PJM stakeholders last week unanimously endorsed proposed changes to the 2021 day-ahead scheduling reserve (DASR) requirement that saw small changes from last year.
David Kimmel, PJM senior engineer of performance compliance, reviewed the preliminary proposed changes at last week’s Operating Committee meeting, along with updates to Manual 13.
The DASR is the sum of the requirements for all zones within PJM and any additional reserves scheduled in response to a weather alert or other conservative operations. It is the sum of the three-year averages of both the under-forecasted load forecast error (LFE) and eDART forced outages.
DASR requirement components | PJM
Kimmel said the final 2021 DASR requirement is 4.74%, slightly lower than the 2020 requirement of 5.07%. He said the number comes from the LFE component of 2.16%, which is up 0.01% from last year, and the forced outage component of 2.59%, down 0.33% from last year.
The final 2021 DASR value will be incorporated into Manual 13 changes and be implemented in January.
Winter Weekly Reserve Target
The committee also unanimously endorsed changes to the 2020/21 winter weekly reserve target, which changed slightly from last year’s.
2020/21 winter weekly reserve targets | PJM
Patricio Rocha Garrido of PJM reviewed the results of the winter weekly reserve target analysis. The targets for December, January and February are 23%, 27% and 23%, respectively, compared to 22%, 28% and 24% last year.
“These increases and decreases are based on the load uncertainty we have in our most recent reserve requirement study case,” Rocha Garrido said. “However, the values are very close, so it doesn’t make much of an impact.”
Part of the reserve requirement study, the targets help staff coordinate planned generator maintenance scheduling and cover against uncertainties by ensuring that the loss-of-load expectation (LOLE) for winter is “practically zero,” Rocha Garrido said. For the entire year, PJM sets the LOLE at one occurrence in 10 years.
The winter weekly reserve target for each month is the highest weekly reserve percentage, Rocha Garrido said, rounded up to the next integer value.
Manual Endorsements
Stakeholders also unanimously endorsed several minor manual changes.
Lagy Mathew of PJM reviewed updates to Manual 3: Transmission Operations. Mathew said the changes featured minor clarifications, including defining extra-high voltage lines as those equal to or greater than 345 kV.
Kevin Hatch of PJM reviewed updates to Manual 12: Balancing Operations to address changes from the Market Implementation Committee’s special sessions on five-minute pricing and dispatch. Hatch said the RTO has been working with the Independent Market Monitor to identify sections of Manual 12 to be updated and to improve transparency on the dispatch process. Hatch said the changes include updated terminology for “day-ahead market” instead of the outdated “two-pass system.”
Texas regulators last week approved the election of Michigan Public Service Commissioner Sally Talberg and two others to three-year terms on ERCOT’s Board of Directors.
“I’m not trying to pick favorites, but I’m so excited to have Sally Talberg back,” Texas Public Utility Commission Chair DeAnn Walker said during the commission’s open meeting Thursday. “I’m glad to have her back in the ERCOT group.”
Walker said that Talberg approached her recently and asked her advice about joining the ERCOT board.
“I said absolutely,” Walker said. “I’m glad to have her back in the ERCOT group.”
Talberg advised the PUC from 2000 to 2004 during Texas’ transition to retail competition. Pat Wood III chaired the PUC at the time and would go on to also chair FERC under President George W. Bush. Judy Walsh, due to cycle off ERCOT’s board after this year, also served on the commission then.
While working on a master’s degree in public affairs from the University of Texas at Austin, Talberg also worked at the nearby Lower Colorado River Authority.
Talberg told RTO Insider she had expressed her interest in joining the ERCOT board some time ago, “initially thinking it would be some far-off prospect after serving on the MPSC.”
“But these spots were opening, so it happened earlier than I anticipated,” she said.
Talberg was first appointed to the PSC in 2013, serving as chairman from January 2016 to July 2020. Her term expires next July, but she has said she will step down from the commission once her appointment to the ERCOT board is official. (See “Michigan PSC’s Talberg Among Director Nominees,” ERCOT Board of Directors Briefs: June 9, 2020.)
The PUC also approved the elections of retired ISO-NE General Counsel Raymond Hepper and incumbent Director Terry Bulger to the ERCOT board. All three will serve as unaffiliated directors.
The board’s Nominating Committee has put forward former Consolidated Edison CEO Craig Ivey for the final vacant seat. Ivey will be presented to members during their virtual annual meeting in December.
D’Andrea Jumps the Gun
During the PUC’s open meetings, Walker typically opens discussion of a docket by saying she has written a memo with suggested changes. Commissioners Arthur D’Andrea and Shelly Botkin then usually express their agreement and approve the order.
The practice caught D’Andrea off-guard last week as Walker opened discussion of Oncor’s request for a limited code-of-conduct waiver from the commission’s affiliate reporting and affiliate transaction rules (50893).
Commissioner Arthur D’Andrea agrees with Chair DeAnn Walker’s nonexistent memo. | Texas PUC
“I agreed with your memo…” D’Andrea began.
“I didn’t have a memo. Arthur, why are you making it harder?” Walker responded, teasing D’Andrea. The few staffers in the socially distanced hearing room erupted in peals of laughter.
The commissioners agreed they had no concerns with the affiliate issue and approved the order.
