WASHINGTON — Former NERC executive Brian Harrell, now assistant director of the Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency, last week lamented the federal government’s tardy response to the security threat drones pose to utilities.
While many utilities are using drones in storm response and in monitoring vegetation growth along transmission lines, drones equipped with explosives could threaten utility operations.
“This is not an emerging threat. It was emerging five years ago,” Harrell told attendees of the NERC Reliability Leadership Summit on Thursday. “We’re clearly cognizant of the fact that you do not own the airspace above your generating facilities, the airspace above … your transmission substations. And right now, the laws are such that the federal government isn’t being as helpful as it should be.”
Last July, Yemen’s Houthi movement claimed it had used a drone to attack a Saudi Aramco refinery in Riyadh. The company acknowledged a fire at the plant but attributed it to “an operational incident.” In August, explosive-carrying drones were used in an attack during a speech by Venezuelan President Nicolás Maduro.
Harrell, who formerly served as director of the Electricity Information Sharing and Analysis Center (E-ISAC) and director of NERC’s Critical Infrastructure Protection Programs, said the federal government has only limited authority over drones but that DHS is preparing a report on security issues posed by the devices.
“I have strongly advocated that whatever recommendations come out of this report must impact, must touch, the private sector,” he said.
A former security director for Duke Energy, Harrell also cautioned utilities on purchasing drones for their own use.
“If you are using foreign-manufactured drones at your facilities, you potentially are incurring risk. So be very, very mindful of that. … Data loss and prevention is [a real threat].”
In 2017, a leaked memo from Homeland Security’s Immigration and Customs Enforcement bureau (ICE) alleged that Chinese drone-maker DJI was “providing U.S. critical infrastructure and law enforcement data to the Chinese government.” DJI, which has been estimated to hold a 70% global market share, responded that the report was based on “clearly false and misleading claims from an unidentified source.”
Harrell said China is “the most active strategic competitor for cyber espionage against the U.S. government, our corporations and our allies. They are stealers of information. Whereas Russia is a … nuisance in one sense, China is actually taking data for their own use.”
WASHINGTON — Assistant Energy Secretary Bruce Walker said Thursday that the Department of Energy is planning a megawatt-scale “Storage Launchpad” that he predicted will cut the cost of energy storage dramatically.
Walker told attendees of the NERC Reliability Summit that funding for the initiative, which will be assigned to one of DOE’s 17 National Laboratories, is included in President Trump’s proposed fiscal 2020 budget, which was released March 11.
“We are going to build a facility … where we can leverage our focus on chemistry. So we’re looking at aqueous, non-aqueous redox equation-type batteries, zinc manganese oxide,” Walker said. “We’ve made some significant breakthroughs already in that space. We believe we’re going to be able to drive the cost down to basically 20% of what it is today over the next five years.”
The budget proposes $5 million for the Storage Launchpad and $15 million “to accelerate the conversion of the National Wind Testing Facility site into an experimental microgrid capable of testing grid integration at the megawatt scale.” The budget would cut funding for DOE’s Office of Energy Efficiency & Renewable Energy by 70% and eliminate the Advanced Research Projects Agency-Energy. Congress rejected similar proposals last year.
Daniel Gabaldon, director and co-founder of Enovation Partners, a Chicago-based consulting firm that does the data analysis for Lazard’s levelized cost of storage report, expressed some skepticism that a $5 million investment could produce such a dramatic return in battery technology but said DOE’s investment would be “a really healthy development.”
Although Enovation doesn’t track the technologies cited by Walker for Lazard, Gabaldon said the prediction of an 80% reduction is in line with claims of early-stage companies pursuing alternatives to lithium-ion technology.
“We’ve seen very dramatic claims, and it would be certainly helpful for the suppliers, as well as potential buyers, to substantiate those claims,” he said in an interview. “Whether it comes to pass, who knows?”
Gabaldon said federal funding is essential for early-stage technologies. The commercial success of lithium-ion batteries for short-duration uses is “sort of shading the forest floor [and denying light to] young shoots of new technologies that — given the right kind of support — could transcend what lithium-ion can do, especially for longer-duration applications, which in the long run will be really essential,” he said.
Kelly Speakes-Backman, CEO of the Energy Storage Association, said “securing an 80% cost reduction on precommercial storage technologies could be possible in the next five years.”
