About 10,000 central Michigan residents have been forced to evacuate their homes after a small hydroelectric dam beset by safety violations failed under heavy rainfall this week.
An earthen embankment at the 4.8-MW Edenville Dam in Midland County collapsed Tuesday, followed hours later by an overrun of the nearby Sanford Dam, flooding the surrounding area in up to 9 feet of water and prompting an emergency declaration by Gov. Gretchen Whitmer.
“If you have not evacuated the area, do so now and get somewhere safe,” Whitmer said Tuesday. “This is unlike anything we’ve seen in Midland County.”
Michigan had previously rated Edenville in unsatisfactory condition, while Sandford received a fair rating. Both dams are about 95 years old and in the process of being sold.
FERC in 2018 revoked owner Boyce Hydro’s hydropower license to operate Edenville, located between Wixom Lake and the Tittabawassee River, citing concerns about the dam not being able to handle floods.
Edenville Dam
Violations included failing to increase spillway capacity to address the increased likelihood of more frequent flooding; performing unauthorized dam repairs and excavation; neglecting to file a public safety plan or follow its own water monitoring plan; failing to acquire all property rights; and failing to construct required recreation facilities near the dam. The commission has spent about 15 years trying to get Boyce, which has owned the dam since 2004, to increase spillway capacity, the most serious of the safety violations.
The Office of Energy Projects’ Division of Dam Safety and Inspections “has determined that the failure of the project dam could result in the loss of human life and the destruction of property and infrastructure,” FERC warned in 2018.
FERC also said Boyce’s unexecuted plan to repair the spillways and use the temporary installation of a cofferdam for four to six months would “reduce the spillway capacity by approximately 50%, increasing the potential for overtopping of the dam.”
MISO will not open its doors to stakeholders or other visitors for at least the rest of the year as the coronavirus pandemic runs its course, the RTO said Tuesday.
All remaining stakeholder meetings in 2020 will be held via teleconference, MISO Vice President of Strategy and Business Development Wayne Schug said during an Informational Forum.
The decision represents yet another — and more drastic — extension of MISO’s COVID-19 response measures of holding virtual stakeholder meetings and restricting access to control rooms, policies the RTO last month had extended to June 1. (See MISO Extends COVID-19 Measures.)
MISO is also contemplating what timeline and safety precautions to follow before allowing select employees to physically return to its three office locations.
“We’re developing contingency plans,” CEO John Bear said, adding that MISO is seeking stakeholder input on a staged reopening in 2021.
“We’re looking to allow more staff to return to the office at least on a periodic basis. We’re trying to balance work from home with our business interests and with our staff’s personal needs,” Schug said, noting that MISO expects some employees will have difficulty lining up childcare or have family members that are more susceptible to the disease.
Schug said MISO continues to work with epidemiologists to bring some employees back in a “safe and predictable manner.” He also said it may consider holding some off-site in-person meetings later this year.
“Having said that, we understand the pandemic is a very dynamic situation,” Shug said, adding that MISO would adjust dates and virtual meeting setups as necessary.
Schug said MISO will ask stakeholders during a June 17 Advisory Committee meeting for advice based on how their companies are navigating staged reopenings and deciding when to welcome visitors back into their offices. The AC meeting is part of the Board Week that was originally slated to take place June 16-18 in Milwaukee. Those meetings will now be spread out in virtual format over June 10-18 to keep the meeting schedule more manageable.
“Based on what we’re hearing from you — and the world around us — our September meeting will likely be virtual, with a hope we can meet up in Orlando in December,” Bear said.
MISO’s quarterly Board Week in September was scheduled to be held in St. Paul, Minn.
MISO Executive Director Real-Time Operations Rob Benbow said no essential MISO control room personnel have tested positive for the virus to date.
“The control room staff have been doing a good job of isolating themselves … and maintaining that physical distance at work and at home,” Benbow said.
Kevin Murray of the Coalition of MISO Transmission Customers asked how often the RTO orders virus testing and whether it has had difficulties securing tests for its employees.
Benbow said essential employees so far are only tested off-site if they experience symptoms. Operators are responsible for reporting any symptoms and isolating at home until they’ve been tested.
“We require them to have two negative tests before they return to work, so we’ve had about four to five operators go through this process,” Benbow said.
In the meantime, Bear said MISO’s virtual stakeholder meetings have been going smoothly.
“I think we’re going to have some wonderful productivity and efficiencies out of this that can help reduce our costs,” Bear said.
Schug said energy and demand in the footprint is currently trending down about 11% compared to usual spring consumption.
“We anticipate that as stay-at-home orders are lifted and things return to more normal patterns, those numbers will trend back up, but it’s too hard to tell because those orders have just started to be lifted,” Schug said.
MISO has reported that load has been about 10% below average because of the pandemic for about a month. Executives said that as some business reopen, they expect surges in load.
By April 6, 11 of the 15 MISO states were under a stay-at-home order. By the end of the month, three states ended their orders, with the remaining set to expire before the end of this month.
Benbow said MISO has been calculating what load would look like without the pandemic’s effects to prepare itself for a return to more normal load.
However, April’s below-normal temperatures and shelter-in-place directives cut peak load by 10 GW — to 73 GW —compared with the same period last year.