Nuke Decommission Fund Remanded
The commission remanded back to docket management the Comanche Peak nuclear power plant’s requested review of its decommissioning cost study and funding analysis, finding that they do not include evidence required by Texas’ administrative code (50945).
Walker noted in a memo that the study and analysis were not accompanied by a report or supporting testimony and the requested annual funding amount; the decommissioning trust fund’s administrator did not demonstrate the funds are being invested prudently and in compliance with their investment guidelines; and the administrator did not demonstrate efforts to achieve “optimum tax efficiency.”
Comanche Peak Power Co. (CPPC) administers the decommissioning fund. It wants to continue the fund’s annual contribution of nearly $20.1 million through 2025, split between the plant’s two units on a 72.3/27.7% basis. The current approved allocation amount is on a 57.1/42.9% split.
The Comanche Peak Nuclear Power Plant’s two units | The Nuclear Decommissioning Collaborative
CPPC said the two units have a net after-tax value of $1.32 billion. It says according to a May decommissioning cost analysis, it will cost $1.73 billion in 2019 dollars to decommission and completely dismantle Comanche Peak. The analysis shows about a -2.5% difference between the $19.4 million required funding levels and the five-year average decommissioning-fund collections of $19.9 million annually from 2015 to 2019.
In other actions, the PUC:
authorized Southwestern Electric Power Co.’s (SWEPCO) and El Paso Electric’s (EPE) adjustments to their energy efficiency cost recovery factors. SWEPCO will be allowed to recover $5.2 million (50805) and EPE $5.9 million during the 2021 program year (50806).
allowed EPE and Entergy Texas to issue fuel refunds following settlement agreements. EPE will refund $9.4 million (50940) and Entergy $25.5 million (51037) to ratepayers.
Replacing the fossil-fueled energy supply with renewable energy requires unusual focus and substantial investment in the electricity sector. Our ability to meet these needs — elevated by climate change and the COVID-19 crisis — depends on the success of RTOs and ISOs. We at the Union of Concerned Scientists work to make these institutions more transparent, understood and responsive to science and democratically established laws.
The RTOs/ISOs evolved over decades and matured in the 1990s through a combination of electric utility industry and government regulatory desire for cooperation and efficiency. Coordination in the utility industry through competition and innovation becomes harder when the RTOs/ISOs ignore the public interest in further decarbonizing energy. The conflict between an energy market system that ignores external costs and a society and its policymakers that see the health and climate impacts of pollution from energy can’t be ignored.
These organizations have demonstrated they can deliver savings and integration of high levels of renewables.
Utilities are Different
The difference between RTOs/ISOs and better known trading platforms, such as Lyft, Uber, eBay and Amazon, is that the grid operators were established by existing monopolies. But those monopolies did not anticipate renewable energy growth driven by policy, economics or carbon limits. The influence of the incumbent players in making the rules is not found in the better known platforms. How much do the existing asset owners influence new energy technologies in the market? We can take a look at how open, transparent and interested in emissions these grid operators are.
We Have Work to Do
The RTOs/ISOs are at varied and different places on transparency and consideration of climate impacts. Broadly, the RTOs/ISOs provide regional coordination and sharing reserves through power pools that benefit consumers, allow competition and further cost savings and technology innovation. But how well does this structure, set up with advantages for the owners of existing power plants, serve to protect the climate and implement state carbon-reduction policies? When policymakers push the external costs of carbon and health into decisions that can lower carbon emissions, RTOs/ISOs should not counteract those policies and raise costs to consumers.
Transparent and Open?
Transparency builds trust. Stakeholders have to know how decisions are influenced. The public needs to know what decisions are being made.
How well members, stakeholders or even the public follow the decision-making depends in large part on the posting of meetings scheduled, agendas and the minutes of what was discussed. UCS was quick to support press access to NEPOOL when access was denied. But a wider look at the mere posting of meeting dates and agendas for the RTOs/ISOs’ governing boards differ sharply from one regional grid to the next.
In PJM, there is no schedule of board meetings available and no minutes, leaving stakeholders unsure of discussions or changes to items on which members had voted. The ISO-NE board’s meeting dates and bare agenda are available, but minutes are not. At NYISO, board meetings can be open to regulators upon request, and minutes and future dates are published. MISO mails out notices of board meetings, and even the committees of the board hold open meetings. SPP posts meeting notices and extensive minutes and materials. CAISO holds open meetings with video recordings posted on YouTube!
Carbon-aware?
The RTOs/ISOs operate in parallel (and lately in conflict) with state laws that regulate utilities and provide consumer protections, as well as with health and safety protections that address environmental externalities. The New England States Committee on Electricity’s recent vision for the grid connected the lack of transparency in stakeholder and ISO-NE board processes with the need for market reforms suited to “the New England states’ legal requirements, policy imperatives and associated consumer interests.”
New York state CO2 emissions by sector | NYISO, using U.S. EIA data
There is a wide range in how the RTOs/ISOs keep informed and share data about emissions from power plants. Ten to 15 years ago, some ISOs developed a report of average marginal emissions for the evaluation of pollution savings from state energy-efficiency programs. Today, climate change driven by accumulated greenhouse gas is a bigger concern. Reporting totals of emissions over a year and by month or season will help decision-makers facing a wider variety of options to change fossil fuel use and cumulative emissions.
