Page 1075 – RTO Insider

July 14, 2020

PJM OC Briefs: July 9, 2020

The PJM Operating Committee on Thursday unanimously endorsed a “quick fix” solution to give transmission owners access to the Dispatch Interactive Map Application (DIMA), a geospatial situational awareness program that RTO dispatchers have used since 2014.

Ed Kovler, PJM’s senior lead business solutions architect, presented and reviewed the problem statement and issue charge on expanding access to DIMA, which allows operators to see the location of problems on the grid in real time. The quick fix was first presented at the June 4 OC meeting. (See “Dispatch Interactive Map Application,” PJM Operating Committee Briefs: June 4, 2020.)

John Sturgeon of Duke Energy said his company is supportive of TOs having access to DIMA. He asked if there has been any discussion by PJM on the cost of the program and if costs will be passed off to all TOs.

Kovler said PJM had initially considered charging for access to the application, but a decision was made to open it to all TOs at no additional cost. He said costs will be integrated into PJM’s budget.

PJM Operating Committee — DIMA geospatial overview | *PJM*

Tonja Wicks of Duquesne Light Co. asked if confidential information could be added to DIMA and if TOs will be informed by PJM before any changes in information access are made.

Kovler said there are no plans to add any information beyond what has already been demonstrated. The RTO would have to develop a governance process if additional data is added in the future, he added.

PJM plans to present the DIMA issue charge at the July and August Markets and Reliability Committee meetings and the September Members Committee meeting. If endorsed, the Operating Agreement changes will be sent to FERC in September for approval.

COVID-19 Operations Update

Pennsylvania’s move to the “green phase” for reopening from the COVID-19 shutdown has not had a major impact on PJM’s operations, Paul McGlynn told the committee in an update on the RTO’s pandemic operations plan.

McGlynn said most staff continue to telecommute, while control room workers have gone back to a “normal configuration” of two control rooms. He said procedures augmenting operations support staff during critical operating periods have been established.

The current procedures will be in place through at least Labor Day, McGlynn said, and PJM staff will continue to monitor infections in the area and adjust operating plans as needed.

“The PJM plan is flexible and cautious,” McGlynn said.

Stakeholders asked about the year-end deadline PJM instituted for market operations centers that interact with the RTO to operate remotely from their main offices and whether any consideration is being given by the RTO to extending the deadline, as many businesses will continue to operate remotely into 2021.

Mike Bryson of PJM said there were certain compliance concerns regarding keeping the deadline open-ended, but he said extending the deadline should not be an issue if it’s needed.

Synchronous Reserve Review

Rebecca Carroll, PJM’s dispatch director, reviewed the findings from the RTO’s inquiry into why shortage pricing was not triggered during a June 3 incident when synchronized reserves fell short in real time. The report was requested by several stakeholders at the June OC meeting.

Carroll said PJM’s synchronous reserves dipped below the requirement by about 50 MW for about four minutes, from 4:02 to 4:05 p.m. ET.

Real-time security-constrained economic dispatch (RT SCED) case approvals can commit additional reserves to meet the requirement based on the available resources in a 10-minute look-ahead, she said. Real-time synchronized reserves involve an instantaneous calculation of available reserves.

The phenomenon seen on June 3 happens “occasionally,” Carroll said, where generation is either not following the base points sent by PJM or load comes in higher than the forecast. Carroll said the reserves were being fully met by Tier 1 resources at the time and that PJM saw a “significant amount” of Tier 1 generators that were over-generating.

Carroll said generation dispatchers received an alarm the second reserves dipped below the reserve requirement and were able to commit additional condensers to restore the reserves to the requirement.

Gary Greiner, director of market policy for Public Service Enterprise Group, suggested PJM should use both Tier 1 and 2 resources to avoid what happened June 3. “When you have diversity in supply, you can better address situations like this where you’re over-generating,” he said.

Carroll replied that the decision to go with Tier 1 resources is solely based on economics. If there’s enough Tier 1 reserves, she said, the RT SCED engine will use that to solve any problems because it’s the cheapest.

The issue will not exist when Tier 1 is eliminated because of FERC’s ruling in May approving PJM’s proposed energy price formation revisions that consolidate Tier 1 and 2 reserve products, she said. (See FERC Approves PJM Reserve Market Overhaul.)

Black Start Fuel Requirements Update

David Schweizer, PJM’s manager of generation, provided an update on the work plan for the fuel requirements for black start resources. The work was put on hiatus in March pending refining of proposals and costs with stakeholders. (See PJM Backs off Black Start Fuel Rule.)

Schweizer said the intent of additional analysis was to provide further supporting information and to better inform stakeholders regarding the impact of any of the packages proposed.

Technical analysis being done by PJM is focusing on enhancing the previous restoration impact analysis, Schweizer said, which looked at the incremental increase in restoration time analysis if non-fuel-assured black start resources are unavailable during a restoration event.

PJM is also investigating potential gas pipeline and supply issues impacting restoration, Schweizer said, including studying the impacts of the loss of power to gas compressor stations.

Schweizer said work was delayed in the spring because of the COVID-19 pandemic, but PJM hopes to have its analysis done and to restart the stakeholder process by the end of 2020.

July 14, 2020

Colo. ALJ Proposes $235M Exit Fee for United Power

A Colorado administrative law judge on Friday recommended to the state’s Public Utilities Commission that it accept United Power’s exit-fee methodology in its long-running dispute with Tri-State Generation and Transmission Association, saying United and fellow complainant La Plata Electric Association (LPEA) were treated in a “discriminatory manner” (19F-0620E, 19F-0621E.)

Under the recommended methodology, United would pay Tri-State $234.8 million, a figure United said was “comparable” to payments made by other members leaving the cooperative. Tri-State had proposed a charge of $1.25 billion, an amount that would have resulted in an “unfair windfall” to the association’s remaining members, United said.

LPEA would pay almost $97 million to leave Tri-State under the ALJ’s recommendation. The cooperative has not been offered an exit fee by Tri-State.