“Investing $5 million in this effort, while modest, is welcomed by ESA,” she said in a statement. “Any investment in the energy storage industry translates into direct job growth here in the United States.”
Bloomberg New Energy Finance’s 2018 Outlook projects a 66% drop in lithium-ion battery pack prices by 2030, largely because of economies of scale.
Grid Resilience Model as a ‘Platform’
In other remarks, Walker told attendees of the NERC conference that DOE’s effort to develop a North American grid resilience model is progressing and that the department hopes to have a static model complete by October. DOE will then work with NERC, FERC, RTOs, DOE’s power marketing administrations and industry to transition it to a real-time model.
“We will continue [working] on this until such time that we’re able to make the real-time piece work and begin to automate the process with the critical infrastructure we’ve identified,” he said.
Walker said the model will be a “platform” on which DOE can test use of the research and development produced by the department’s National Labs.
One technology, he said, could leapfrog synchrophasors, which were introduced after the 2003 Northeast blackout. With sample rates of about 50 times a second, synchrophasors are too slow for “a system that’s as dynamically changing and integrating renewables and dealing with different levels of harmonics and transients like we’ve never seen in the past, with the threat vectors that we’re seeing,” Walker said.
He said the department is drawing on previously developed fiber optic sensing technologies, which sample about 1 million times a second. “We probably don’t need a million times a second, so what we’re going to try and figure out [is] exactly what we do need to be able to see the harmonics and transients that we’re actually seeing on the grid today.”
Walker also promoted the March 28 technical conference DOE and FERC are hosting “to discuss security practices to protect energy infrastructure.”
In January, Walker announced a $1 million Electricity Industry Technology and Practices Innovation Challenge seeking technologies to address vulnerabilities and threats, and mitigate energy sector interdependencies.
Walker said innovations in energy storage could change how the industry looks at reserve margins. “Reserve margins were put back when the system had fuel security and we anticipated two generators and two major transmission lines dropping off the system,” he said.
“That formula doesn’t work anymore because if I ever take out one of your [natural gas] pipelines, you’re going to lose thousands and thousands of megawatts of generation. And so, you’re automatically going to go into underfrequency load shed.
“We’ve got to do something about it. I know through our organization, which is very much focused on R&D, they look at me a little cross-eyed sometimes when I’m like, ‘We don’t have three years to solve this problem. We’ve got like three months.’”
WASHINGTON — The changing resource mix and growth of distributed generation means planners must adopt new models and new mindsets, speakers said at NERC’s biennial Reliability Leadership Summit on Thursday. The event attracted more than 120 RTO officials, utility executives and regulators at the Mayflower Hotel.
David Ortiz, deputy director of FERC’s Office of Electric Reliability, said the growth of renewable generation and distributed resources requires planners to broaden their focus.
“Our general assumption that we can disaggregate this analysis into bulk [power system-] and distribution-level analyses that interact in well-defined and predictable ways is losing its validity,” he said. “Studies of seasonal peak load and traditional measures of resource adequacy and capacity no longer provide a general representation of the reliability of the electric system.”
Ortiz said planners should learn from “the natural experiments that are taking place before us.”
“We can’t randomly assign solar panels to houses and then take a look [at the impact]. They’re just there. But what we can do is pose and assess alternative explanations for observed facts. By doing this in a rigorous way, we can make sure our analysis of the situation is technically sound and is therefore a good basis for decision-making.”
For example, he said, one could hypothesize that the lack of coordination between distributed energy resources and the BPS will cause operators to dispatch plants uneconomically. “We have all the data. We can take a look and determine whether or not that is correct,” he said, posing a second hypothesis. “Or maybe, during times of high distributed energy resource output, transmission constraints will be relieved.
“In the past … it was possible to consider a handful of cases. If we’re going to appropriately and effectively deal with the kind of changes that are coming, it’s going to be necessary to consider not a handful of cases or hundreds, but potentially thousands of different scenarios spanning the complete space of uncertainties in generating resources, access to supporting infrastructure [and] contributions of distributed energy resources.”
The shift will require “prioritizing insight over precision,” Ortiz said, citing the aphorism, “All models are wrong, but some are useful.”