Real-time prices fell more sharply, with LMPs averaging $18/MWh compared with $26/MWh last April.
Benbow said natural gas prices in particular have been battered by the pandemic, with Chicago Citygate trading at an average $1.68/MMBtu, down from $2.46/MMBtu a year ago, and Henry Hub at $1.69/MMBtu, down from $2.59/MMBtu.
In the midst of the widespread quarantine measures, MISO set a new all-time wind generation peak of 18 GW on April 9.
Queue Waiver Request Before FERC
MISO has also requested a 60-day extension of its June 25 deadline for developers to demonstrate exclusive land use for projects entering MISO South’s 2020 interconnection cycle. (See MISO to File 1st COVID-19 Queue Waiver Request.) The RTO asked for FERC to issue an order on the waiver by Friday (ER20-1794).
Chris Supino, with MISO’s legal department, said the waiver request doesn’t foreclose individual waivers for interconnection customers.
“Obviously a customer is free to go to FERC and request any waiver they want,” Supino said during a May 12 conference of the Interconnection Process Working Group. He urged customers to notify MISO of their situations to allow it to file supporting comments with FERC, should it deem a waiver necessary.
Supino said MISO will re-evaluate the need for further queue waivers if COVID-19 restrictions pick back up or continue for another month.
“It’s easy to go overboard at first, and we’re trying to take an incremental approach,” Supino said.
ERCOT may need to use Energy Emergency Alerts (EEAs) to provide “operational flexibility” and ensure it has sufficient resources to mitigate capacity shortages this summer, according to FERC’s 2020 Summer Energy Market and Reliability Assessment.
The report released Thursday found that aside from ERCOT, all NERC planning regions should have adequate generation available to exceed their reserve margins during June, July and August. FERC staff noted, however, that the projections were prepared before the COVID-19 outbreak began to impact the bulk power system and warned that system operators should prepare for deviations as the situation evolves.
ERCOT is predicting a reference reserve margin of 12.6% for the summer, according to its Summer 2020 Final Seasonal Assessment of Resource Adequacy, released May 13. (See ERCOT’s Summer Reserve Margin up to 12.6%.) This is higher than the initial projection of 10.7% used in NERC’s report, but still below NERC’s reference margin level of 13.75%. ERCOT said the elevated reserve margin in its latest assessment is due to a downward adjustment in peak load forecast to account for economic impacts from COVID-19.
In a podcast accompanying the summer assessment, members of FERC’s Office of Energy Policy and Innovation (OEPI) and Office of Electric Reliability (OER), which drafted the report, said the outlook for this summer is comparable to last year, when ERCOT reported a considerably lower reserve margin of 8.5%. (See Abundance of Summer Capacity — Except in Texas.) This led to what the grid operator characterized as a “difficult August,” though it was able to operate reliably throughout the summer months. (See ERCOT, SPP, CAISO Recount Summer Challenges.)
NERC 2020 anticipated reserve margins | NERC
“While ERCOT faced some challenges last year, it maintained system reliability with no load curtailments even as it set several new peak loads, including its current standing all-time peak load of 74,820 MW on August 12, 2019,” said Louise Nutter, with OER.
But despite the lack of load curtailments, ERCOT was forced to declare an EEA several times last summer to activate emergency procedures such as demand response measures and increased generation imports from neighboring regions. Even with these measures in place, the operator still found itself short on reserves at times, experiencing real-time locational marginal prices of up to $9,000/MWh. Based on the experience of last year, ERCOT identified a “potential increased need to call an EEA” under some scenarios this summer.
Net Growth in Generation Capacity
One area where ERCOT leads other regions is in the growth of its generation capacity. The grid operator intends to add more than 3 GW of generation this summer, almost entirely comprised of wind and solar facilities.
Industry-wide, about 5.6 GW of capacity is scheduled to come online this summer. MISO has the largest expansion planned after ERCOT, with 1.21 GW of primarily natural gas-fired generators. Next is CAISO, with 680 MW of wind and solar. ISO-NE, NYISO and SPP plan to add 60 MW, 80 MW and 10 MW, respectively.
Planned retirements total 1.3 GW, mostly by PJM, which will shut down 900 MW of coal-fired plants and approximately 200 MW of natural gas facilities while adding around 300 MW of solar capacity. The report noted that these projections could change due to the COVID-19 pandemic, with the economic slowdown affecting construction on new units as load and price reductions accelerate planned retirements across the industry.
While renewables make up most of the projected growth, natural gas will “continue to play a pivotal role” in the generation mix this summer, thanks to both the installation of new gas generators and the retirement of facilities using other fuels. The share of gas generation is highest in NYISO, where it represents 55% of total net summer capacity, but it remains the largest single source of generating capacity in every organized wholesale market.
Report Details
FERC cited data from the National Oceanic and Atmospheric Administration that “assesses a greater than 50% probability” of above-average temperatures throughout the Western U.S. and parts of the Southern and Eastern U.S. this summer, while average temperatures are predicted for the upper Midwest. NOAA also predicts that the 2020 Atlantic hurricane season will be more active than usual, with up to 16 named storms, eight hurricanes and four major storms between June 1 and Nov. 30.
