Page 1077 – RTO Insider

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.

July 11, 2020

FERC Storage Order Survives State Challenge

Energy storage advocates scored a key victory Friday when the D.C. Circuit Court of Appeals rejected challenges to FERC rules that restrict states from prohibiting behind-the-meter storage resources from participating in organized wholesale electricity markets.

State regulators, utilities and public power groups last year petitioned the court to overturn the provisions of FERC Order 841 that require states to provide energy storage resources (ESRs) connected to distribution systems full access to federally regulated energy markets, calling the rules “arbitrary and capricious” and “not in accordance with law.” (See States, Public Power Challenge FERC Storage Rule.)

The National Association of Regulatory Utility Commissioners spearheaded the challenge, with the Edison Electric Institute, the American Public Power Association, the National Rural Electric Cooperative Association and American Municipal Power filing a separate complaint.

FERC energy storage — AES battery storage | *AES*

The D.C. Circuit’s decision was unsurprising given the three-judge panel’s evident skepticism about the petitioners’ arguments during a May proceeding. (See DC Circuit Skeptical of NARUC Challenge to FERC Order 841.)

“Petitioners argue FERC is offsides in Order No. 841 by prohibiting states from barring electric storage resources on their distribution and retail systems from participating in federal markets. We find no foul here, so we deny the petitions,” Judge Robert Wilkins wrote on behalf of the panel.

In Order 841-A, FERC denied rehearing of Order 841’s express lack of a state opt-out for behind-the-meter retail ESRs, arguing that its authority to regulate RTO/ISO markets gave it “authority to determine which resources are eligible to participate” in those markets.

In its arguments before the court, Wilkins noted, “FERC emphasized, again, that Order No. 841 did ‘not specify any terms of sale at retail,’ but a state may not ‘broadly prohibit all retail customers from participating in RTO/ISO markets,’ since states cannot … intrude on the commission’s jurisdiction by prohibiting all consumers from selling into the wholesale market.’”

The court agreed with FERC’s contention that “Order No. 841 does not modify states’ authority to regulate the distribution system, including the terms of access, provided that they do not aim directly at the RTO/ISO markets.”

“Order No. 841 solely targets the manner in which an ESR may participate in wholesale markets,” the court wrote. “This action is intentionally designed to increase wholesale competition, thereby reducing wholesale rates. Keeping the gates open to all types of ESRs — regardless of their interconnection points in the electric energy systems — ensures that technological advances in energy storage are fully realized in the marketplace, and efficient energy storage leads to greater competition, thereby reducing wholesale rates.”

Even NARUC acknowledged the potential benefits from local ESRs participating in wholesale markets, the court said.

“If ‘directly affecting’ wholesale rates were a target, this program hits the bullseye,” the court wrote.

In rejecting the petitioners’ complaints that the lack of an opt-out provision violates states’ authority to regulate their distribution systems, the court acknowledged “there is little doubt that favorable participation models will lure local ESRs to the federal marketplace,” requiring use of those systems. Still, “nothing in Order No. 841 directly regulates those distribution systems. … States remain equipped with every tool they possessed prior to Order No. 841 to manage their facilities and systems,” the court said.

“But because FERC has the exclusive authority to determine who may participate in the wholesale markets, the Supremacy Clause — not Order No. 841 — requires that states not interfere” with those markets, the court found.

In that vein, the court rebuffed NARUC’s contention that local ESRs cannot participate in federally regulated wholesale markets — and therefore do not fall under FERC’s authority — until they can navigate state-regulated facilities.

“Any state effort that aims directly at destroying FERC’s jurisdiction by ‘necessarily deal[ing] with matters which directly affect the ability of the [commission] to regulate comprehensively and effectively’ over that which it has exclusive jurisdiction ‘invalidly invade[s] the federal agency’s exclusive domain,’” the court said, citing precedent from 1962’s Northern Natural Gas Company decision.

The court also pointed out that under Order 841, states keep their authority to prohibit ESRs from simultaneously participating in interstate and intrastate markets.

“States retain their authority to impose safety and reliability requirements without interference from FERC, and ESRs must still obtain all requisite permits, agreements and other documentation necessary to participate in federal wholesale markets, all of which may lawfully hinder FERC’s goal of making the federal markets more friendly to local ESRs,” the court said.

The court additionally acknowledged that individual states will be free to challenge the rules “applied to their own state regulations or imposed conditions.”

“Petitioners are likely correct that litigation will follow as States try to navigate this line, but such is the nature of facial challenges,” the court wrote.

Renewable energy and storage advocates applauded the decision.