“Models [can] highlight tradeoffs in system investments and approaches to solving problems such as transmission constraints, need for voltage support, integration of DERs, management of inverter-based resources, [greenhouse gas] and criteria pollutant emissions, and other factors. By doing so, planners can support a robust stakeholder process based on a common understanding of the various tradeoffs and then develop appropriate plans.”
Mark Ahlstrom, vice president of renewable energy policy for NextEra Energy, said the increasing sources of uncertainty may require a shift in system operations.
“We still don’t seem to have the commitment to get into actual probabilistic system operations in terms of … dispatch,” he said. “It keeps coming up. It’s complicated. Its computational. But I think that’s something we have to consider … in the future.”
The Impact of Inverters
Peter Brandien, vice president of system operations for ISO-NE, said planners need a “mindset change” as inverter-based resources grow.
“We used to get a lot of services we naturally took for granted from the rotating mass of the generators. … Now we’re trying to [determine] exactly what those services are and put controllable devices on the system to mimic what we used to get from this rotating mass. … We need a mindset that we’re almost protection control engineers on this big machine…
“We have to understand that this system probably needs to be tuned on a regular basis as the resources change. And I think until we accept that concept, then I fear we’re going to run into problems and we’re always going to be one event behind in addressing the problem.”
NERC CEO Jim Robb expressed similar concerns over the organization’s response to the August 2016 Blue Cut wildfire, when 1,200 MW of solar disconnected from the grid. The October 2017 Canyon 2 fire resulted in the loss of more than 900 MW of solar. (See NERC to Try Again on Inverter Rules.)
“The sad thing about that was it took the Blue Cut fire and gigawatts tripping offline for us to realize that we really do have a problem … when I think every engineer knew that that problem was out there,” he said. “But it took an event to mobilize us to start to deal with it.”
David Morton, chairman of the British Columbia Utilities Commission, said regulators must change their
“capacity” by adding engineering talent and “culture” through a willingness to take more risks. For its part, Canada is beginning to use regional modeling “to understand the potential economic benefits of reinforcing limited interregional interconnections,” he said.
“There’s a wealth of analysis of the many benefits of transmission. However, not all the benefits attributable to transmission are exclusive to the actual route or corridor in which it’s constructed,” he said. “There’s often no one to speak, much less decide, on the merits of a given project on behalf of the entire regional market it will affect. Transmission planning and construction should anticipate development of generation resources and access to lower-cost resources in order to avoid significant economic congestion.”
David Weaver, vice president of transmission strategy and planning for Exelon, sounded a similar theme, referring to offshore wind targets set by state officials in New York, New England and PJM. “With these really aggressive state goals, we need to get more proactive about what transmission investment is needed to be able to reliably deliver those renewable resources.”
Weaver asked whether planners also need to consider the impact of climate change and sea level rise. “Do we need storm-hardening standards?” he asked. “Do we need to build our assets at higher elevations above sea level?”
Spotlight on the West
Many of the changes discussed at the summit are being felt most acutely in the West.
Rich Hydzik, senior transmission operations engineer for Avista, said he’s seen changes he never expected.
“In the 15 years I’ve worked in system operations, I’ve never seen a coal plant [output] go up and down regularly. But I see them do it probably six months of the year now between day and night. And that is a big change,” he said.
He also cited California’s excess daytime solar capacity. “If you’d have told me 10 years ago [that] we’d see big time power flow out of California almost year-round during certain hours of the day, I would never have believed it.”
Mark Rothleder, vice president of market quality and renewable integration for CAISO, said that scheduling day-ahead resources on an hourly basis is no longer sufficient because of how much solar output can change within an hour.
“We’re looking at going to a 15-minute granularity … in the day-ahead time frame. We already do it in the real-time [market], but we’re finding it’s increasingly necessary to do that in the day-ahead. We’ve got 7,000 MW of behind-the-meter solar; 12,000 MW on the grid side. So, we see those evening and morning ramps as a significant challenge.”
Minnesota Public Utilities Commissioner Matthew Schuerger said the growth of distribution-level solar means his state needs to incorporate distribution planning into its integrated resource planning, “where they haven’t traditionally been.”
Planners also are having to look differently at how they procure reliability services. “When you planned for capacity, you got everything else: energy, voltage support, frequency response and ramping flexibility,” Schuerger said. “We’re moving out of that world.”