Other findings from the report include the following:
Natural gas production is expected to average around 88 Bcf/d, a 3.7% decline from last summer. This will be accompanied by a 3% decrease in demand to about 78 Bcf/d. A major driver for this drop is falling consumption for electric generation, the largest sector of gas demand, which is expected to fall 1.6% this year.
U.S. natural gas exports are expected to “reach new highs” this summer, thanks in part to 5.3 Bcf/d of capacity additions at four LNG liquefaction terminals. Pipeline exports to Mexico are also expected to grow as new pipeline connections are added. LNG exports, combined with pipeline exports, are expected to average 14 Bcf/d in the summer months, up from 10.9 Bcf/d last year.
Natural gas storage levels are expected to end the injection season at 3.84 Tcf, around the five-year average. Staffers said the injection season began relatively high due to a mild winter, which helped to build back inventories from a large deficit in 2019.
Hydropower generation in California is expected to be lower than last year due to a below-average snowpack, which could lead to increased use of gas-fired plants and imports of power. Utilities in the state may also have to selectively de-energize transmission and distribution lines due to continued risk of wildfires. (See CAISO Predicts Adequate Summer Capacity.)
NERC Summer Assessment Previewed
In a preview of NERC’s 2020 Summer Reliability Assessment, planned for release June 1, FERC revealed the organization is forecasting net demand of approximately 750 GW, about 0.9% higher than summer 2019. Growth in demand is concentrated in ERCOT and WECC, with reductions predicted for PJM and MISO. Total generating capacity is expected to grow by about 0.2% over last year.
ERCOT’s control room | ERCOT
The team preparing NERC’s report told the Reliability Assessment Subcommittee in April that it has been a challenge to address the ongoing impact of the coronavirus outbreak while still providing a balanced look at other reliability issues. (See RAS Balancing COVID-19 Impacts in Reliability Report.) Nearly all of the report’s key findings have been affected by the pandemic in some way.
NERC released a separate report earlier this year to help with the issue. The Pandemic Preparedness and Operational Assessment — Spring 2020 is described as a “bridge” to the summer reliability assessment that can examine the effects of COVID-19 and provide guidance so that the main report is not overwhelmed with a single issue. (See PPE, Testing Top Coronavirus Concerns for NERC.)
Despite the growing threat of cyberattacks, utilities in many countries lack consistent regulatory frameworks for hardening their systems against malicious actors, according to a new report from the National Association of Regulatory Utility Commissioners and the U.S. Agency for International Development.
The groups produced Evaluating the Prudency of Cybersecurity Investments: Guidelines for Energy Regulators as a resource to help energy regulators craft strategies for determining whether utilities’ cybersecurity preparations are cost-effective and worthwhile. The guidelines are particularly intended for Europe and Asia, but the organizations hope they will be useful for any regulator that has not created their own frameworks yet and are unsure of where to begin.
“Start with a plan, and don’t waste time trying to make it perfect; this will also help to get the operators thinking strategically,” the report says. “The U.S. experience of many state regulators shows that starting to do something, even when it seems to be a drop in the ocean, provides expertise, feedback and engagement that are precious for shaping continuously improved strategies.”
Evaluating Effectiveness a Major Challenge
A crucial step in the development process, and the one that may be most challenging for regulators just starting their task, is deciding how to evaluate the effectiveness of a particular cybersecurity standard. It may be impossible to tell if one standard works to keep the grid safe because the metrics to determine success have not been developed yet. Another standard may seem to be working fine until an attacker exposes a vulnerability in a utility’s security protocols that the regulator never thought to test.
The report acknowledges that the four-step checklist for establishing reliability metrics in general is well understood: First, researchers and experts identify a list of useful indicators. Regulators then impose the calculation of these metrics on regulated companies, which report their value on a regular basis. These values are used to assess whether future investments will be effective for delivering the desired results.
The process of developing metrics for regulatory purposes | NARUC
But applying this process to create cybersecurity metrics is difficult, as “research concerning cybersecurity performance indicators is ongoing, while established practices are nearly nonexistent.” While metrics have been developed — the report singles out the Electric Power Research Institute’s Cyber Security Metrics for the Electric Sector as “one of the most advanced studies in the field” — these are at a very early stage of maturity.
Even if a metric seems to show improvement after a particular measure is implemented, the two events may not necessarily be connected; the positive change could simply be because of increased awareness of cyber risk on the part of a utility’s employees.
No One-Size-Fits-All Approach
In addition to an incomplete body of research, regulators must contend with the wide array of threatening actors, which have varying levels of sophistication as well as widely differing goals. Because each country faces a different set of adversaries, it may be hard to apply the work done in one market to other geographies, the guidelines say.
While the report draws on previous work by regulators — such as NERC’s Critical Infrastructure Protection (CIP) standards, as well as others from the U.S. and other countries — it does not present “unique turnkey solutions” for adoption and warns against copying successful strategies too closely. An effective regulatory framework must be tailored to address the circumstances of each individual market, based on the best information available and cognizant of the practical limitations facing regulated entities.
Suggested questions to shape regulators’ development are:
What are my objectives, and where should I start?
What strengths, weaknesses, opportunities and threats exist for utilities in my country from a cyber perspective?
Are there governing laws or administrative rules that limit or expand my influence in this area?
What mutual aid agreements are in place, if any, between my country and its neighbors?