United Power exit fee — An ALJ’s judgment favors United Power’s exit-fee formula in its tiff with Tri-State G&T. | *United Power*

FERC in June accepted Tri-State’s proposed contract-termination payment (CTP) methodology for filing but also set hearing and settlement judge procedures. The commission said it could not resolve issues of material fact based on the existing record and that the CTP methodology had not been shown to be just and reasonable (ER20-1559). (See FERC Sets Tri-State’s Exit-fee Rules for Hearing.)

United in May filed a lawsuit in a Colorado county district court against what it called a “civil conspiracy” to deprive state regulators of jurisdiction over Tri-State’s exit fees. That proceeding is pending, but a Colorado ALJ in the meantime rejected Tri-State’s defense that the PUC lacks jurisdiction.

The parties have 20 days to file exceptions to last week’s decision, after which the PUC will then consider the complaint.

United has been trying for more than two years to arrange an exit from Tri-State before its wholesale service contract expires in 2050.

“We recognize this is just the next step in a long process,” said Bryant Robbins, acting United CEO, in a statement. “It’s our goal to provide reliable power to every family and business we serve, and to provide that power at a cost that makes sense. We carefully considered our obligations to Tri-State and developed what we believed was a fair exit cost.”

In a competing statement, Tri-State CEO Duane Highley said efforts “to protect the interests of all our cooperative members and their electricity consumers” will continue before the PUC and FERC, and he issued a warning to the cooperative’s members.

“If this decision is allowed to stand, more than $1 billion in costs will be unjustly added to our members’ electricity bills in Colorado, Nebraska, New Mexico and Wyoming,” Highley said. “In an effort to save money for themselves, United Power and LPEA are a step closer to forcing costs they agreed to pay onto smaller, less wealthy utilities and their rural consumers.”

Tri-State said the recommendation would result in a contract termination figure “that is far below any fair value” of the two utilities’ contracts and “well below” their share of the association’s debts and other obligations. It said United’s share of its outstanding debt and other obligations is approximately $762 million.

The association also noted that United and La Plata both “freely signed” long-term power contracts with it in 2007 and agreed to share the supply costs with other utility members. It also said the CTP methodology was developed by its utility members and that they all can participate in the FERC settlement and hearing process.

The two utilities are among Tri-State’s three largest members. United is the largest, with about 15% of electric demand thanks to its 93,000 members in Denver’s northern suburbs. La Plata is the third largest among Tri-State’s 42 distribution utility members, with more than 34,000 members in southern Colorado.

July 14, 2020

Calif. Rushing Microgrids for Fire Season Shutoffs

California is moving quickly to adopt microgrids to store wind and solar energy and to provide electricity during public safety power shutoffs (PSPS) in wildfire season, but long-term energy storage and resilience remain problems, panelists said last week at a California Energy Commission workshop on “Assessing the Future Role for Microgrids.”

Leaders of the CEC, the California Public Utilities Commission and CAISO met in three sessions over two days during the workshop, hearing from panelists and presenters on the challenges and promise of microgrids: small-scale generation and distribution systems that can power a single building or a whole community.

Over a total of six hours, participants discussed using microgrids to offset fire-prevention blackouts starting this fall and, in the longer term, to store renewable power and make up for possible capacity shortfalls during the switch from natural gas plants to renewable resources in the next three years.

Senate Bill 100, passed in 2018, requires load-serving entities to provide only zero-carbon electricity to retail customers by 2045.

“Microgrids are one of the tools that will help the state get to our 100% clean energy standard in the most efficient and equitable way possible,” said CEC Vice Chair Janea Scott, who led the sessions.

CPUC President Marybel Batjer said she’s worried about Pacific Gas and Electric’s plan to use diesel generators to supply electricity during PSPS events this summer and fall. PG&E intends to connect hundreds of diesel generators at substations to supply customers during the shutoffs.

“I am concerned that this wildfire season, we will see a lot of diesel generation used to ensure resiliency, and we have to get to a cleaner and quieter form of resiliency backup power,” Batjer said.

Neil Millar, CAISO’s vice president for transmission planning and infrastructure development, said it was important for the ISO to learn about the “different flavors of microgrids that are evolving” and to ensure “our existing processes are adequate for accommodating them.”

CAISO and the CPUC are working to manage the connection of microgrids to the statewide grid and to include microgrids in the state’s resource planning process, he noted.

Fast-tracked Measures

Senate Bill 1339, passed in 2018, directed the CPUC to “facilitate the commercialization of microgrids for distribution customers of large electrical corporations” by Dec. 1.

In response, the CPUC established a new section in its Energy Division focused on microgrids and fast-tracked rulemaking to speed the connection of microgrids in anticipation of this year’s fire season, which typically lasts from late summer through November.

In June, it adopted a proposed decision ordering investor-owned utilities to streamline and expedite interconnection processes for microgrid resilience projects and to work with local and tribal governments to bring the projects online by late summer, in time for the anticipated power shutoffs. (See California PUC Approves Microgrids, Fire Plans.)

The CPUC directed energy storage facilities to import power from the grid prior to PSPS events. It permitted PG&E to upgrade substations and install diesel generators, but only for the 2020 fire season. And it ordered IOUs to increase staffing to hasten microgrid interconnections.

“We’re really focused on … fast-tracking near-term strategies and actions we can put in place in time for this year’s wildfire season,” PUC Senior Analyst Jessica Tse said during the first microgrid workshop session on July 7.

Beyond the next few months, the CPUC and CEC are seeking ways to build microgrids that use wind and solar with battery storage to ride out power outages. (See CPUC Proposal Would Promote Microgrids.)

The CEC is funding millions of dollars in pilot projects to find microgrid solutions that can be replicated and installed on a larger scale. The projects are on military bases and tribal lands, at ports and airports, in industrial settings and wastewater treatment plants, and in low-income and disadvantaged communities.

Projects recently approved include $6 million to determine if it might be feasible to use banks of batteries that have been removed from electric vehicles, but still have plenty of useful life, for storage in microgrids. With 750,00 EVs sold so far, and millions more expected to hit California roads in the next decade, there will be a lot of used batteries, CEC Chair David Hochschild said. (See Calif. Energy Commission OKs $22M for Storage.)