“This is an enormous step for energy storage, with the affirmation that energy storage connected at the distribution level must have the option to access wholesale markets, allowing homes and businesses to contribute to the resiliency, efficiency, sustainability and affordability of the grid,” Energy Storage Association CEO Kelly Speakes-Backman said in a statement. “This latest affirmation of Order 841 is especially important as it ensures energy storage can contribute all its values to the grid, regardless of its connection point. As our electric system becomes more modernized and distributed, we are seeing the regulatory frameworks at both the wholesale and retail levels adjust to that reality.”

“During a time of great uncertainty over the scope of the Federal Power Act, today the court rightfully recognized the important role energy storage plays in our nation’s wholesale electricity markets,” American Council on Renewable Energy CEO Gregory Wetstone said in a statement. “This decision will provide the clarity necessary to widely deploy energy storage, an essential component to securing the carbon-free grid we need to properly combat the climate crisis.”

FERC Chair Neil Chatterjee also expressed pleasure with the ruling, saying the removal of market barriers for storage has been one of his “top priorities.”

“I have said repeatedly that I think … we may look down the road and say [Order 841] was one of the single most significant … actions taken by a government agency to address carbon mitigation and the transition to a clean energy future. And so, if in fact our initial read of this decision is correct, this is a very significant victory indeed,” Chatterjee said.

Plaintiffs in the case were expectedly dissatisfied with the outcome.

“We are, of course, disappointed in the court’s decision,” said NARUC Director of Communications and Public Affairs Regina Davis. “We are still reviewing the opinion and weighing our options at this time. We may issue a formal statement next week after we’ve had time to review today’s decision.”

“We believe that the jurisdiction over local distribution facilities left to state and local authorities under the Federal Power Act includes the authority to determine whether those facilities may be used by electric storage resources to access FERC-regulated wholesale markets,” said APPA General Counsel Delia Patterson. “Although APPA is encouraged that the court emphasizes that state and local regulators retain authority to impose safety, reliability, and other requirements on storage resources’ use of the distribution system to access wholesale markets, the inability to adopt a clear prohibition on such use is likely to lead to further litigation over particular state and local requirements, as the court acknowledges.”

July 10, 2020February 19, 2025

Pa. House Passes Bill Limiting RGGI Entry

The Pennsylvania House of Representatives voted Wednesday to pass a bill limiting the state’s entry into the Regional Greenhouse Gas Initiative (RGGI), but experts expect the state will ultimately enter the environmental compact despite concerns from legislators.

House Bill 2025 passed by a bipartisan majority of 130-71. It would require the legislature’s approval before Pennsylvania can enter any multistate program like RGGI that imposes taxes. The Department of Environmental Protection would need to submit “a description of the economic and fiscal impacts that would result” from joining such a program to aid the legislature in its decision.

The bill would also require legislative authorization before the state can impose a carbon tax on employers engaged in electric generation, manufacturing or other industries.

Gov. Tom Wolf signed an executive order in October directing the DEP to develop a rulemaking for joining RGGI by July 31; citing the pandemic, Wolf provided the department with a six-week extension, to Sept. 15. His authority to issue such an order has been continually challenged by the Republican-controlled legislature. (See GOP Continues Opposition to Pa. RGGI Plans.)

Rep. Jim Struzzi speaks June 8 before the vote on his bill limiting Pennsylvania’s entry into the Regional Greenhouse Gas Initiative. | Pa. House

“This bill gives a voice back to the people by allowing those of us who represent them to have say in this process,” Rep. Jim Struzzi, the bill’s primary sponsor, said during Wednesday’s House session and vote. “The action to enter RGGI would have serious ramifications on Pennsylvania businesses, jobs, energy prices and future economic opportunities that are not being considered by the governor.”

RGGI, which includes New York and the six New England states, currently has three PJM states: Delaware, Maryland and New Jersey. On Wednesday, Virginia Gov. Ralph Northam announced that the state had finalized a rule in preparation for it joining the compact on Jan. 1. (See PJM Panel Weighs Impact of Pa., Va. Joining RGGI.)

The bill now goes before the State Senate for consideration, with sessions scheduled for July 13 and 14. The body may take up the House bill or consider its companion bill, Senate Bill 950, which currently has 20 Republican sponsors, representing 40% of the 50-seat chamber.

During Wednesday’s session, House Majority Leader Kerry Benninghoff (R) said that of the nine states that have already entered into RGGI, all of them voted to join through votes in their respective legislatures. Benninghoff also called RGGI a “job killing” measure that will drive high-paying jobs out of Pennsylvania and into Ohio and West Virginia, the state’s two neighbors that are neither part of nor considering joining the compact.