Do I have enough skilled personnel in-house to address cybersecurity cost identification and benchmarking?
The report says ensuring cybersecurity preparedness can be accomplished only by those most familiar with a particular market and with the most at stake in the event of a successful attack. While much can be gained from sharing information on threats and defense measures, there is no single approach that can be used on a wide scale, it says.
It is “likely [a gold standard] will never appear because the design of a regulatory approach is not a technical task, but it is truly connected to a country’s values, vision and legal environment,” the report says. “Regulators must get started immediately and learn lessons along the way because experience will answer more questions than a 1,000-page book that would become outdated in six months’ time.”
FirstEnergy promoted its chief financial officer on Tuesday to take over as president beginning next week.
Steven Strah | FirstEnergy
Steven E. Strah, who was named CFO and senior vice president in 2018, was elected by the FirstEnergy board of directors to serve as president effective Sunday. Strah is taking over the role as president from Charles E. Jones, who has been FirstEnergy’s president, chief executive officer and member of the board since 2015. Jones will continue to serve as CEO and a member of the board.
Strah will oversee FirstEnergy Utilities; corporate services and information technology; finance; product development, marketing and branding; external affairs; rates and regulatory affairs; and strategy. Strah, who began his career with The Illuminating Company in 1984, previously served as regional president and vice president of distribution support of Ohio Edison, and senior vice president at FirstEnergy Utilities.
“Steve is a strategic and driven leader with a deep understanding of FirstEnergy’s business and the needs of our customers, employees and investors,” Jones said in a press release. “He is committed to driving our long-term, customer-focused growth plans, as well as our mission to be a forward-thinking electric utility.”
FirstEnergy also made several other senior leadership moves on Tuesday:
K. Jon Taylor was elected senior vice president and CFO and will report to Strah, overseeing accounting, treasury and investor relations.
Robert P. Reffner was elected senior vice president and chief legal officer, reporting to Jones. He will add risk management and internal auditing to his current duties overseeing the corporate, legal, information and compliance and real estate departments.
Ebony L. Yeboah-Amankwah was elected vice president, general counsel and chief ethics officer, reporting to Reffner.
Mary M. Swann was elected corporate secretary, reporting to Yeboah-Amankwah.
John Skory was named vice president of FirstEnergy’s utility operations.
Gary W. Grant Jr. becomes president of Ohio operations, reporting to Skory.
Michelle R. Henry, director of FERC and state regulatory compliance since 2018, was named vice president of customer service.
James H. Myers III was named president of West Virginia operations. Myers is taking over for Holly C. Kauffman, who is retiring after 36 years with the company.
FERC Chairman Neil Chatterjee, who has long been rumored to have political ambitions, floated a trial balloon last week on a potential run in the 2021 Virginia gubernatorial race.
Chatterjee created a Facebook group titled, “Hypothetical: Draft Neil Chatterjee for Virginia Governor 2021” on May 16. The page — which features a photo of Chatterjee in the commission meeting room, wielding a gavel and wearing a Washington Nationals baseball cap — had attracted almost 300 members as of Tuesday.
Chatterjee, a Kentucky native, joined the commission in August 2017 after serving as Senate Majority Leader Mitch McConnell’s (R-Ky.) energy adviser.
FERC Chair Neil Chatterjee with his former boss, Senate Majority Leader Mitch McConnell (R-Ky.) and New England Patriots coach Bill Belichick | Neil Chatterjee
“Does this mean you won’t be a lieutenant [governor] candidate for Kentucky in 2023?” asked one member on the Facebook page.
“Love, love, love Kentucky,” Chatterjee responded. “But [I] have been living in Virginia for almost 20 years.”
“I will not make any decisions about my future until after the completion of my term at the commission,” Chatterjee said through a FERC spokesperson in response to questions from RTO Insider. “While I appreciate the kind and encouraging responses, this was a lighthearted post to social media. All kidding aside, I take my role as chairman of the commission very seriously. I have been and will continue to be accountable to the staff, to my colleagues, to the courts and to the free press.”
The filing deadline for the primary is April 25, 2021, more than two months before Chatterjee’s FERC term expires on June 30.
But Chatterjee would need to make a decision well before April. According to the Virginia Department of Elections, gubernatorial candidates must obtain 10,000 signatures (at least 400 from each congressional district) to get on the ballot. (The filing deadline for independent candidates is June 8, 2021.)
Hatch Act
If Chatterjee decides to move forward with a campaign, he will be governed by the Hatch Act, which prohibits federal employees from seeking public office in a partisan election or soliciting or accepting political contributions.
The law is intended “to ensure that federal programs are administered in a nonpartisan fashion, to protect federal employees from political coercion in the workplace, and to ensure that federal employees are advanced based on merit and not based on political affiliation,” according to U.S. Office of Special Counsel.
The Field
Chatterjee could face a crowded field if he decides to run to replace Gov. Ralph Northam (D), who is prohibited by the state constitution from seeking re-election.
State Sen. Amanda Chase has announced her candidacy for the Republican nomination, and several other present and former elected officials, including former U.S. Rep. Barbara Comstock, have been named as potential candidates.