California microgrids — The city of Fremont, Calif., employs solar and battery storage to power critical facilities such as fire stations. | *City of Fremont*

In another CEC-funded project, the city of Fremont is using solar and battery storage to allow critical facilities such as fire stations to “island” from the grid for up to three hours. But local jurisdictions need the ability to provide power while disconnected from the grid for longer periods, said Rachel DiFranco, the city’s sustainability manager.

PG&E’s fire-safety blackouts in the fall of 2019, affecting hundreds of thousands of customers, lasted for days at a time. (See CPUC Orders Changes to PG&E Shutoff Rules.)

Earthquakes and wildfires could sever ties to the grid for even longer periods, said Rosa Vivian Fernández, CEO of the San Benito Health Foundation, a small clinic that serves thousands of farmworkers in the city of Hollister. In August 2019, San Benito became the first health care facility in California to run entirely on its own zero-carbon microgrid using a rooftop solar array and lithium-ion battery storage.

Fernandez said she learned from visiting Puerto Rico after Hurricane Maria in 2017 that health care facilities could be disconnected from power for weeks, unable to serve patients.

“When disaster strikes … [you] may have severe damage to infrastructure,” she said during the first of Thursday’s two workshop sessions.

Seth Baruch, director of energy and utilities for health care giant Kaiser Permanente, explained why Kaiser had decided to install microgrids at a growing number of its facilities.

In 2018, the Kaiser Permanente Richmond Medical Center was the first hospital in California to install a renewable-energy microgrid for backup power during outages. Hospitals generally use diesel generators for emergency power, but Kaiser is pursuing microgrids as it seeks to become carbon neutral and because diesel fuel can run short in emergencies, Baruch said.

“When you need diesel, everyone needs diesel,” he said. With power shutoffs and potential surges in COVID-19 cases, Kaiser wants to ensure its facilities have power “24/7” for days at a time, he said.

Hydrogen Fuel Cells

The need for microgrids that can supply long-term backup power prompted a discussion Thursday, during the workshop’s final session, on deploying microgrids that use hydrogen fuel cells, which produce electricity through an electrochemical reaction of hydrogen and oxygen.

Lithium-ion batteries can only provide power for short-duration outages. Fuel cells can provide power indefinitely given a supply of hydrogen and oxygen produced by separating water into its components with a solar-powered electrolyzer, advocates said Thursday.

Stone Edge Farm, a 16-acre Sonoma County winery, has a microgrid with solar panels, batteries, an electrolyzer that produces hydrogen from rainwater and a bank of hydrogen fuel cells, winery owner Mac McQuown told commissioners.

“Our objective in our microgrid is to be independent of the utility grid 24/7, 365,” McQuown said.

Microgrids using fuel cells power a low-income housing community in Brooklyn, a college in Bridgeport, Conn., and a high school and fire stations in Woodbury, Conn., said Jack Brouwer, director of the National Fuel Cell Research Center at the University of California, Irvine.

“Fuel cells have this opportunity to do that because they have very high power capabilities to power a whole community,” Brouwer said.

The big problem is cost. In applications such as microgrids, fuel cells produce electricity at $4,000 or more per kilowatt, the NFCRC says on its website. Fuel cells would be competitive in providing power for stationary loads if they reach an installed cost of $1,500 or less per kilowatt, it says.

Current research is seeking to reduce costs by using less expensive materials and producing fuel cells on a larger scale, the NFCRC says.

Brouwer said using hydrogen technology in conjunction with wind, solar and battery storage is another way to make fuel cells more practical. Existing natural gas pipelines might also be able to carry hydrogen, but that idea has proven controversial among clean-energy advocates who want to do away with natural gas entirely, he said.

Still, he said, California may ultimately need hydrogen fuel cells to provide electricity during long outages and to meet its ambitious decarbonization goals.

Hydrogen can “deliver resilience for weeks on end,” Brouwer said, and “the solution to get all the way to zero [carbon] needs something like fuel cells and hydrogen.”

Millar, with CAISO, said he agreed. “The solution here isn’t one or the other; it’s all of the above,” he said.

July 14, 2020February 19, 2025

Electricity Industry Asks for Regulatory Certainty

Former FERC Commissioner Philip Moeller told the current commissioners last week that demand destruction is the electricity industry’s primary concern during the COVID-19 crisis.

Moeller, now executive vice president of the Edison Electric Institute’s business operations group and regulatory affairs, said that the longer it takes to flatten the curve of coronavirus cases, decreasing demand becomes a larger problem.

Phillip Moeller, EEI | FERC

“I don’t know how long [the recovery will take], but if demand stays lower for an extended period of time, that takes on added risk,” he said during a panel on access to capital Thursday, the second day of a commission technical conference on the pandemic’s impact on the energy industry. “The cost of equity is higher, and despite the lower interest rates, that is a risk the market has put into the price of capital.”

In June, EEI ask ed FERC for expedited action on the Notice of Inquiry the commission opened on return on equity policies last year (PL19-4). (See FERC Opens Inquiries into Tx Incentives, ROE Policies.)

“We hope FERC comes up with policy that helps with stability [and] continues to attract [capital] needed to build [transmission] infrastructure,” Moeller said. “It’s getting more and more difficult to build major energy projects. It’s worth remembering that all transmission projects, regardless of who develops them … [go] through a vigorous process. Whether it’s the engineering contract or the construction contract, those are laborious projects in themselves before a project gets the greenlight to go ahead.”

CAISO General Counsel Roger Collanton, speaking for the ISO/RTO Council, said liquidity is the most immediate concern for market participants.

“COVID-19 has caused some disruption in the financial markets, which could affect liquidity sources for market participants to cover their positions,” he said. “In addition, some market participants’ revenue streams may be impacted by declining loads and nonpayment for retail services. This does not mean we can relax our monitoring of credit risk. We must remain even more vigilant during these uncertain times.”

Collanton said the grid operators monitor for credit downgrades and unexpected default rates that could lead to lower amounts of unsecured credit limits. Market participants whose credit ratings fall beneath investment grade would be forced to post only secured forms of collateral for all outstanding liabilities without an allowance for unsecured credit, he said.