NYISO established an Environmental Advisory Council in 2004 that provides it with reports that include average marginal emission rates from its generation, as well as the cumulative CO2 emissions in New York from all sectors (drawing data from the U.S. Energy Information Administration). PJM reports only the average marginal rate of emissions, released each spring, and it is impossible to determine if this report is shared with the RTO’s board because there is no transparency. ISO-NE has, since 1993, made a similar annual report of marginal rates of emissions, though with an 18-month delay from the end of the year. CAISO makes monthly reports of emissions. SPP makes none.
Changed Energy Mix
Reporting on the energy mix is another measure of improvement on climate-harming emissions. SPP does post data showing enormous use of wind energy. In the spring and fall, SPP’s energy supply mix is routinely as high as 50% wind. All the other RTOs/ISOs also display their current energy mixes on their websites. These kind of data on the resources meeting electricity demand are fundamental to the RTO/ISO function. Such displaying and archiving of energy data is a minimal level of transparency not found from utilities outside the RTOs/ISOs.
The accumulation of CO2 in the atmosphere comes from the cumulative emissions from combustion (and other biological sources). A decent comparison and metric for RTO/ISO boards to monitor would show total greenhouse gas emissions from power plant operations, along with the sort of data EIA provides on fuel-burning emissions in other sectors of the economy in their regions. That reporting would allow RTO/ISO boards to monitor changes as members and utilities pursue electrification and electricity replaces fossil fuel in building and transportation. RTO/ISO boards should receive a report annually on how the grids they manage are affecting the climate.
What We Need from RTOs
Regional cooperation to meet energy demand requires transparency and openness now, as the public, leaders and utility industry members meet the challenge of climate change and decarbonize energy. Leaders of all these organizations need metrics reflecting their own operations and markets, both for daily business and for addressing climate-damaging emissions of carbon and methane.
People in government need the informed cooperation of citizens and corporations to implement policy on climate. With all the decision-making ahead, the RTOs/ISOs are going to be key for people, their polices and utilities to work together in new ways to move off climate-damaging fuels.
The New England states are asking for change from their RTO. The Mid-Atlantic states are in court over their RTO’s objection to renewable energy policy. We have to decide: Are these organizations up to the task?
Mike Jacobs is a senior energy analyst for the Union of Concerned Scientists with expertise in electricity markets, transmission and renewables integration work.
MISO said it will file with FERC updates to its emergency pricing design by the end of the year, hoping to spur more action from suppliers when conditions get risky.
The changes involve two new minimum-offer floors, expanding the definition of fast-start resources and integrating costs of its Midwest-to-South transmission limit into prices.
The RTO will introduce two new minimum emergency-offer floors: $500/MWh for maximum generation warnings and $1,000/MWh for maximum generation events.
MISO Market Design Adviser Michaela Flagg told the Market Subcommittee on Thursday that the new floors “reflect the value of emergency supply” and said the $1,000/MWh minimum lines up with the grid operator’s established threshold of how much it’s willing to pay before entering an emergency.
Customized Energy Solutions’ Ted Kuhn urged MISO to move away from static numbers in its proposal. He said tying the emergency-offer floors to the RTO’s current value of lost load (VOLL) and operating reserve demand curve is short-sighted, especially because it is considering an increase to its outdated VOLL figure.
The VOLL has been unchanged since 2009. At the time, $3,500/MWh was the estimated price at which some customers would opt for service interruption.
“That $1,000 number is going to be quite different in perhaps the very near future,” Kuhn said.
Along with the new offer floors, MISO said it will extend resources’ eligibility to set LMPs during emergency conditions. It plans to include online resources with four-hour or less start-up times in the fast-start definition during maximum generation alerts, warnings and events.
MISO emergency procedures | MISO
MISO’s current fast-start definition requires resources to fire up within 10 minutes of notification and run for at least an hour.
“We really saw the benefits drop off after four hours, so four hours seems to be a sweet spot,” Flagg said. “It allows a lot of these resources to participate in pricing.”
Flagg said allowing a short-lived relaxation of the fast-start lead time requirement in emergencies “better aligns with the real-time commitments made during emergency operations.” Staff say it is common during emergencies for operators to commit resources with notification and start-up minimum run times between one and four hours.
“During emergency conditions, the fast-start resource definition does not align with resources committed in real-time and, therefore, prices are not able to reflect the full costs of units needed to meet system demand and reserve requirements,” MISO said.
The grid operator also wants to better incorporate into energy prices the cost of managing its Midwest-to-South transfer limit.
To do that, MISO will set a marginal value of $200/MWh on its reserve procurement enhancement constraint management.
Under the existing reserve procurement enhancement (RPE), MISO models the effects of transmission constraints on the deliverability of reserves and adds the marginal cost of delivering them to zonal reserve market-clearing prices. The RPE ensures reserves are deliverable within the Midwest and South regions and that MISO doesn’t violate its megawatt limits on the Midwest-South transmission constraint for longer than 30 minutes. The settlement agreement governing the constraint stipulates that the grid operator not exceed the contractually set megawatt limits for longer than 30 minutes.
MISO says the marginal value limit assigned to the constraint — currently administratively set between $20 and $40/MWh — does not reflect the value of meeting the reliability requirement, resulting in “insufficient reserves being cleared in the sub-region and inefficiently low prices.” The grid operator said $200/MWh is more appropriate, according to its studies.