Former Gov. Terry McAuliffe, Attorney General Mark R. Herring and Lt. Gov. Justin Fairfax have expressed interest in seeking the Democratic nomination.
“Lighthearted” or not, Chatterjee’s flirtation means his future actions as chairman will be viewed by at least some through a partisan lens.
FERC Chair Neil Chatterjee’s Facebook page includes a photo of him with a chainsaw, reminiscent of the iconography of former Republican Presidents Ronald Reagan and George W. Bush. | The Reagan Foundation and Institute, Neil Chatterjee
Some renewable energy supporters have cited Chatterjee’s support of an expanded minimum offer price rule in PJM as evidence that he is supporting President Trump’s pro-coal agenda. Chatterjee has denied the charge, saying he is merely ensuring a “level playing field” for fossil fuel resources in response to state renewable energy subsidies.
Chatterjee and fellow Republican Commissioner Bernard McNamee have regularly clashed with Democratic Commissioner Richard Glick over their refusal to consider greenhouse gas emissions in rulings on natural gas pipelines and LNG export facilities.
On May 12, Chatterjee sent a letter rejecting Herring’s call for a moratorium on new gas pipeline approvals in Virginia during the coronavirus pandemic. “The public’s need for strong energy infrastructure is not lessened by this pandemic,” Chatterjee said in the letter, which he tweeted about. “It is imperative that the commission continue to operate as close to normal as possible, so that the energy sector is well-positioned to contribute not only to Virginia’s economy but also to the nation’s economy as a whole.”
Climate activist Drew Hudson, of Friends of the Earth, tweeted that if Chatterjee runs “he’ll be a joke — but it will not be funny.” Hudson said the chairman “personally ordered pipelines to take land from Virginia landowners, denied [their] appeals for rehearing, and threatened their homes and lives in the process.”
Before his time on McConnell’s staff, Chatterjee worked in government relations for the National Rural Electric Cooperative Association, as an aide to House Republican Conference Chairwoman Deborah Pryce (Ohio) and as a staff member on the House Committee on Ways and Means.
Chatterjee served as FERC chairman from August to December 2017 when he was replaced by Kevin McIntyre. He returned to the chairmanship in October 2018 when McIntyre, fighting cancer, relinquished the post.
In October 2017, Chatterjee praised then-Energy Secretary Rick Perry’s “bold leadership” in calling for price supports for coal and nuclear plants. Chatterjee joined in a unanimous vote rejecting Perry’s Notice of Proposed Rulemaking in January 2018.
In returning to the chairmanship, Chatterjee credited McIntyre for helping him grow “from [a] formerly partisan legislative aide to independent regulator.” (See Returning Chair Pledges to Protect FERC’s Independence.) McIntyre died in January 2019.
The expanded minimum offer price rule (MOPR) will cost PJM ratepayers almost $9.7 billion over the next nine years if FERC adopts revised floor prices allowing most nuclear plants to clear, according to a new analysis by critics of the commission’s directive.
Michael Goggin and Rob Gramlich of Grid Strategies generated headlines last August with a report that predicted an expanded MOPR could add $5.7 billion annually to PJM’s capacity costs. (See MOPR Impact Study Ruffles Feathers Ahead of FERC Ruling.) The estimate was cited by those calling for pulling the Commonwealth Edison zone in Northern Illinois out of the capacity market — and criticized by others, including Independent Market Monitor Joe Bowring, as wildly inflated.
Gramlich said the new analysis was prompted by FERC’s December order, which exempted more existing renewable energy than prior proposals, and PJM’s March 2020 compliance filing, which reduced MOPR floor prices for nuclear plants and renewables. (See PJM MOPR Floor Prices Reduced for Gas, Nuclear, Solar Units.)
Projected Increase in capacity costs by region and delivery year ($ millions) | Grid Strategies
The new analysis considers two scenarios: one in which FERC accepts PJM’s lower floor prices, and one in which the prices reflect the RTO’s original October 2018 proposal.
The authors say the new report is subject to many uncertainties, but that even under the best-case scenario, the MOPR is guaranteed to raise prices. “There are so many versions of MOPR and factors such as bid levels that vary between versions and over time that it is not possible to definitively conclude, as some have, that MOPR will have limited cost impacts,” the report says. “Under most scenarios, MOPR will result in billions or tens of billions of dollars in excess costs to electricity consumers across PJM.”
The report notes that the clearing price for the most recent Base Residual Auction in 2018 was $140/MW-day, with some zones clearing at between $165.73 and $204.29/MW-day.
PJM reduced MOPR floor levels of $175/MW-day for solar PV with tracking, which would have been low enough to clear in some areas of the RTO in 2018. But the RTO’s proposed $367/MW-day for solar PV without tracking, $1,023/MW-day for land-based wind and $3,146/MW-day for offshore wind are well above prior clearing prices.
PJM’s new proposal would allow multiunit nuclear resources to clear the market along with most or all single-unit nuclear plants. The authors assumed new renewable sources would not clear under either of the two scenarios, regardless of whether they were using the default bid levels proposed by PJM or resource-specific offer floors.