“The majority of the market participants qualifying for unsecured credit use only a fraction of their limit to handle the day-to-day variances in their outstanding liabilities,” Collanton said. “However, if a market participant’s declining financial health has led to the elimination of unsecured credit limits in wholesale electricity markets, it has likely led to elimination of unsecured credit in other markets, which could begin to pose a liquidity problem.”

He noted FERC has recently allowed some RTOs to impose higher credit requirements on market participants that may pose a higher credit risk.

“In part, this discretion will allow these ISOs/RTOs to assess the positions of market participants that may not operate physical assets and may create asymmetric risks between themselves and the rest of the market,” Collanton said.

He suggested the commission remind state regulatory commissions to monitor load-serving entities’ financial health and the importance of maintaining credit protections.

FERC Commissioner Bernard McNamee | FERC

Asked by Commissioner Bernard McNamee whether infrastructure investments will continue given the pandemic, American Electric Power’s Antonio Smyth, senior vice president of transmission ventures, strategy and policy, noted that his company has already shifted $500 million of capital spending from 2020 to 2021.

“This really highlights and underscores the importance of the commission continuing to adopt solid ROE policies and mechanisms that are put in place to allow us to continue to invest,” Smyth said. “If we don’t invest today, we’ll certainly suffer the consequence tomorrow.”

Christine Tezak, managing director of ClearView Energy Partners, noted the energy sector is not immune from movements in the global economy.

“This is not leaving anyone untouched,” she said. “Where the commission is going to need to exercise its discretion is discerning where there are developing problems. These are cyclical markets, and the commission needs to recognize it would be asking itself to accomplish a superhuman feat to predict all cyclicality in cyclical markets. I think there’s good faith on Wall Street that state regulators are going to work with utilities and work on recovery of bad debt over some period of time.”

Kinder Morgan President Kimberly Dang said access to capital has improved since the Federal Reserve’s market interventions in March and April, but it has gotten more expensive.

“That has unleashed uncertainty into the industry,” she said. “Projects are more difficult to get done in this environment, and that’s going to drive up required returns. Needed projects are not getting built. We need as much certainty as possible. We can’t have contractors sitting on the right of way.”

Several other panelists weighed in on the danger of regulatory uncertainty.

“The power industry has done a phenomenal job in maintaining reliability and keeping the lights on. I believe we have the tools to manage through right now,” NRG Energy CEO Mauricio Gutierrez said. “The biggest risk, when I talk to investors, is regulatory risk and regulatory intervention. Changing the rules in middle of the game is the biggest risk to investing in the power grid.”

“Our industry is the most capital-intensive industry in America,” Moeller said. “Because of the long-term nature of these investments, we appreciate the extent to which the commission is working to provide that certainty, so we can provide reliable, safe electricity.”

Smyth reminded the commission of the transmission system’s “vital, reliable service, which goes back to the base ROE.”

“We believe the commission should continue with its work to adopt a sound ROE policy,” he said. “On the incentives front, well-crafted ROE policies will ensure the grid works for customers, both today and in the future.”

Duke Energy CFO Steve Young closed the panel discussion by complimenting FERC on its “very fair and balanced view” of the risk associated with building, owning and operating long-term infrastructure.

“Having a healthy respect for that risk, as they set ROEs and recovery policy, is very valuable,” he said. “That allows us to effectively raise capital and gives the investor confidence. They’ve done a good job of that over the years.”

Gas Sector Finds Some Capital Available

Another panel Thursday explored the COVID-19 pandemic’s effect on natural gas and oil supply, demand, transportation and infrastructure planning.

Anatol Feygin, chief commercial officer for LNG giant Cheniere Energy, told McNamee the natural gas industry finds itself in a “very challenging time.” Some sectors have ready access to the capital markets, but others don’t, he said.

“Parts of the industry fall under the infrastructure umbrella where, in a low-interest-rate environment, it has plenty of capital. Hundreds of billions of dollars have been raised on the infrastructure side of world,” Feygin said. “The upstream space is working to morph its business model and economics … to offer the types of return that are attracting … investment. It’s a difficult transition.”

Several panelists said the rapid growth of COVID-19 cases and the ensuing lockdowns caught them off-guard, in contrast with the 2008-2009 financial crisis.

“In 2008 and 2009, we could kind of see that coming a little bit. There was more time to react to it and more time to recover,” said Gary Gibson, CEO of City Utilities of Springfield (Mo.). With the COVID-19 crisis, “we saw some pretty immediate changes in our industry and what consumers were doing. Going forward, we still have issues of when we could shut down again. If we continue in that direction, we’ll see more demand destruction that will continue for several years.”

“There were some lessons learned previously,” he continued, “but we’re learning new lessons now.”

“In 2008, when the economy recovered and our industry’s access to capital was still there, it transformed our industry to be the world lead for gas production,” said EQT CEO Toby Rice, alluding to the shale drilling revolution. “Now, with a lack of returns, there’s very cautious thinking. A lot of people have concerns whether that access to capital returns for the energy industry. We have to ensure we still have access to capital to keep our economy strong, our energy cheap, improve the environment and enhance the national security of our country. We have to be more efficient, to allow the market to be more efficient.”

July 12, 2020January 26, 2025

WECC: Operators Caused Unneeded Load Sheds

System operators in the WECC footprint were too quick to declare energy emergency alerts (EEAs) during several recent events, resulting in unnecessary load sheds on two occasions, according to a new NERC “lessons learned” notice.

The notice detailed five incidents in which software glitches, communication lapses and generator malfunctions contributed to unnecessary EEAs, two of which resulted in the shedding of a combined 250 MW of load.

Donnie Bielak, PJM’s manager of reliability engineering, briefed the RTO’s Operating Committee on the lessons Thursday. “Some of these were actually EEA-3s and result in load shed, so some of the mitigating actions were quite severe,” he said.

One of the load-shed incidents occurred in the evening of a hotter-than-forecast day as solar PV resources were declining, when an unidentified reliability coordinator declared an EEA-1 for a balancing authority at the request of the BA, referred to in the document as “BA 1.” (As is customary, although the notice identified WECC as the source of the lessons, it did not identify the entities involved.) About the same time, two generators totaling 530 MW tripped offline, causing the RC to place BA 1 and a second BA within the same reserve sharing group (RSG) in an EEA-3.