MISO said most of its sub-regional emergencies are called “due to limited transfer capability” over the Midwest-South constraint.
VOLL Questions over Hurricane Laura
Some stakeholders continue to question whether Hurricane Laura’s landfall on Aug. 27 near the Texas-Louisiana border was the right time for MISO to administer VOLL pricing.
Xcel Energy’s Kari Hassler said that because VOLL pricing was applied after-the-fact, generator actions as the event unfolded were motivated by circumstance, not pricing.
“I don’t want to say it was a misuse of VOLL, but it didn’t incent generators,” Hassler said.
WPPI Energy economist Valy Goepfrich said she pictured VOLL discerning cost-causation and not for use “during a disaster.” Other stakeholders agreed that cost-causation is difficult to trace in a natural disaster.
[UPDATED Nov. 9 11:25 a.m. ET to reflect election results.]
A measure in Nevada to enshrine a clean energy mandate in the state constitution is heading to victory, while New Mexico voters approved an overhaul of their state’s Public Regulation Commission, and Arizonans elected another Democrat to the state’s Corporation Commission.
Votes remained uncounted in Nevada, but ballot Question 6 was leading 57% to 43% as of Sunday night, according to the secretary of state’s website. The measure asked voters for the second time in two years if the state should make clean energy goals a part of its constitution.
A law signed by Democratic Gov. Steve Sisolak in April 2019 requires the state to get half its electricity from non-carbon-emitting resources by 2030, but environmentalists worried it could be overturned by elected officials if the political winds shift and sought a more permanent solution.
Amendments to Nevada’s constitution must be approved in two consecutive elections, so the question faced a final vote this year after winning 59% support in 2018. That effort, like the current one, was bankrolled by California billionaire and environmental activist Tom Steyer. (See Climate Policy on the Ballot Tuesday.)
An array near Las Vegas is among the utility-scale solar projects that Nevadans increasingly rely on for renewable power. | U.S. Bureau of Land Management
New Mexico
New Mexicans voted 55% to 45% for a constitutional amendment to revamp the PRC from a five-member body elected by district to a three-member body of at-large utility commissioners appointed by the governor.
A nominating committee will make recommendations of “professionally qualified nominees” under the measure, which prohibits more than two of the PRC’s members from belonging to the same political party. The new law replaces commissioners’ staggered four-year terms with six-year appointments.
It takes effect Jan. 1, 2023, ending the terms of elected members at the close of 2022.
Two members of the PRC backed the ballot measure, arguing that utility regulators should have experience in the complex field. Some of those elected to the PRC lack the backgrounds needed to understand and rule on regulatory issues, Commissioners Cynthia Hall and Stephen Fischmann wrote in an opinion piece published in a number of the state’s newspapers.
“The public and the utility companies that serve them deserve to have commissioners with meaningful expertise when they begin working as commissioners,” Hall and Fischmann wrote. “That means graduate-level education plus significant industry or regulatory experience. Commissioners should be experts at the outset, not rookies.”
Hall was re-elected to a two-year term on the commission Tuesday; Democrat Joseph Maestas was newly elected to an open seat.
Other members of the PRC contended that allowing the governor to appoint its members would deprive voters, especially those in rural disadvantaged communities, of the opportunity to influence ratemaking and policy decisions.
“There is no requirement for any sort of geographic representation, which makes it extremely likely that the commission would be dominated by members from the urban population centers rather than rural New Mexico,” Commissioners Theresa Becenti-Aguilar and Jefferson Byrd wrote in a competing op-ed.
Commissioners were also divided in their support of a landmark law from 2019 that requires the state’s investor-owned utilities to get 100% of energy from carbon-free sources by 2045. Both Hall and Maestas support the measure.
Arizona
In a close and contentious race for three seats on the ACC, Democratic newcomer Anna Tovar led a pack of six candidates to win election, along with two Republicans. Tovar, one of a slate of three Democrats backed by New York billionaire Michael Bloomberg, secured nearly 18% of votes cast.
Republican incumbent Lea Marquez Peterson came in second with 17%, closely followed by Republican Jim O’Connor, who had a similar vote tally.
Left behind were Democrats Bill Mundell and Shea Stanfield and Republican Eric Sloan, each of whom fell short of the top three vote getters.
Potentially at stake in the race is an Oct. 29 commission decision to adopt a 100% clean energy mandate by midcentury. California, New Mexico and Washington also have 100% clean-energy
The commission, which currently has four Republicans and one Democrat, voted 3-2 for the mandate. Chairman Bob Burns and Commissioner Boyd Dunn, neither of whom sought re-election, voted with Democrat Sandra Kennedy in support of the measure.
With the two Republicans winning office, the decision could be reversed. Republican Commissioner Justin Olson expressed his dismay with the potential cost to ratepayers in a statement after the Oct. 29 vote. Marquez Peterson opposed the move. And O’Connor said he would vote to reverse the decision if elected, The Arizona Republic reported.
When Microsoft set a goal of using 100% renewables by 2025 and becoming carbon negative by 2030, it realized it couldn’t do it on its own. So, it turned to … an oil company?
You heard that right, Mark Schütz, global senior digital strategy director for Microsoft, told a Northeast Energy and Commerce Association webinar last week.