One thing that won’t be changing, said Thad LeVar, chairman of the Public Service Commission of Utah, is the IRP process itself.
LeVar said the proposed addition of a day-ahead market in the Western Energy Imbalance Market has “real potential.”
But he said his state won’t be signing up if it means the end of IRPs.
“I think I’m safe in predicting that Western states like Utah are not — at least in the near future — going to express an interest in joining an RTO that has authority over resource adequacy and system planning,” he said. “The IRP model is going to continue to be a bedrock principal in the Western U.S. in the near term.”
Below is a summary of the issues scheduled to be brought to a vote at the PJM Markets and Reliability and Members committees on Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be in Wilmington, Del., covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Markets and Reliability Committee
Consent Agenda (9:10-9:20)
Members will be asked to endorse the following manual revisions:
B. Manual 13: Emergency Operations: Updates language to align with both NERC EOP-004-4 and OE-417 reporting requirements in Attachment J, relating to disturbance reporting.
C. Manual 20: Resource Adequacy Analysis: Periodic cover-to-cover review includes minor grammatical corrections and updated language to reflect implementation of Capacity Performance. Removes references to demand resource factor and deletes sections 5 and 6, which relate to demand-response reliability target analysis procedures and limited-availability resource constraint procedures, respectively.
D. Manual 37: Reliability Coordination: Periodic cover-to-cover review that includes minor grammatical updates and annual changes to transmission owner designations. Adds PJM’s Reliability Plan to attachment A and updates appendix D to include AMP Transmission as a TO.
1. Deficiency Cure Periods (9:20-9:30)
PJM will ask stakeholders to endorse changes to Manual 14A: New Services Request Process and the Tariff that would give customers 10 days to fix minor errors in interconnection requests whether they submit their application on the first or last day of the new services request window. (See “Quick Fix for Queue Filing Errors Endorsed,” PJM PC/TEAC Briefs: Feb. 7, 2019.)
It would be effective with queue AF1, which opens April 1.
2. Fuel Security Problem Statement and Issue Charge (9:30-10:00)
PJM will seek endorsement of its plan to address potential fuel security threats, even though stakeholders called the proposed 12-month timeline for drafting Tariff changes too aggressive last month. (See “Stakeholders Urge Slower Timeline on Fuel Security,” PJM MRC/MC Briefs: Feb. 21, 2019.)
Stakeholders will be asked to endorse a problem statement and issue charge centered on ensuring grid reliability during times of extreme stress. It would create a senior task force reporting to the MRC with a schedule calling for a task force recommendation by September and a FERC filing in December.
PJM drafted the problem statement as part of a three-phased approach for ensuring the resilience of its generation portfolio. Staff completed the Phase 1 analysis in December, saying that while no imminent risk currently exists, the RTO should explore proactive, market-based mechanisms for retaining or procuring fuel-secure resources. (See PJM Begins Campaign for Fuel Security Payments.)
The D.C. Office of the People’s Counsel has drafted an alternative problem statement and issue charge that would have stakeholders evaluate “energy” security rather than PJM’s focus on “fuel” security and would provide education on the roles of DR, renewable resources and energy storage in ensuring energy security. It also would require the RTO to provide a probability level of risk for all options and mandate a “rigorous cost-benefit analysis” for any rule changes.
Members Committee
1. Meeting Locations (1:25-1:55)
Members will vote on a proposal to move future MRC and MC meetings to PJM’s Conference and Training Center in Valley Forge, Pa.
Katie Guerry of Enel X proposed the location changes during the Feb. 21 MC meeting, saying the center provides stakeholders cost efficiencies, as they have access to PJM staff and resources while they are there. (See “Stakeholders to Consider Retiring Wilmington as Meeting Site,” PJM MRC/MC Briefs: Feb. 21, 2019.)
HOUSTON — Last week’s 38th annual CERAWeek by IHS Markit brought together a record 4,300 global energy movers and shakers, including 35 ministers and other government officials, from more than 70 countries.
Panel discussions and speakers in more than 400 sessions focused on geopolitics, trade and costs, price volatility, environmental policy, disruptive technologies and the battle to attract the workforce of the future.
Energy Secretary Rick Perry was a ubiquitous presence during the week. He and his staff held bilateral meetings with 10 countries and also met with power CEOs, LNG exporters and U.S. National Lab representatives. When Perry wasn’t in meetings, he was glad-handing potential investors and customers for U.S. LNG and other petroleum products.