“It is likely that some solar, and potentially some land-based wind projects, could demonstrate evidence for unit-specific bid levels that are low enough to clear the capacity market,” the report acknowledged. “If resources do not clear, capacity market prices increase and redundant replacement capacity must be purchased and paid for by consumers, further increasing their bills.”
| Grid Strategies
Under the first scenario, the new MOPR could increase capacity costs by nearly $10 billion total over its first nine years, an average of more than over $1 billion annually. PJM’s capacity costs last year totaled $8.7 billion.
Under the second scenario, subsidized nuclear units in Illinois, New Jersey and Ohio would fail to clear, resulting in an increase of almost $24 billion over the nine years, an average of $2.6 billion annually, the authors say.
Caveats
The authors said their estimates are likely conservative because they don’t include the impact of subjecting self-supply, state default service auctions, demand response and energy efficiency resources to the MOPR.
Another variable is how quickly PJM states meet their renewable portfolio standards. Grid Strategies estimates almost 47 GW of nameplate capacity wind, solar and storage will be needed by 2030 to meet state targets.
“The cost of MOPR would be higher if renewable deployment is front-loaded into the next few years to benefit from federal renewable tax credits that are phasing down for projects completed through the mid-2020s” as was assumed in the 2019 study, the authors said. “This would result in a larger cost being attributable to MOPR, as those resources are subject to MOPR for a longer period of time and there is a larger price impact in the near term, but likely lower total cost to consumers because the renewable projects benefits from larger tax credits.”
Another course of uncertainty is that PJM is planning to revise the method for calculating the capacity value of wind and solar projects. (See PJM MRC Moves Forward on Storage, Hybrids.)
NYISO will face myriad challenges in the coming decades as New York decarbonizes its economy and the power sector transitions to zero-emissions generation, industry stakeholders heard Monday.
“Aggressive renewable goals raise questions about how a fully decarbonized energy system can work, especially given the intermittency of wind and solar,” Sam Newell, a principal with The Brattle Group, told the Installed Capacity/Market Issues Working Group.
“Importantly, why we’re here discussing this in New York is because New York has the mandates, and it’s actually the first entire RTO to go to 100% clean,” Newell said. “There are plenty parts of the country where individual entities have already gone to 100%, but they’re embedded in a much larger system that helps balance, so New York will be on the front end of seeing the challenges of going to a completely clean system.”
Brattle representatives presented an interim report on New York’s evolution to a zero-emission power system, modeling operations and investment in scenarios of increasing electrification for the years 2024, 2030 and 2040. They will consider feedback before presenting the final study results to stakeholders in June.
Hourly generation and load: 2024, 2030 and 2040 | The Brattle Group
As part of its “Grid in Transition” initiative, the ISO retained Brattle to simulate the resources that can meet state policy objectives and energy needs in order to inform planning for reliability and market design over the next two decades. (See N.Y. Looks at Grid Transition Modeling, Reliability.)
Electricity generation is already a relatively minor source of greenhouse gas emissions in New York, representing less than 16% of total emissions, so reaching economy-wide decarbonization goals likely implies significant electrification of buildings and transport, Newell said.
The high electrification case in the study sees 43 GW more capacity in New York by 2040.
Statewide Effort
NYISO is not alone in thinking about the future of the New York grid.
The state’s Public Service Commission this month authorized a study to identify distribution upgrades, local transmission upgrades and bulk transmission investments needed to meet the state’s clean energy goals (20-E-0197). (See NYPSC Launches Grid Study, Extends Solar Funding.)
The study was mandated by a budget amendment passed in April that created a new siting agency for renewable energy projects. The New York State Energy Research and Development Authority will collaborate with the Department of Environmental Conservation and the Department of Public Service to develop build-ready sites for renewable energy projects. (See NY Renewable Supporters Push for New Siting Agency.)
“We’re accounting, of course, for the Climate Leadership and Community Protection Act [CLCPA], but also other related programs and policies, such as continued participation in the Regional Greenhouse Gas Initiative, and the zero-emissions credit [ZEC] program for nuclear,” Newell said. The ZEC program expires in March 2029.
New York’s economy-wide decarbonization trajectory | The Brattle Group
New York’s CLCPA (A8429), signed into law last July, mandates that 70% of the state’s electricity come from renewable resources by 2030 and that generation be 100% carbon-free by 2040. (See Cuomo Sets New York’s Green Goals for 2020.)
The law’s clean energy mandates also include doubling distributed solar generation to 6 GW by 2025, deploying 3 GW of energy storage by 2030 and raising energy efficiency savings to 185 trillion BTU by 2025.
Newell said the NYISO study also accounts for the retirement of the Indian Point nuclear plant, as well as for “the new NOx rules that are likely to cause about 3,000 MW of older peaker plants downstate to retire.”
The paradigm shift coming to the electricity sector will see new technologies and resources supplant the old ways and means, the report said.
Today, gas-fired generators, dispatchable hydro and pumped hydro storage are key sources of flexibility, but the wind and solar output expected to dominate in the future is primarily driven by weather, thus reducing the amount of flexibility provided by generation.
“Between 2030 and 2040, we also see significant growth in renewable generation, so by 2040, we’re finding about two-thirds of load is served by wind and solar, and about one-third of load is served by offshore wind alone,” said Brattle senior associate Roger Lueken.
The future system will require more flexibility across all timescales, with hourly and seasonal balancing of intermittent renewables and more volatile load, he said.