Microsoft and Royal Dutch Shell, Europe’s largest oil-and-gas company, are now strategic partners on decarbonization efforts, the latest iteration of three decades of collaboration by the two companies. Digital technology will play a central role.
Artificial Intelligence, Solar and Wind
Shell will supply renewable energy to Microsoft to help the tech giant meet its targets, which includes erasing all historical emissions by 2050 through carbon capture and sequestration technology. Microsoft, in turn, will support Shell’s plans to use artificial intelligence to transform its operations to reach net-zero emissions by 2050 or earlier.
“It all started with our joint ambition,” Schütz said. “We were looking for partners, particularly in the energy industry, to make our ambitions reality. But [we also wanted] to make a greater impact with partners like Shell to accelerate the low-carbon transition worldwide.”
Shell currently has more than 1.6 GW of solar generation capacity through its operated facilities and joint-venture partnerships in North America. This includes a 43% stake in Silicon Ranch, one of the largest independent power producers in the U.S. with more than 120 solar facilities across 14 states. Shell’s 230-MW wind portfolio in North America includes interests in four onshore projects and energy obtained from eight partners. It has the potential to generate an additional 5 GW through joint-interest wind farms under development.
Clockwise from top left: Mark Schutz, Microsoft; Matthew Picardi, Shell; and Daniel Silva, Shell | NECA
Shell and Microsoft have been working together on AI for three years. Forty-seven AI-powered proprietary applications have been deployed across Shell’s businesses this year, along with real-time technology to reduce carbon emissions in the company’s LNG operations. The new strategic alliance will accelerate the companies’ AI work to drive efficiencies further and reduce emissions.
Additionally, Microsoft has developed technologies to help keep Shell’s workers and sites safe, including the use of Azure cloud computing to power Shell’s autonomous integrity recognition system, which uses image recognition algorithms to detect when equipment or parts of a site are susceptible to corrosion. The two companies will advance the use of sustainable aviation fuels and plan to use Azure and data from Shell assets to strengthen operational safety by improving risk analysis, prediction and prevention.
Shell’s Transition
In 2017, Shell pledged to reduce the net carbon footprint of its energy products by about half by 2050, upping that in April 2020 with a pledge to reach net zero by mid-century. But it has known about the impact of carbon emissions on climate since the 1980s.
An internal report in 1988 reportedly predicted CO2 levels could double by 2030 and the potential disintegration of the West Antarctic Ice Sheet, resulting in a worldwide sea level rise of 5 to 6 meters, enough to flood low-lying countries. Rising air temperatures would “drastically change the way people live and work,” the company concluded. The company did not share the results of the report, however, which were disclosed by a Dutch news organization in 2018.
Shell, which has seen its stock price drop almost 60% this year, told investors last month its oil production might have peaked last year.
Daniel Silva, general manager for strategic enterprise development for Shell, said the transition to net-zero emissions is “really complex and will demand much more in-depth conversations on how we dive into those fundamental challenges.” Silva added that three principles guide Shell’s activities and initiatives on decarbonization: how to avoid emissions in the first place; if they are unavoidable, how they can be reduced; and how to remove and offset them.
Supporting Customers
Shell and Microsoft will work together on new digital tools to help Shell’s suppliers and customers reduce their carbon footprints. Silva said there is “absolutely no solution” that does not include customers as well.
“We are the biggest [mobility] retailer in the world,” Silva said. “We have more than 44,000 sites across the globe and have 30 million customers that come to our gas stations, every single day, so that’s a very relevant component.”
Shell and Microsoft are both customer-centric organizations, but customers’ behaviors and needs are changing, so “the customers of today will definitely not be the customers of tomorrow,” he said.
The sheer scale of Shell’s customer-facing sectors necessitates capital investment and partnerships like the one with Microsoft to achieve decarbonization, according to Silva, who is “super excited” to see the further use of AI and data-driven methods.
“We need to cater to the customers who go to our sites to buy coffee, or charge their electric vehicle, or buy premium gasoline or lubricants,” Silva said. “We need to make sure that that transition is done responsibly, working with our consumers, with policymakers and with the technology partners to be able to get there.”
Schütz said Microsoft recently announced a $1 billion Climate Innovation Fund to accelerate the development of carbon reduction, capture and removal technologies with a goal of carbon negativity.
“We need more technology tomorrow and the day after tomorrow, and we think we can best do that by working together to bring the new tools that we are developing, and also potentially Shell is developing, together with its expertise on energy,” Schütz said.
Silva concluded that Microsoft and Shell working together on technology initiatives is the best way to “fundamentally tackle” decarbonization.
“Each one of these elements will have carbon monitoring, and out of that, you will have renewables 24/7 or at least a high percentage of the time,” Silva said.
CAISO said Friday it was continuing to shake up its leadership team under new CEO Elliot Mainzer and recently appointed Chief Operating Officer Mark Rothleder.
The reorganization, which takes effect Monday, is a combination of promotions, expanded duties and interim appointments. All the executives involved will report to Rothleder, CAISO said. (See CAISO Leadership Changes Continue.) The changes will also bring together previously separate functions, including market policy, planning and operations, the ISO said.
“This restructuring will give us the opportunity to look at our roles and responsibilities from a fresh perspective and enhance alignment and integration from market policy to system dispatch,” Rothleder said in a news release.
Among the personnel changes:
Khaled Abdul-Rahman, executive director of power systems and smart grid technology development, will become vice president of power system and market technology.