“No governor has the authority to rule by the swipe of a pen without the input or the consent of the people of Pennsylvania,” Benninghoff said. “No governor has the authority to implement a tax, and no governor has the authority to enter into a binding compact or agreement. That authority lies with the people of Pennsylvania and the members of this chamber sent by the people.”

Rep. Leanne Krueger (D), a supporter of RGGI, said H.B. 2025 was an attempt to downplay the significance of reducing carbon dioxide emissions in Pennsylvania and at the same time scare people into thinking the actions of joining the group will harm them financially.

“Joining RGGI is the biggest climate action that Pennsylvania will have ever taken, the biggest environmental action certainly of my generation,” Krueger said in comments after the bill passed. “And yet we’re facing a bill that would stop the governor in his tracks and not allow us to join this common-sense” market.

Outside View

Despite Wednesday’s vote, outside observers said Pennsylvania still stands a strong chance of joining RGGI.

ClearView Energy Partners predicted in a report that Wolf is guaranteed to veto any bills passed by the legislature overriding his executive order. And although Wednesday’s bill passed with bipartisan support, ClearView said there most likely won’t be enough votes to overcome a veto.

ClearView said legislators may rely on a strategy of inserting H.B. 2025 language into November’s budget, forcing Wolf to take a stand on budget debates. However, it pointed out Wolf has line-item veto authority over the budget and has used his power before to reject abortion language inserted in last year’s budget.

Another possible Republican strategy, according to ClearView, is a legal challenge, as legislators have argued that Wolf’s executive order did not cite specific provisions within the Pennsylvania Air Pollution Control Act, which does not describe CO2 as a “pollutant.”

July 10, 2020February 12, 2025

Coal Org Pushes Back on Self-Commit Study

Coal trade organization America’s Power has countered a recent Union of Concerned Scientists analysis that claimed coal generation self-commitments are unnecessarily costing Midwestern ratepayers millions.

The group, formerly known as the American Coalition for Clean Coal Electricity, said that far from conducting uneconomic behavior, MISO’s coal units closely follow energy demand. The group said that in 2018, changes in electricity demand and coal generation output correlated about 87% of the time, regardless of utility or whether MISO issued dispatch instructions. It also said the percentage was the same as natural-gas fired generation in the footprint.

“Not only are coal-fired generating units run economically, they are run according to market demand as much any other type of generation in MISO,” America’s Power said in its rebuttal, released June 25 and titled “Never Let the Truth Get in the Way of a Good Story.”

“Self-committing coal-fired power plants is not a trick to rip off ratepayers,” it said. “Rather, it benefits ratepayers and helps maintain the reliability of the electricity grid.”

UCS’ June analysis concluded that coal plant self-commitments saddled Midwest electricity customers with $350 million in avoidable costs in 2018. The study also said individual ratepayers could have saved an average $60 apiece over the year if the most efficient existing resources in MISO were deployed instead of coal plant self-scheduling. UCS used the study to make a case for state regulators to open investigatory dockets into utilities that exhibit high costs. (See UCS Analysis Knocks Coal Self-commitments.)

| America’s Power

MISO has said about 90% of energy from its coal is either from economic commitments or economically dispatched above the units’ economic minimum levels.

“Some claim that self-commitment of coal-fired resources results in prolonged run times and uneconomic outcomes for end-use customers,” MISO said in an April report. “Further, they say self-commitment distorts the markets by allowing coal units to displace lower-cost renewables and other resources from the grid. In fact, the vast majority of all self-committed coal generation in MISO is actually dispatched economically — meaning it is the lowest-cost resource option that MISO markets have available at the time to serve load.”

MISO Executive Director of Market Operations Shawn McFarlane said most self-committed, coal-fired energy is dispatched economically.

“We try to minimize any uneconomic dispatch … taking into account operational constraints,” McFarlane said during the Market Subcommittee meeting in May.

Monitor to Weigh in

On Thursday, MISO’s Independent Market Monitor David Patton told the MSC that he will publish his own report on coal self-commitments next month, but he doesn’t anticipate alerting staff and stakeholders to a problem.

Coal resources that offer in the day-ahead market as must-run are overwhelmingly offered economically, Patton said. He said 98% of available offline coal units offered economically in the day-ahead market this spring, up from 89% last year.

“As gas prices fall, it’s becoming harder to predict when it will be economic for coal resources to run,” Patton said. Offering in must-run status prevent the units from incurring expensive cycling costs when they’re decommitted and brought back online later, he said.