central to the North planning regions in both directions; and
PJM’s Northern Illinois territory to the rest of its footprint east of Indiana.

Nearly all the transfers were chosen based on heavy historical usage; however, the PJM transfer was selected because of an influx of wind generation additions in the area by 2025.

At the end of last month, MTEP 20 contained 510 proposed projects at a combined $4.06 billion. (See Price Tag Rising for MTEP 20.) Those figures will remain fluid as MISO finalizes the transmission package over the next three months.

MTEP 20 is also on a shorter-than-usual timeline this year.

MISO announced earlier this year that it will revise the MTEP 20 schedule to allow the Board of Directors’ System Planning Committee an additional month to review the transmission package prior to the full board vote in early December. That means the PAC will review, then vote on, whether to recommend the draft MTEP 20 report about a month earlier than usual, in September instead of October. (See “MTEP 20 Schedule Change,” Northern Focus for MTEP 20.)

PAC Chair Cynthia Crane has said the truncated MTEP timeline caused “some consternation” among stakeholders. “As much as everyone wants to give the board extra time to review, it’s going to take a month out of the process to form the MTEP,” Crane reported to the MISO Steering Committee in February.