Anna McKenna, assistant general counsel for regulatory issues, will step in as interim head of market policy and performance, Rothleder’s prior job, while CAISO searches for a replacement.
Neil Millar, recently appointed as vice president for transmission planning and infrastructure development, will have an expanded role, including overseeing operations engineering services.
John Phipps, director for real-time operations, will become executive director of grid operations.
Janet Morris, executive director of program management, will take on an expanded role as executive director of program and application management.
Hugo Frech, director of infrastructure engineering and network operations, will be promoted to executive director of the same areas.
“I would like to congratulate Mark and Khaled on their executive promotions and to thank the other members of my skilled leadership team who have stepped into new roles to support this reorganization,” Mainzer said in a statement.
CAISO CEO Elliot Mainzer | BPA
Mainzer, the former head of the Bonneville Power Administration, became CEO on Sept. 30, a day after former CEO Steve Berberich retired. (See CAISO Retiring, Incoming CEOs Field Questions.)
One of Mainzer’s first actions was to promote Rothleder, one of several vice presidents at the ISO, to his new role as second-in-command.
Mainzer will oversee the redesigned executive organization.
“The new team will enable Mainzer to focus on strategy, culture and stakeholder engagement while strengthening the ISO’s capacity to effectively integrate new resources and enhance reliability during the transition to a decarbonized electricity grid,” CAISO said.
The New York Climate Action Council’s Power Generation Advisory Panel on Thursday decided to take on the issue of methane gas leakage as part of an effort to scope out by next fall a statutorily mandated path to reduce the state’s greenhouse gas emissions 40% by 2030 and no less than 85% by 2050.
New York PSC Chair John B. Rhodes | New York DPS
“After good discussion about the narrower methane leaks and associated emissions and safety consequences on the natural gas system, we’re going to turn this analysis into statements that reflect collective thinking,” said John B. Rhodes, chairman of both the panel and the state’s Public Service Commission. The panel is one of six, each sector-specific, advising the CAC.
The panel also discussed the broader issue of developing and integrating renewable energy resources onto the New York grid.
The Climate Leadership and Community Protection Act (CLCPA) directs the state’s Department of Environmental Conservation (DEC) to include upstream emissions in its statewide emission calculations. New York on Oct. 27 concluded its hearings and public comment process on statewide emissions limits for 2030 and 2050 proposed by the DEC — 60% and 15%, respectively — of estimated 1990 GHG emissions. (See New York Holds Final CLCPA Emissions Hearings.)
The Future of Gas
Kit Kennedy, NRDC | New York DPS
Kit Kennedy, director of energy and transportation for the Natural Resources Defense Council, said that addressing methane leakage is a natural part of dealing with GHG emissions, but that it should be done in a way that doesn’t extend the life of the natural gas system.
“We do know we are going to have to get off gas to meet the CLCPA goals, at least fossil gas,” Kennedy said. She said she was concerned about language indicating a continued need for natural gas in the near to medium term. “I don’t know what that means, [as well as] needing gas to ensure reliability. I prefer that we keep those issues as distinct as possible.”
New York’s GHG emissions in 2015 were virtually unchanged from 1990 levels, according to a recent study that highlights upstream impacts and the role of methane under the state’s revised reporting rules. (See NY Study Highlights Rising Methane Emissions.)
A 100-year time frame map of methane (CH4) emissions by county in New York state in 2017; officials expect in January to issue the 20-year time frame study mandated by the CLCPA. | NYSERDA
The issue of methane leakage is inexorably tied with a solution for the missing 25% of emissions reductions in 2040, said John Reese, senior vice president of Eastern Generation, which controls approximately 5,000 MW of generation in the state, including some peaker units.
“We need to look at what it takes to mitigate the leakage, and [if we are] going to use the natural gas system infrastructure system going forward to meet some of the other needs that currently are unfilled in 2040,” Reese said. “Looking at this in a stovepipe or isolated manner will be problematic. The impact piece of this is the first step before we can look at how we go about dealing with this larger issue.”
John Reese, Eastern Generation | New York DPS
Macy Testani, assistant project manager at the New York State Energy Research and Development Authority (NYSERDA), said that consumers, not utilities, pay for leaks from points beyond the main natural gas pipelines and that there is little incentive to fix the aging pipes that run to many residences and businesses. She referred to a 2019 study that breaks down the leakage in-state in terms of upstream, midstream and downstream sides, the latter contributing significantly to overall emissions attributed to gas infrastructure.
Rhodes interrupted to say that, “It is certainly the case that the state regulatory apparatus and the utilities are prioritizing repair to the riskiest stretches of leak-prone pipe, in this case being a safety concern of explosion.”
William Acker, executive director of the New York Battery and Energy Storage Consortium (NY-BEST), said that methane is more impactful but also more reactive, meaning a lot of the methane in the atmosphere is naturally consumed each year.
William Acker, NY-BEST | New York DPS
“You can stop the leaks, or you can react the methane and get rid of it,” Acker said. “It might be that there’s an economically viable path that stops the major leaks and reacts some of the methane to get rid of it. … Has there been any research on that, or is that an area being considered at all? … It may be a crazy idea.”
Testani said that NYSERDA and the DEC have not looked at the reactivity of methane in the current mitigation project, but “we’re at the point where we need all crazy ideas to consider.”