Flexible loads, such as controllable electric vehicles and HVAC, can provide limited balancing within the hourly time frame, but new technologies will be needed to provide seasonal storage or zero-emission, dispatchable supply. The balancing challenge is across multiple timescales, the report said.
“We find that throughout 2030 and even 2040 there’s really minimal curtailment of wind and solar, despite the system predominantly being served by renewable generation, and that’s due to the amount of short-term balancing from storage and from the long-duration balancing provided by renewable natural gas production and consumption,” Lueken said.
Transmission Flows and Pricing
Today, New York transmission flows are primarily southbound, transferring power from upstate to downstate zones. In the future, those flow patterns become more variable, with flows occasionally reversing direction, the report said, noting that the frequency of constrained hours southbound generally increases.
Several stakeholders wanted more information on the transmission constraint and energy pricing assumptions in the study, but Newell deflected those questions.
Electrification and climate change will alter long-standing New York load patterns | The Brattle Group
“A model like this does produce shadow prices of all the constraints, which you could interpret. For example, if we have in 2030 a 70% clean requirement, you could interpret that as a market price for RECs [renewable energy credits],” Newell said.
“I think the New York ISO doesn’t want to be in a position of putting out a study that implies a cost of the state policy objectives, particularly when we haven’t focused in great detail with stakeholders on some of the cost constituents, like how much will the cost of various renewable resources come down, what might be the cost of an option with Hydro-Québec, or what might be some of the full resource integration costs,” he said.
The value in studying the future grid is not the ability to predict very particular resource mix scenarios, but in providing illustrative outcomes of how the grid may evolve in order for planners to understand future attributes of the power system.
“What NYISO said to me, and I think said to you all in the beginning, is that this is to try to inform across a range of scenarios, what type of fleet does it look like?” Newell said. “Is it 100 GW of equal amounts of solar, wind and offshore wind? Just broad-brush, paint a picture so that we can even start to look at what reliability concerns there will be. Later we can discuss how you even begin to think about price formation.”
NERC is projecting a total ERO Enterprise budget of $211.4 million for 2021, up 2.4% from the previous year as the organization and its regional entities grapple with the uncertain economic conditions arising from the COVID-19 pandemic.
In the first draft of NERC’s 2021 business plan and budget, the organization set its proposed budget at $82.9 million, an increase of $203,000 from the 2020 budget. The figure includes delay costs of about $1.8 million associated with the Align software tool, which was originally planned for rollout in 2019 but is now scheduled for release in 2021. (See NERC’s Align Tool Set for 2021 Rollout.) NERC plans to pay the Align delay costs using its operating contingency reserves (OCR), meaning assessments should not be affected.
ReliabilityFirst plans to raise its assessment from $22.3 million to $23.2 million, while SERC Reliability expects its assessment to grow from $22.5 million to $23.5 million. Midwest Reliability Organization and Texas Reliability Entity will keep their assessments flat at $17 million and $13.3 million, respectively, while Northeast Power Coordinating Council plans to reduce its assessment from $15.3 million to $15.2 million, and Western Electricity Coordinating Council expects a reduction from $25.3 million to $25 million.
ERO Enterprise 2021 preliminary budgets | NERC
NERC proposes to keep its own assessment unchanged at $72 million. In drafting the business plan and budget, NERC aimed to keep its assessment flat overall from 2020 in response to economic uncertainty among the electric industry and load-serving entities. Total ERO Enterprise assessments are expected to rise to $189.2 million, a 0.8% increase over 2020.
Align Delay Accounts for OCR Rise
NERC broke down its budget by category as follows:
Personnel — $48.2 million (3.4% increase over 2020). For 2021, overall headcount is expected to remain stable, with the increased budget attributable to rising salaries and medical insurance premiums.
Meetings and travel — $2.2 million (33.7% decrease). Fewer in-person meetings are expected in 2021 because of ongoing pandemic conditions.
Operating expenses — $28.2 million (2.2% increase). Increased software support expenses for products such as the ERO Secure Evidence Locker (SEL) will offset lower spending on other contracts and consultants and professional services for noncritical projects. (See NERC Investigating Chinese Tie to Software Vendor.)
Fixed assets — $3.3 million (29.5% decrease). The fixed assets budget includes the Align delay costs.
Net financing activity — $845,000 (505.2% increase). No loan borrowing is planned for 2021; debt servicing costs include a planned $2 million loan this year covering development costs for the SEL.
NERC also expects the OCR balance at the beginning of 2021 to be $7.7 million, representing 10.7% of the organization’s total budget, minus the System Operator Certification and Cybersecurity Risk Information Sharing Program (CRISP) budgets. This is higher than the normal target of between 3.5 and 7%; the excess is planned to fund the Align delay costs, as well as to have additional cash reserves on hand in light of the uncertain economic conditions.
ERO Enterprise 2021 preliminary budget by program area | NERC
The Compliance Monitoring and Enforcement Program (CMEP) (51%) and Reliability Assessment and Performance Analysis (RAPA) (18%) are expected to account for the largest share of the ERO Enterprise’s spending once again, as they did in last year’s budget. (See ERO Budgets up 3.8%; Assessments up 2.9%.)