“I have the coolest job in the world. I have a front-row seat to some of the most astonishing examples of cutting-edge innovation,” he said during his keynote address Wednesday. “We’re approaching the dawn of a new American energy era, where we embrace new and smarter ways to reach our energy and environmental goals.”
Perry drew mild twitters of disbelief when he noted Texas, the state he governed for 14 years, now produces 15% of its total energy from wind and solar resources, “more, percentage-wise, than our friends in Europe.”
“We [the U.S.] expect to become a net energy exporter next year, and for the next 30 years,” he said. “Thanks to innovation, we’ve got more than enough energy to share with the world.”
Perry said the U.S. needs to emphasize innovation over regulation, referring to the administration’s all-of-the-above energy policy that focuses heavily on petroleum exports. Central to that is increasing exports of LNG to energy-hungry markets in Latin America, Europe and Asia, many of whose energy ministers pleaded with him to keep the U.S. in the Paris Agreement on climate change.
“We would go into the [bilateral discussions], and they would say, ‘How about [us] buying some of that LNG you guys got?’” Perry said, leaning over in his chair as if whispering to his moderator.
Meeting with the media after his keynote, Perry addressed the Green New Deal resolution being championed by freshman Rep. Alexandria Ocasio-Cortez (D-N.Y.). The resolution calls for, among other items, securing 100% of the nation’s power demand through “clean, renewable, and zero-emission energy sources.”
Naturally, the Green New Deal has drawn significant political and energy industry pushback.
“How we get there — is it this number or this number? — is where good negotiations start,” Perry said. “I don’t think [Ocasio-Cortez] should be castigated and pushed aside, just on the face of her comments, in that she wants to live in a place where’s there’s clean air and clean water. So do I. The question is, how do we get there?
“I hope to help her understand what we have done over the past decade with the shale revolution … what LNG has done, and how we can get that to China or India. How we can bring carbon capture or [other technologies] into countries where they don’t have it,” he said. “I think she and I would say those are both goals … places we can agree on, that we don’t have to be disagreeable. I’ve been in this business for a spell, and I’d rather be agreeable.”
The commission in early 2018 unanimously rejected the Department of Energy’s Notice of Proposed Rulemaking that it order RTOs and ISOs to compensate coal and nuclear generators with 90 days of on-site fuel their full operating costs (RM18-1). At the same time, FERC opened its own resilience docket (AD18-7) and directed grid operators to respond to questions on how they assess resilience. (See DOE NOPR Rejected, ‘Resilience’ Debate Turns to RTOs, States.) The commissioners said they will use the responses to determine whether additional action is necessary.
“We have a keen understanding of the urgency of doing this analysis, but this is so, so significant and important,” Chatterjee said during a media briefing in explaining there is no timeline for taking action. “This is about getting it done right, and doing this in a thoughtful and deliberate, evidence-based way.
“We have a rich and robust record before us. What are the attributes that are necessary to grid resilience? Once we make that determination, is there a long-term or short-term threat to grid resilience?” he said. “It’s just a really, really complex undertaking, so important we are being very thoughtful and making sure we get it right. Whatever action we take must withstand legal scrutiny and present a record that is fact-based.”
Chatterjee said Perry showed “leadership” by raising the issue of grid resilience.
“People are now talking about [grid] reliability and resilience in the same breath.”
For his part, Perry said he has “thrown a lot of Jell-O at the walls to find a solution the majority of us can support.”
“Yes, there are ways to generate power that is cheaper than coal and nuclear. With the prices of natural gas today, you can generate your electricity substantially cheaper than certainly coal or nuclear,” he said. “Gas is cheaper, but it’s interruptible. Are you willing to take the chance to save money on this side, with the chance to losing power over here?
“Is the money spent on baseload electricity worth it?” Perry asked. “I happen to think it is, to have an all-of-the-above energy structure. This is a really fascinating conversation we need to have. We are looking for the answer to a question that vexes us right now.”
DOE Trying to Make CCS ‘Sexy’
A panel debating carbon capture and sequestration agreed it’s not a sexy field right now, but help could be on the way.