The CLCPA also requires that methane emissions be compared with CO2 over a 20-year period rather than the 100-year time frame still used by virtually all other governments in the world. Testani said NYSERDA expects to issue the draft 20-year time frame analysis in January.
Bring on the Renewables
John Williams, NYSERDA | New York DPS
The CLCPA requires that 40% of the benefits of state investments in clean energy reaches disadvantaged communities, which are often located near the dirtiest oil- and gas-fired peaker plants. The state is taking “an accelerated approach” to meeting those investment goals, said John Williams, vice president for policy and regulatory affairs at NYSERDA.
A big challenge in retiring those peakers “is not just a peaking issue; it’s also an overall energy production issue,” NYISO Executive Vice President Emilie Nelson said.
Many studies show that, especially in light of climate change, sustained periods of weather patterns, such as lulls in the wind or less sunshine in winter, are not conducive to high renewable output, she said.
Emilie Nelson, NYISO | New York DPS
“That could happen on a seasonal basis for quite a long duration, so it’s a daily cycle; it’s a seasonal cycle; so, that’s not just a peak issue,” Nelson said.
“Despite the new siting law in New York, siting and community concerns and opposition are still a big issue … as is access to all for renewables, which ties into equity and environmental justice concerns,” Kennedy said. “I’d also like us to dig a little deeper into some of the assumptions … like lack of suitable space for large-scale renewables downstate.” S
Lisa Dix, Sierra Club | New York DPS
he urged panel members to “make sure we are not locking ourselves into traditional thinking.”
Lisa Dix, New York representative for the Sierra Club Beyond Coal Campaign, brought up barriers in NYISO to dispatching storage and said she wanted to “amplify the question mark” on the lack of space issue, suggesting that NYSERDA officials assessing build-ready sites look in New York City and Long Island.
“In the process of getting rid of dirty peaker plants, how will those sites be reused?” Dix said.
In response to Dix, Nelson said that in August, “NYISO did implement a full complement of storage rules that allow participation of storage directly in our energy markets. … So, there is an option for participation and dispatchability by storage resources within the wholesale markets.” (See NYISO’s 2nd Storage Compliance Almost Hits Mark.)
The rapid restoration of electric service to customers in the southern U.S. following Hurricane Laura this summer was a testament to the need for collaboration between all industry stakeholders in an increasingly volatile hurricane environment, representatives of SERC Reliability and MISO told NERC’s Member Representatives Committee (MRC) on Thursday.
“2020’s been a record year in many ways, and it’s taken a lot of work by a large number of folks to get through this storm season, and we’re not done yet,” said Tim Ponseti, vice president of operations at SERC. “Hurricane Laura’s a tremendous example of our entire industry, along with regulators and the government … rising to the occasion and pulling together in a way that’s truly patriotic. … If only other parts of our country could pull together in a similar way.”
Strong Hurricanes a Known Threat
Grid operators knew by this spring that 2020’s hurricane season would be unusually active, with additional stress expected from the ongoing COVID-19 pandemic. (See Pandemic Adds to 2020 Hurricane Season Challenges.) But Laura proved an even trickier challenge than expected, growing in strength from Category 2 — with 100-mph sustained winds — to Category 4 — with sustained wind speeds of more than 150 mph. When the storm made landfall Aug. 27 near Lake Charles, hurricane-force winds were felt as far away as the Louisiana-Arkansas border.
The storm damaged or destroyed more than 1,900 transmission structures and damaged 430 substations, resulting in 342 initial sustained transmission line outages. More than 1 million customers lost power in Louisiana, Texas, Arkansas, Tennessee, Mississippi and Oklahoma. Damage estimates so far total more than $14 billion.
Damage to power lines after Hurricane Laura made landfall in Louisiana, August 2020 | SERC
“We use the word ‘restoration’ a lot. This was not a restoration; this was a reconstruction for many pieces of the system,” said Todd Hillman, chief customer officer at MISO. “This was not like other storms, and the messaging [and] story around that was pretty important.”
Recovery work was further hindered by the arrival of Hurricane Delta, which made landfall Oct. 9 in Creole, La., just 12 miles east of the spot where Laura hit six weeks earlier. While Delta was a much weaker storm than Laura, at 100-mph sustained winds, and lost strength rapidly after landfall, it still knocked out some of the critical 500-kV lines that crews had restored following damage from Laura and caused 820,000 customers in four of the same states to lose power again.
Advance Prep Helped Speed up Response
Despite the devastation, crews worked rapidly to restore service; all customers affected by Laura regained electricity by Oct. 1, while the outages caused by Delta were addressed by Oct. 15. While some bulk electric system transmission lines remain under repair, the major lines serving their areas were restored by Oct. 18. Ponseti credited the effective response to SERC’s recognition of the growing threat from severe weather, particularly after the incorporation last year of the Florida Reliability Coordinating Council’s territory. (See FERC OKs SERC’s Expansion into Florida.)
“SERC’s regional risk report identified extreme weather as one of the top two risks the BES system faces within our footprint, and Hurricane Laura proved this point in spades,” Ponseti said. “And with the addition of the Florida peninsula to SERC, it’s almost impossible for hurricanes to miss the SERC footprint.”