NERC is requesting comment from industry stakeholders on the proposed business plan and budget by June 26; stakeholders are also encouraged to participate in their relevant REs’ stakeholder review processes. The Finance and Audit Committee will hold a conference call and webinar at 1 p.m. ET on June 4, where representatives from NERC and the REs will provide an overview of their 2021 business plans and budgets.
Texas regulators last week adopted rules establishing a cybersecurity monitor and coordination program for investor-owned, municipal and cooperative utilities that count on their voluntary participation (49819).
The amendments to the Texas Public Utility Regulatory Act (PURA) don’t require utilities to participate or to submit documents to the monitor. Utilities have made the rules’ voluntary nature a key issue in the proceeding.
But that left members of the Public Utility Commission nonplussed over comments made in the docket. Chair DeAnn Walker said during the commission’s open meeting Thursday that she was “taken aback” and “floored” by some of the stakeholders’ comments “and some of the people making those comments.”
The amendments are the result of two bills approved last year by the state legislature. Senate Bill 64 established the cybersecurity coordination program to share guidance on best practices, while SB 936 set up the cybersecurity monitor.
“Over the years, we have had input from the legislators that they clearly wanted something like this,” Walker said.
Commissioner Arthur D’Andrea said that he too was “taken aback” by the utilities’ comments, noting that the PUC has stood “shoulder-to-shoulder” with its stakeholders during the recent legislative session.
Commissioner Arthur D’Andrea
“While [the program is] voluntary, this is not an audit,” he said. “We want to protect their data, but we do expect participation and cooperation.”
When several utilities asked that “voluntary” be added to the rule, the PUC responded by saying the “voluntary nature of participation … is made clear throughout the rule.”
Monitored utilities will contribute to the program through their administrative fee to ERCOT. Those outside the ERCOT footprint will pay for the monitoring under a separate fee.
Any Texas utility “may” participate in the cybersecurity coordination program at no cost.
Commissioners Defend PUC Staff
Walker and D’Andrea both defended commission staff after they felt staff’s comments on an ERCOT Nodal Protocol revision request were devalued in a grid operator stakeholder meeting last week (NPRR1020).
PUC staff filed joint comments with ERCOT staff on NPRR1020, which clarifies that emerging battery storage technologies can be interconnected and operated as a resource. The change proposes to add a definition for “integrated battery storage system” (IBSS) and modifies the definition of “wholesale storage load” (WSL) to include IBSS.
PUC staff did not sign their individual names to their comments, while ERCOT staff did. During the Protocol Revision Subcommittee’s (PRS) meeting Wednesday, at least one stakeholder questioned why PUC staff didn’t sign their names, according to another stakeholder who requested anonymity.
“They wanted a name of a particular staff member. I find that offensive,” said Walker, who relayed her understanding of the PRS meeting based on a phone call she had received from staff.
PUC Chair DeAnn Walker makes a point during the commission’s May 14 open meeting.
PUC staff said PURA rules already allow for storage system loads integrated into a single container to be eligible to receive WSL treatment. They said the current IBSS definition “may arbitrarily exclude some integrated battery systems that do not meet all of the criteria specified in the proposed definition.”
“Therefore, [PUC] staff and ERCOT suggest revisions … in an effort to provide clearer guidance and minimize arbitrary treatment in extending WSL treatment to integrated battery systems,” agency representatives wrote. “The definition should focus on the characteristics that support extending WSL treatment to [storage systems] integrated into a single container instead of adding a new technology category to the WSL definition, which already includes the term ‘batteries.’”
“Technology is going to change. We have to be nimble to be able to change and do things with it,” Walker said. “If staff believes [NPRR1020] falls under our current rule, I find it offensive that people at ERCOT are challenging and saying that staff has no rights and has to [identify themselves].”
“Staff’s position is an institutional voice, and that should be good enough,” D’Andrea said. “This [NPRR] is already two-and-a-half years in the making. I’m already embarrassed by how long it’s taken us to nimbly account for this technology. This is the kind of thing Texas should be able to adapt to and that the markets should be able to handle well.”
The Wholesale Market Subcommittee agreed to take up NPRR1020, and ERCOT staff said it would schedule a workshop on the issue. Like the PRS, the WMS reports up to ERCOT’s Technical Advisory Committee.
ERCOT and PRS Chair Martha Henson, with Oncor, both declined to comment.
Customer Protections Extended to June 17
The commission added another month to its pandemic-related provision that suspends customer disconnections for non-payments, from May 15 until June 17, acknowledging concerns that extensions of the emergency order are being issued open meeting by open meeting (50664).
“I was really hoping at this point we would be further along in our reopening of the state,” Walker said, pointing to the Texas Panhandle and the rising numbers of COVID-19 cases related to meatpacking plants. The state reported more than 700 cases on Saturday alone.
“Those customer bills will continue to rack up,” she said. “At some point, they’re going to get a bill they have to pay.”
“I’m concerned we’re just starting to see the effects of economic disruption,” Commissioner Shelly Botkin said.
The order applies to low-income customers of vertically integrated electric utilities that operate outside of ERCOT: Entergy, El Paso Electric, Southwestern Public Service and Southwestern Electric Power Co.
In other actions, the PUC approved an amendment to the PURA that adds retail brokers or aggregators to those governed by customer protection rules for retail service (50406).