Under EEA-1, the BA seeks to use all available generation to meet firm load, firm transactions and reserve commitments; non-firm wholesale energy sales are curtailed unless they are recallable to meet reserve requirements. Under EEA-3, firm load interruptions are imminent or in progress.

Demand was higher than normal and solar PV output was declining on the last day of this seven-day loading trend, when a reliability coordinator in the WECC footprint declared an EEA-1 at a balancing authority’s request. The alert turned out to be unnecessary, NERC said. | NERC

The RSG’s computer program for requesting contingency reserve assistance from other RSG members requires the system operator to fill out information in a pop-up display. Because BA 1 submitted its request first, the program required BA 2 to acknowledge BA 1’s request before submitting its own. But the system did not credit BA 2 with the assistance it was providing to BA 1 because BA 2 filled out its request before acknowledging the request from BA 1. As a result, the program required BA 2 to provide about 200 MW more generation than was needed for the RSG to recover its reporting area control error (ACE).

“It appeared that they were short and they actually weren’t,” Bielak explained.

In addition, about 60 MW of contingency reserves were not available because a resource failed to start. The combination of events made it appear that BA 2 could not recover its ACE within 15 minutes, prompting a BA 2 system operator to shed 150 MW of firm load.

“What was not known to the system operator at the time was that the two units tripped one minute and six seconds apart, so the resource loss was outside the one-minute threshold of a reportable balancing contingency event, making the requirement to recover the reporting ACE within 15 minutes not applicable per BAL-0024,” NERC said.

In another incident, operators reduced available transfer capability for a major transmission corridor threatened by a wildfire, reducing an RSG’s ability to deliver contingency reserves to some of its member BAs. One of the BAs asked its RC to put it into an EEA, but because the BA was participating in the RSG, the contingency reserves from the zone were sufficient to recover from the largest, most severe single contingency. “After-the-fact review per the RSG and the BA indicated the BA did not need to request an EEA,” NERC said.

In another case, a BA fell short of its required contingency reserves as load was increasing, causing its RC to declare an EEA-3. It was later discovered that the BA was never short generation but that its tool was not reporting all available generation to system operators.

Misreading BAL-002

The second incident that resulted in load shedding occurred when a BA lost generation and asked for reserves from its RSG but fell short of its required generation when some units it requested to help failed to start. To recover the BA’s reporting ACE within 15 minutes, the system operator shed about 100 MW of load.

It was later determined that, because the BA was in an RSG and the amount of lost generation was less than the threshold for a reportable balancing contingency event, the BA did not have to recover their reporting ACE within 15 minutes. Thus, the system operator was not required to shed load under BAL-002.

Several changes resulted from the incidents, including:

weekly start-up tests of units relied on for replacement reserves;
an initiative to develop a new way of determining generation replacement reserves that takes account of factors such as increased outages, market dynamics and variable generation;
development of a new load-forecasting tool, which is being used on a trial basis; and
enhanced operator training on topics, including three-part communication, implementing interruptible loads and responding to data integrity issues.

Changes also resulted from a fifth incident, when a 300-MW resource was lost in the evening as solar resources were dropping, causing the BA to fall below its required levels and triggering an EEA-3. The incident resulted in the introduction to the day-ahead load forecast of a “high confidence” band — assuring load will come within the high and low ranges of the forecast. It also caused the entity to increase its coordination with its thermal generators to ensure units are positioned in their fastest ramp rate ranges before the start of the evening solar ramp.

NERC said the incidents indicated that BAs participating in an RSG need to understand when they are acting as a member of the RSG or as an independent BA. “BAs in [two cases] dropped load per their individual limits but not per their RSG obligations,” NERC said. “They were focusing on recovering their individual ACE.”

It said BAs participating in an RSG should provide periodic refresher training to their system operators on the applicability of BAL-002 and procedures to determine when they are and are not considered an active member of the RSG.

It also said RSGs should validate their programs for multiple contingency reserve activations to ensure their computer programs do not miss prior reserve activations. “BAs should have a process to validate that all available reserves are accounted for and properly displayed for the BA system operators to be aware of in case they need to be called upon,” NERC said.

Wind Generation Cutoffs During Cold Weather

The Midwest Reliability Organization was the source of a second lessons learned report that NERC said highlighted the need to ensure grid operators know whether wind turbines in their footprints can operate in extreme cold. [Editor’s Note: An earlier version of this article mistakenly attributed the lesson to WECC.]

The report stemmed from extreme cold weather on Jan. 29-31, 2019, when unplanned wind generation outages triggered a maximum generation event, resulting in a registered entity calling on demand response, behind-the-meter generation and voluntary reductions to avoid emergency power purchases.

Actual overnight temperatures for the period were a few degrees lower than forecasted, and when temperatures fell below -21 degrees Fahrenheit, some wind farms shut down their turbines to avoid damage to their gear boxes.

On Jan. 30, the temperature was 4 degrees lower than expected and wind output was 6 GW below the day-ahead forecast, a 50% shortfall. Fears of insufficient generation to meet the morning peak resulted in the maximum generation event.

A registered entity in WECC had forecast 8.5 GW of wind generation for its morning peak on Jan. 30, 2019. But temperatures below -21 F forced the shut down or derates of 98 of 216 wind generators, leaving the entity with only 4 GW of wind for the peak load hour. | NERC

The entity had expected 8.5 GW of wind generation in its unit commitment for the Jan. 30 peak, which reflected a 1-GW reduction because of unit cutoffs from cold temperatures. But 98 of 216 wind generators had to be derated or shut down, leaving the entity with only about 4 GW of wind for the peak load hour. The units that continued to operate had heating sources in the gearbox to prevent the oil from freezing, allowing them to operate at -40 F.

The entity’s deployment of load management resources, along with school and business closings, reduced demand by at least 3 GW, allowing it to avoid emergency power purchases.