Ten major storms have made landfall in the U.S. this year, including five hurricanes. | SERC
Along with hurricane risk, the merger with FRCC also brought SERC a team of professionals experienced in dealing with severe weather, which the regional entity put to use as Laura approached to draw up a set of restoration guidelines to share with MISO, Entergy, Cleco Power and other utilities in its footprint.
‘Tough Calls’ Needed in Emergency
The guidelines include specific actions to be taken by the various types of entities. However, SERC placed the greatest emphasis on establishing industrywide coordination, with clear responsibilities and points of contact between SERC, MISO and utilities. Such arrangements are crucial for ensuring massive grid damage can be repaired both quickly and safely.
“When you’re in the middle of the event, the utilities of course want to get their members back online. One of the roles of an ISO/RTO is to take that wider system view,” Hillman said. “[That] made us make some tough calls … [because] we were understanding that there were bigger impacts and potentials if more of the system [came] down. … It’s not great to hear, ‘No, you can’t restore those customers yet; no, you can’t get that back online yet; we need to make sure that we’re sequencing this in the right way.’”
Although the arrival of Delta so soon after Laura put pressure on already hardworking crews, Hillman and Ponseti said the second storm did provide an opportunity to test what the entities learned from the first, “as the ink was still drying.” MISO, SERC and their utilities came away from the experience with a renewed appreciation for the fundamental work of thoroughly studying support requirements for extreme weather response; public communication to ensure that customers understand the scope of the problem; and above all, preparing staff through constant practice and assessments.
“You do a lot of drills, and you think to yourself, ‘Oh my gosh, it’s another drill. It’s another black start drill; it’s another system restoration drill,’” Hillman said. “Well, all those drills matter. It’s important to keep our operators trained … because when you’re in the heat of things, you … absolutely do not want to be the person that says, ‘Where do I find that information, and who do I talk to about it? How does that work?’ We didn’t have time to do any of that. And so [the] preparation and drills really played a key part in us getting the system back online.”
MISO is gearing up to draft FERC-mandated rules before it welcomes potentially thousands of distributed energy resource aggregations into its markets.
Last week’s preparation and discussion was in response to FERC’s Order 2222, which directs RTOs and ISOs to allow DER aggregators to compete in their markets. (See FERC Opens RTO Markets to DER Aggregation.)
During a teleconference Thursday, MISO’s Market Subcommittee voted to create a stakeholder task force to handle the work. The Steering Committee is expected to approve the task force’s creation Monday.
“It was 2016 when FERC issued its first DER aggregation Notice of Proposed Rulemaking,” MISO DER Program Director Kristin Swenson told stakeholders. “We’ve been waiting for this a long time.”
Swenson said MISO must create a “coordination framework” for compliance purposes that facilitates communication among itself, regulatory authorities, distribution utilities and DER aggregations. She said the RTO’s many state jurisdictions means the grid operator faces a challenge in creating multiple operating procedures.
“MISO has a tall order in front of us. … We need to learn how to work with each other in a new way to facilitate all of these new resources on the distribution system,” she said. The grid operator will create a new market participation model for DER aggregators, she said.
“Some folks said that this is the first time they’ve seen a FERC order leading the technology development,” Swenson said. “It’s a pretty exciting order.”
Swenson said staff will focus on how MISO can avoid double-counting DERs in metering and telemetry. “How do we avoid double-counting a DER in both the retail and wholesale markets? To be determined,” she joked.
Earlier this year, Swenson said MISO views visibility into DERs as its first challenge.
“We need to obviously understand shifts in pattern [and] in load. If a lot of rooftop solar is installed, for instance, that can affect our load patterns,” she said during the Reliability Subcommittee’s meeting in April. “We’re mindful that we need to better match some of our processes to changes in the industry.”
Swenson said staff continue to look for solutions to MISO’s “aggregation balance problem,” when the market system, burdened with several thousand points of generation, cannot solve. The system could have trouble locating aggregated DERs’ precise location to alleviate reliability issues.
MISO has until July 2021 to submit a compliance filing at FERC. Swenson said she hopes it’s “pencils down” in June to give time for legal staff to review the proposed compliance.
Swenson said the RTO is planning to hold multiple workshops on how it designs its Order 2222 compliance. The grid operator is also supportive of stakeholders and its state regulators’ decision to form a task force to guide compliance, she said.
The Organization of MISO States (OMS) pressed for a state regulator-led task force as soon as possible during a conference call of the RTO’s Steering Committee on Nov. 3.
“OMS is interested in digging in as soon as possible,” Executive Director Marcus Hawkins said.
Some Steering Committee members bristled that OMS would propose a MISO task force with handpicked leadership in mind. Hawkins said he was only giving the stakeholder community a heads-up that multiple OMS members are interested in helming a new task force. He said the usual stakeholder vote on task force chairs would naturally take place.
“OMS is just being transparent with the fact that it will put people forward,” Hawkins explained.
Swenson said coordination with OMS will be pivotal to MISO’s compliance filing.
“We know this is a state-jurisdictional system; so, much of how this order plays out will be determined by the [relevant electric retail regulatory authorities],” she said. “Understanding what the plans are of each state is critically important to us.”
Stakeholders asked during the Market Subcommittee meeting Thursday whether FERC’s rules always necessitate an RTO task force.
“It depends on the complexity of the issue. And this order touches on several areas,” subcommittee Chair Megan Wisersky said.