DOE Under Secretary of Energy Mark Menezes took advantage of the moment to announce $30 million in funding opportunities for two front-end engineering design (FEED) studies for carbon dioxide capture systems. The projects will support FEED studies for CO2 systems on both coal and natural gas power plants.
“We’re looking for scale-up technologies,” Menezes said, saying the funds can be used for both retrofitting existing units and designs on new facilities. “All the new generation is natural gas or renewables. We need to take away minimizing economic incentives for the CO2 we produce every day. For so long, we’ve been pointing the finger at who’s responsible. We’ve got to stop that and understand it’s in the global interest to do something with these [generation] byproducts.”
Pratima Rangarajan, CEO of OGCI Climate Investments, followed Menezes’ announcement with one of her own: the organization’s annual Carbon Capture, Utilization and Storage Investments Day in September, at a date to be announced.
“We’re inviting the DOE to participate,” Rangarajan said. “We don’t think we can [make carbon capture a reality] without carbon capture storage in the United States. We need to stop [CO2] from going into the atmosphere, just like we do with plastic bottles so they don’t go into the ocean. We have to show it’s another way to have a low-carbon energy source that can create jobs and be an energy source, even if it’s not sexy.”
Stanford University professor Sally Benson called for a five-fold increase in CCS, saying a lack of governmental subsidies has stunted the sector’s growth. Many are waiting for the IRS to issue guidance on its Carbon Oxide Sequestration Credit, for those facilities using carbon-capture equipment “originally placed in service at a qualified facility before Feb. 9, 2018.”
“Why the resurgence of carbon capture sequestration now?” Benson asked. “For some people, it’s the financial incentive. For others, it’s, ‘Oh my God! This is really scary! Change is really upon us.’”
McNamee, Chatterjee Laud LNG Project’s Approval
FERC Commissioner Bernard McNamee, who joined the commission in December, said the commission’s recent order approving the Calcasieu Pass LNG export terminal showed some things still work in D.C. (See LaFleur Sides with Republicans on LNG Terminal as Glick Dissents.)
“It’s a great opportunity … to export the abundance of natural gas that we have. Everyone talks about so much dysfunction in Washington, but I thought it was also a great example that we were able to come together and compromise to make this work,” said McNamee, who was joined by fellow Republican Chatterjee and LaFleur in the 3-1 decision. (Democratic Commissioner Richard Glick dissented.)
“We have to determine whether [an order] is consistent with the public interest, but there are a lot of issues that go with that,” he said. “We have to take a hard look at the environmental issues … these are all important things that have been delegated to the government to make sure they’re in the public interest.”
Chatterjee credited McNamee and LaFleur with negotiating a computation of greenhouse gas emissions as the commission approved its first LNG project in two years. FERC has 12 more proposed LNG projects before it.
“I’m optimistic because the biggest speaking point in negotiations had been around greenhouse gas emissions,” Chatterjee said. “Now that we have the greenhouse gas question answered and a framework in place, I’m really optimistic it will enable us to approve some of the projects in front of us.”
NRG’s Gutierrez a Fan of Competitive Markets
NRG Energy CEO Mauricio Gutierrez may be a states’ rights advocate when it comes to environmental policy, but not when it comes to competitive markets and the grid.
“States have absolutely every right to determine their environmental policy. If they want to have a renewable portfolio standard, or a clean energy standard for their constituents, they have absolutely that right,” he said during a Thursday media briefing.
“Where I have a different opinion is they can’t do it at the expense of competitive markets. Competitive markets work, and they work very well,” Gutierrez said. “We have to define the attributes we want from the grid and let competitive forces determine the best way to meet those attributes. American history has told us that competitive markets are the most efficient way to provide consumer benefits. I think that’s the same in the electric markets.”
PROVIDENCE, R.I. — Offshore wind will soon be comparable in scale to other renewable energy resources such as onshore wind and solar, participants at the quarterly meeting of ISO-NE’s Consumer Liaison Group heard last week.
New England never had natural gas or oil and has always had to pay for energy imports, but the region’s luck is changing with offshore wind, said Jeffrey Grybowski, co-CEO of Ørsted US Offshore Wind.
“Offshore wind has no size constraints like there are onshore,” Grybowski said. He cited the ever-growing size of commercial wind turbines as proof: Siemens (8 MW), Vestas (10 MW) and General Electric (12 MW).