“Wind unit owners should prepare for extreme cold-weather performance and promptly communicate anticipated operating parameters and data to their BA, RC and [transmission operator] to ensure readiness and provide situational awareness in both operations and planning,” NERC said.

July 12, 2020

RI Seeks to Lead with 100% Renewable Goal

Rhode Island may meet its goal of using 100% renewable electricity by 2030, but that doesn’t mean the rest of New England can do the same.

So heard more than 150 people Thursday at a virtual public meeting on how the state’s Office of Energy Resources (OER) is working with the Brattle Group to develop a plan by year-end to achieve a 100% clean grid by the end of the decade.

“The two most significant barriers to accelerated renewable growth are the following: One is sustainability and affordability from a consumer perspective,” OER Commissioner Nicholas Ucci said. “The other major challenge is sustainable siting.”

The state, which had 95 MW of clean energy in 2016, has increased its share almost tenfold to 920 MW as of the first quarter of 2020, Ucci said.

Rhode Island renewables — Brattle Group preliminary analysis shows Rhode Island will have a gap of 4,300 GWh in clean power production a decade from now. | *The Brattle Group*

The OER is conducting a study that should be released in December that looks at opportunities for solar development on greyfields and brownfields, landfills and carports, all to ease the burden of siting for developers, he said.

The state is also looking forward to the 400-MW Revolution Wind offshore wind project, which will supply 25% of its electricity when it goes online in a few years, Ucci said.

Nicole Verdi, deputy chief of staff to Gov. Gina Raimondo, referred to climate change as a threat to the very existence of the low-lying Ocean State.

“Rhode Island is warming at the fastest rate of any state in the continental U.S.,” Verdi said. “Our sea levels rise faster each year, and we are rapidly approaching the point of no return.”

If the status quo persists, sea levels could rise as much as 10 feet by the end of this century, she said.

“Let me paint a picture of how disastrous this could be. A 10-foot rise in our sea level would turn Little Compton, Portsmouth and Tiverton into a chain of small islands,” Verdi said. “A 5-foot rise would give the state house a moat.”

Decarbonize Everything

Raimondo signed an executive order in January committing the state to be powered by 100% renewable electricity by the end of the decade and directing the OER to conduct economic and energy market analyses in order to develop workable policies and programs.

“This is a very aggressive goal, more so than any other U.S. states have put in place,” said Brattle principal Dean Murphy in opening the day’s presentation. “Achieving 100% renewable electricity by 2030 is the focus of this study, but it’s important to keep in context that the 100-by-30 goal is really just one step toward the larger and longer-term economy-wide goal of 80% reduction in greenhouse gas emissions by 2050.”

Brattle last month delivered a similar study to ‘Astonishing’ Buildout Needed for Clean NY Grid.)

Electrifying most heating uses and most transportation would roughly double the demand for electricity over the next few decades, “and of course, you haven’t decarbonized the heating or transportation sector unless you’ve also decarbonized electricity,” Murphy said. “That gives a sense of why decarbonizing electricity is important: first to get the carbon out of the existing electricity sector, and then to provide carbon-free generation to power other sectors as a way of decarbonizing those.”

Daniel Collins, director of government affairs at the New England Power Generators Association, asked whether the study will consider carbon pricing as a potential solution to meet the 2030 goal and beyond. “The executive order mentions leveraging market competition, which would presumably make carbon pricing a viable policy option,” he said in a written question. “I also note that OER is conducting a separate study on carbon pricing, albeit with a different consultant.”

“As you note, carbon pricing is being studied elsewhere,” Ucci responded. “However, OER will consider the lessons learned through both studies and integrate where appropriate. Indirectly, any future carbon pricing scheme could produce revenues that might ultimately be invested in new clean energy resources, e.g. local solar, energy efficiency, etc. That type of outcome, if it came to pass, would be consistent with our analytical framework here.”

Cadmus Group and Synapse Energy Economics delivered a preliminary assessment on their carbon pricing study for OER in May and expect to issue a proposed mechanism for carbon pricing by the end of this summer.

Encouraging Renewables

Murphy said the report’s “‘gap’ refers to the amount of additional renewables that you’d need by 2030 to meet 100%, additional beyond where we are now, beyond the commitments that have already been made. We are not identifying those mechanisms by which additional renewables could be procured or provided to get to 100%.”

National Grid, the state’s main utility, reported at a seminar last month on its decarbonization efforts. (See NE Utilities Lay out Strategies for Net-zero Emissions.)

The utility’s Renewable Energy Growth (REG) program supports the development of distributed generation projects with wind, solar, hydropower and anaerobic digestion — and has a separate program for homeowners and small business operators installing facilities 25 kW and smaller.

In addition, the state runs its own solar marketplace to help residents install solar panels on their property.

Rhode Island can lead New England by example, said Jürgen Weiss, another principal with Brattle.

“The climate leadership role could be making sure Rhode Island helps push down greenhouse gas emissions as much as possible to avoid the worst consequences of climate change,” Weiss said.

Another more narrow goal is to make sure that the policies that get implemented lead to the decarbonization of the power sector, which seems obvious, but there are factors that need to be considered to ensure the outcome, he said.

“Any policies implemented should lead to additional greenhouse gas emission reductions in the power sector — reductions that would not have occurred absent the policies,” Weiss said.

He said state policies may not result in additional GHG emissions reductions if compliance happens through an alternative compliance agreement, or “out clause.”

Theoretically, the trade of renewable energy credits and certificates could lead to emissions reductions in Texas, but not in Rhode Island, so policymakers should be aware of all the details, Weiss said.

Another policy consideration is to make sure that 100% of load is counted, “which is easier said than done, for not all demand for electricity in Rhode Island is metered, such as a diesel generator in the backyard that’s only used for emergencies,” Weiss said.

An industrial facility might have its own generator, the most typical example being a combined heat and power plant, so decarbonizing 100% means capturing all the elements, he said.

Especially after 2030, moving to electrify transportation, heating and cooling will not get the region to net-zero emissions unless the power sector continues to decarbonize, Weiss said.

A renewable energy standard “is a good starting point, but it’s not enough. … We need additional resources,” he said.