“Each one of these manufacturers tries to one-up the other,” he said. “The projects are getting larger, reducing costs, and Ørsted is now working on a 1.2-GW project off the U.K.”
The lucky break for the region is that big load centers along the Northeast coast match the location of the highest offshore wind generation potential, Grybowski said.
“In addition, New England super-peak days in winter coincide with what are normally the highest production times for offshore wind here,” he said.
On the solar front, Acadia Center projects the region, combined with New York, will have 24 GW of distributed solar installed by 2030, plus about 12 GW of utility-scale solar.
“The economics of siting solar farms is driving developers to large, flat, forested sections of land, and this isn’t Kansas,” said Erika Niedowski, the center’s Rhode Island director and policy advocate.
According to the state’s Energy Plan, Rhode Island could develop more than 1,800 MW of solar by 2035, compared to the current 105 MW. “But we need to be developing clean energy with a balanced approach, with environmental considerations,” Niedowski said.
Douglas Gablinske, executive director of the Energy Council of Rhode Island, joked about the increasing resistance among New Englanders to any kind of new energy infrastructure: “I’ll introduce a new acronym to the sector, NWN, for ‘nobody wants nothing.’”
Under the proposal’s two-settlement structure, resources would be paid or charged for deviations between the inventoried energy purchased in a forward position for the entire winter season and the spot settlement rate — representing energy maintained during each trigger condition.
ISO-NE estimates the voluntary program will have direct costs of $112 million to $158 million a year. George noted that “the markets work together, so though this will be a payment through the energy market, when that’s dealt with in the capacity market the net cost is likely to be a lot less than that.”
The New England Power Pool Participants Committee on Wednesday rejected the RTO’s interim proposal, which would cover capacity commitment periods 14 (2023/24) and 15 (2024/25). Despite the proposal receiving less than 33% vote in favor, the RTO will move ahead with its filing. Members also rejected a proposal by energy services firm Energy New England (ENE) that would have limited compensation to oil and certain natural gas, demand response and electric storage resources.
Meg Lusardi, executive vice president of PowerOptions, the largest energy-buying consortium in New England, also questioned the RTO’s reasoning.
“The interim program … we refer to it as winter reliability on steroids,” Lusardi said. “The program failed to win passage at NEPOOL, though how that will affect decision-making at FERC is hard to say.”
PowerOptions signed on to a study by Synapse Energy Economics last May that showed the RTO’s January 2018 fuel security analysis to have been too conservative, which resulted in overplaying the risk of rolling blackouts, she said.
“There are cost impacts to customers with all of these market mechanisms that are going on, and it is complicated,” Lusardi said. “We all know that Mystic is being paid to run for 2022 to 2023, and maybe for 2023 to 2024, and this has been approved. The estimated cost for that is $200 million a year, so customers are going to have to take on that cost.”
George also mentioned that the RTO’s enhanced storage participation rules go into effect April 1, 2019. In February, FERC accepted Tariff revisions that enable batteries and other emerging storage technologies to more fully participate in the region’s wholesale electricity markets. (See FERC Accepts ISO-NE Storage Tariff Revisions.) But still pending before the commission is the RTO’s December 2018 filing that demonstrates full compliance with FERC Order 841.
Transformation of the Rhode Island power sector extends beyond grid modernization, said Jonathan Schrag, deputy administrator of the state’s Division of Public Utilities and Carriers.
“The larger power sector transformation … includes the work that the Office of Energy Resources is leading on procurement of clean energy resources … and the work that our Public Utilities Commission is leading on guidance for the way we do performance incentive mechanisms,” Schrag said.
The transformation also includes work his agency is taking on in collaboration with OER on non-wires alternatives, he said.
“We’re not just technology-agnostic, but hostile to any particular one” being pushed over any other, Schrag said.
Since the state deployed the bulk of its advanced meters between 1999 and 2003, most “are aging out now,” requiring state officials in the next few years “to make some critical choices around a very large distribution system asset.”
One strategy for the state is not so much “to promote electrification, but to optimize it,” he said.
“Rate design is a big deal,” said Timothy Hebert, COO of ENE, which serves municipal power companies. “What’s driving cost structures for customers is really changing. Around some of the new strategies that are being employed — distributed generation, storage — we’ve seen a lot of interest at the municipal utility level in developing electric vehicle programs.”