July 12, 2020

Community Shared Solar Grows in NYC

New York continues to be a pioneer in expanding access to community solar for low- and moderate-income people, and the New York City Housing Authority (NYCHA) is a powerful agent in that effort, with more clients than the population of most U.S. cities.

NYCHA has a commercial solar program and a residential one, the ACCESSolar program, which aim to install 25 MW of renewable energy on its properties by 2025, generally at less than 40 kW per building, Chris White, an associate with the housing authority’s capital projects/sustainability program, told more than 100 people Thursday in a virtual meeting hosted by Sustainable CUNY at the City University of New York.

The housing authority completed its first round of solicitations last year, with the pandemic greatly disrupting the progress so far in 2020, he said.

“Right now, we’re trying to work through COVID, wrap up some lease agreements and get our first projects constructed. We’re hoping that our first solar panels will be in construction in the next couple of months … and hopeful that we’re going to have our next round of solar opportunities probably around the end of this year,” White said.

The solar program aims to generate revenue, use underutilized spaces, provide job training and green jobs for residents, and reduce energy costs for those who live in NYCHA housing, Section 8 voucher holders and other low- and moderate-income people across the city, White said.

Community Shared Solar — Amount of solar capacity (MW) installed in New York City per year | *CUNY*

The housing authority serves about 400,000 people in 176,000 apartments and another 200,000 people through its voucher program, the largest numbers of any city in the country, and gets special reduced electricity rates from the New York Power Authority, he said. (See New York City Ramps Up Community Solar.)

Ron Reisman, NYC solar partnership manager for Sustainable CUNY, said the organization has been supporting NYCHA’s program from the beginning three years ago with technical assistance, assessments, proposal evaluations and other services.

Sustainable CUNY developed the New York solar map and portal, which includes a calculator to help residents find the solar potential of their homes or businesses. It includes links to resources on permitting, interconnections, zoning, financing and other topics related to solar and storage, Reisman said. The organization supports both renewable energy development on the university’s campus properties and for New York’s distributed generation framework, he said.

Sharing Benefits

“Supporting the NYCHA initiative is part of our overall mission to expand the deployment of solar in New York City, and energy storage as well, in a way that all New Yorkers can take advantage of energy, environmental and economic benefits,” Reisman said.

The National Renewable Energy Laboratory’s webpage on low- and moderate-income solar policy basics notes that community solar is attractive to many regardless of income, because shading and inadequate roof conditions make solar unsuitable for nearly three-quarters of the residential rooftops in the U.S.

The lab says several jurisdictions have begun exploring community solar to expand solar access to low- and moderate-income communities, and mentions New York as one of four states — California, Colorado and Oregon are the others — that have enacted low-income carve-outs as part of their community solar policies.

The New York Public Service Commission’s 2015 order establishing net metering gave special consideration to projects that promised 20% participation by low-income people (15-E-0082).

“We’re very excited about the work we’re doing installing solar at the [NYCHA’s] Carver Houses,” said Charles Callaway of WE ACT for Environmental Justice, who also has a seat on the state’s 22-member Climate Action Council. “If we weren’t in this pandemic of COVID-19, we’d probably be in the buildings.”

His organization is looking to recruit a couple buildings in East Harlem into the solar program and working to get residents the cost estimates needed to move forward on installing solar panels.

“Getting people the information they need to sign up for community solar is very important,” Callaway said. “We’ve tried a couple of strategies around just doing street outreach.”

Callaway reported some low-income people being fearful of innovative clean energy programs after having been “scammed” by unethical energy service companies, a practice that the PSC has cracked down on repeatedly in recent years. (See NYPSC Reins in ESCOs, Expands Community DG.)

The mayor’s office works with Sustainable CUNY and the NYC Economic Development Corporation to expand access to the benefits of solar energy and other forms of renewable energy. Programs include Solarize NYC — for community group purchasing — and a related program called Shared Solar NYC.

Juan Parra, community solar program manager with Solar One, an environmental education nonprofit in the city, said his organization is involved in two active projects now: a 685-kW project in Sunset Park, on the roof of the Brooklyn Army Terminal, and NYCHA’s ACCESSolar.

“We’re implementing workforce training opportunities, so we’re not just training folks in solar installation skills, but actually making commitments with the installer to hire them as part of the solar installations for these projects,” Parra said. “We’re excited that training is going to start next week.”

Daphany Sanchez of Kinetic Communities Consulting worked with NYCHA on the solar project and said the housing authority is working in Harlem to learn how to scale community solar for small businesses and local nonprofits.

“Community-based organizations have done outreach in the past, so when we talk about community solar outreach, the concerns are around how do we ensure these are truly low- and moderate-income people, how do we capture that information, when in reality such organizations” have secured the same personal information for housing, health and education, Sanchez said. “It is not new.”

July 12, 2020

ERCOT Briefs: Week of July 6, 2020

ERCOT said last week that its corporate members have approved the elections of two unaffiliated directors, the re-election of a third unaffiliated director and amendments to the grid operator’s amended and restated bylaws.

Staff conducted a ballot vote “to resolve the items” before a scheduled Friday special meeting of corporate or voting members. They received enough votes to pass each of the four motions on July 2 and canceled the special meeting.

ERCOT plans to file the three director nominations for approval with the Texas Public Utility Commission this week. It expects approval in early November.

The Board of Directors in June approved Michigan Public Service Commission Chair Sally Talberg and retired ERCOT Board of Directors Briefs: June 9, 2020.)

Board Chair Craven Crowell, Vice Chair Judy Walsh and Director Karl Pfirrmann all roll off the board when their terms expire at the end of this year.

ERCOT has already filed the bylaw amendments with the PUC for its expedited approval (50918). That should come by July 31, according to the docket’s procedural schedule. The amendments address the need and processes for teleconference meetings under social-distancing requirements related to the COVID-19 pandemic.

Demand, Temps on the Rise

June’s peak demand in ERCOT’s footprint came within 116 MW of last June’s peak, a sign that consumer demand and summer heat are nearing normal levels. The grid operator recorded a peak demand of 68,043 MW during the hour ending at 6 p.m. on June 8. Peak demand last June was 68,159 MW.

Gas-fired resources accounted for 40.9% of the energy produced during the month, with wind energy responsible for 23.34%. Coal resources provided 16.6% of ERCOT’s energy in June.

The grid operator was expecting a potential new weekend peak demand and a new all-time peak on Monday, July 13. ERCOT set a new all-time peak of 74.8 GW last year and has predicted a new mark of 75.2 GW this year, almost 1.5 GW less than staff predicted before Texas began locking down in March.

A heat wave continues to bake the Southwest and has brought triple-digit temperatures to much of Texas.

July 12, 2020

Monitor Says MISO Needs Higher Reserve Margin

MISO’s Independent Market Monitor said the RTO would be better served by an even higher planning reserve margin, two days after it recorded its first emergency of the summer.

Monitor David Patton said the grid operator should be using a 20% planning reserve margin requirement instead of the current 18% requirement that was in place when it called a maximum generation event on July 7. MISO’s planning reserve margin has climbed steadily in recent years; in 2017, it was just under 16%.

Speaking during a Market Subcommittee teleconference Thursday, Patton said part of the problem is MISO does not assume that planned generation outages and derates occur in the summer months.

But MISO is wrong there, he said.

Had it accounted for historical planned and unreported summertime outages, MISO would find its 18% margin requirement would look more like 11%, Patton said. If the RTO only included load-modifying resources that have lead times of two hours or less, that margin would fall to 8%, he said.

MISO currently allows LMRs with lead times as long as 12 hours to participate in its capacity market. The RTO recently filed with MISO Offers Concession on LMR Capacity Credit Plan.)

Patton said he would be “comfortable significantly reducing LMR accreditation to a two-hour” notification time. He said LMRs with six-hour notification needs provide “almost no reliability value” and wondered why they were being treated comparably with more valuable resources.

“It is the case that MISO has made improvements to notify LMRs to be ready ahead of time. And that’s good. But it’s still the case that MISO cannot see emergencies that far in advance,” he said.

Patton said excluding planned outages from reserve margin planning and accrediting long-lead LMRs contributes to the footprint’s tight conditions.

“We’re not as adequate as we think we are,” he said. “I think we’re adequate for this summer, but improving how we accredit capacity and price shortages will be increasingly important.”

Patton also said MISO needs higher pricing during shortages, especially as more intermittent resources are introduced into the resource mix.

“I’m not sure that we need new [market] products as much as we need really good shortage pricing,” he said.

Another Emergency Declaration

The Monitor’s recommendations were delivered as much of MISO Midwest was gripped by a persistent heat wave.

The high temperatures prompted MISO to issue a maximum generation emergency about 1-5:30 p.m. July 7 for its Northern and Central regions.

MISO reserve margin — MISO real-time prices at 3 p.m. ET July 9 | *MISO*

LMPs at the Michigan hub exceeded $400/MWh on July 7 and neared $700/MWh around 3 p.m. Thursday. MISO’s peak load topped out at just over 114 GW on Thursday. The RTO had planned for a 120-GW peak that day.

MISO first issued a hot-weather alert and capacity advisory on July 1 and a conservative operations declaration beginning July 6. Conservative operations — where MISO requests that all transmission and generation outages be put on hold, if possible — were in effect through Friday.

MISO imported capacity from PJM during the July 7 emergency, even as the PJM region was also experiencing stifling heat.

Patton said MISO is mostly saved from capacity deficiencies during hotter-than-normal weather combined with low wind output by its “substantial” import capability from its footprint’s neighbors. He said imports are “utilized to avoid shortages in all the hottest conditions.”

He also reminded stakeholders that MISO still has a “theoretically flawed” capacity market where demand doesn’t set capacity’s reliability value. MISO’s vertical demand curve causes resources to prematurely retire, he said.

Patton also noted that MISO had several warm days with air conditioning demand in March and April. He said spring load would have been slightly higher than average but for the languishing demand introduced by COVID-19 pandemic-related lockdowns.

MISO executives said they will prepare data on and a review of the July 7 emergency event for the Reliability Subcommittee meeting July 30.

July 12, 2020

MISO Market Platform Replacement Project up $20M

MISO’s market platform upgrade project is $20 million over budget as staff and vendors navigate the intricacies of replacing a decades-old system and pandemic-related supply chain issues.

The project’s costs have risen to nearly $160 million, up from the $140 million projected last year. MISO Executive Director of Digital Strategy Jeff Bladen said the increase is largely because of the complexities of swapping out system components that couldn’t be foreseen two years ago.

Speaking during Thursday’s Market Subcommittee meeting, Bladen also said implementing MISO’s new private cloud server was held up by the ongoing coronavirus pandemic’s interruptions of the supply chain. The new private cloud will house the modular platform, replacing the current server-based platform. (See Test Phase Approaches for MISO Market Platform.)

MISO Market Platform Replacement — Jeff Bladen, MISO | © *RTO Insider*

“We are moving ahead,” Bladen said. “We have been impacted by that to some degree in the buildout of the private cloud.”

Bladen said the private cloud will probably be online later this month, a month later than the RTO anticipated pre-pandemic.

MISO Director Baljit Dail said that even with the cost increase of the project, the cost-benefit is “still significant.”

“I think it’s important to remember that the legacy system was installed in 2009. It’s over a decade old,” Dail said at MISO’s June board meeting. He said staff stretched the original platform as far as they could, adding software and market products to keep up with a changing grid.

Bladen said the existing system’s architecture was originally designed for PJM in the mid-1990s.

MISO is replacing the platform gradually, turning off core elements of the old system one at a time and replacing them with new microservers. The day-ahead market is set to go live on the new platform in 2023.

“We’ve started down this path in earnest, with actual coding as we speak,” Bladen told stakeholders.

The old market platform will be completely retired in 2026. However, the bulk of the replacement will be complete by late 2024, Bladen said. The real-time market will likely go live on the new platform in early 2025.

Additionally, the new market participant interface test environment has been open since April and will be until June 2021. Parallel operations of the new and old interfaces will take place July-October 2021.

“We have seen some traffic and activity, but several companies have not tested it yet,” MISO Senior IT Director Curtis Reister said.