Regarding EV charging, Synapse’s Paul Peterson noted ISO-NE performed a 2016 economic study that showed one scenario with 3 million EVs in New England by 2030.
The RTO modeled the EVs to charge at night, “ran the model, and the problem was now the peak occurred at night,” Peterson said. “So then they told the model to charge the EVs at off-peak hours, and there was virtually no change to peak demand in the model, with or without the EVs, and the actual electrical energy used is not terribly significant.”
Data cannot be talked about enough, as there are so many additional layers of information to look at these days, Hebert said.
“We have a lot of different things happening … a dance going on every day.”
CAISO’s RC West Oversight Committee held its first monthly meeting Thursday at ISO headquarters in Folsom, Calif., as the grid operator prepares to assume the reliability coordinator role for most of the West this year.
CAISO Operations Center | CAISO
Among the committee’s first orders of business was to elect a chair, Michelle Cathcart, vice president of transmission system operations with the Bonneville Power Administration, and a vice chair, Steve Cobb, director of transmission and generation operations at Arizona’s Salt River Project.
The election was an important step “because we really would like to make sure we’re hearing clearly from you, our customers, on how we should be operating this RC,” Phil Pettingill, CAISO’s director of regional integration, told those in the room and on the phone. “That’ll really set things up for us going forward.”
Michelle Cathcart and Steve Cobb were elected chair and vice chair, respectively, of the RC West Oversight Committee. | CAISO
Cathcart and Cobb have been serving in their roles for some time but were officially elected by committee members without opposition on Thursday.
RC West, as it’s now called, has secured agreements from 39 entities in the Western Interconnection, including Arizona Public Service, PacifiCorp and Seattle City Light. Its footprint stretches from the Canadian border into northern Baja California, and from the Pacific Ocean to the Rocky Mountains.
CAISO plans to become the RC for its current territory in California and Mexico on July 1. BC Hydro will become the RC for most of British Columbia on Sept. 2. CAISO will then take over for many areas outside its footprint on Nov. 1, while SPP will take responsibility for other parts of the West on Dec. 3.
RC West has hired 18 reliability coordinators from Peak Reliability, CAISO, MISO, PJM and ERCOT, among others. CAISO set up around-the-clock control centers in Folsom, adjacent to the ISO’s main control room, and at a separate location in Lincoln, Calif., which is also in the Sierra Nevada foothills near Sacramento.
CAISO reliability employees will start shadowing Peak staff on May 1. The ISO is undergoing an RC certification process by the Western Electricity Coordinating Council that is expected to last until Oct. 1.
CAISO is slated to take over RC responsibilities for most of the West this year. | CAISO
The RC West Oversight Committee’s members include representatives from balancing authorities and transmission operators throughout CAISO’s RC territories. Its purpose is to provide input and guidance to CAISO’s RC management team on matters related to the RC function including operational issues, policies and procedures, and new tools or staffing that significantly affect the budget and costs for RC services.
The committee is planning to meet monthly throughout 2019. Its next meeting will be a webinar on April 17 followed by an in-person meeting May 21 in Folsom. The committee has its own webpage on CAISO’s site.
“We’re pleased that the ISO’s RC West is achieving targeted milestones and on track to begin operations later this year,” CAISO CEO Steve Berberich said in a news release upon the committee’s formation last month. “We welcome the participation from balancing authorities and transmission operators throughout the western United States, Canada and Mexico, and view this as a positive example of regional collaboration.”
MISO says it will rely on the same set of futures for the third straight year when it evaluates transmission projects in its 2020 Transmission Expansion Plan (MTEP 20) — but some stakeholders are eager for a rewrite of the scenarios.
The RTO announced the decision at a Thursday workshop on MTEP 20 futures development after proposing last month to recycle the futures with limited demand, capital cost, fuel price, retirement and renewable data revisions. But some members have argued that MISO’s limited fleet change future is no longer a likely scenario, and others have asked for more integration of the RTO’s ongoing, multiyear renewable generation study. (See “MISO Proposes Virtually Unchanged MTEP 2020 Futures,” MISO Planning Week Briefs: Feb. 12-13, 2019.)
MISO in 2017 created four future scenarios for use in MTEP planning, including:
limited fleet change, in which the fleet remains relatively static with coal units retiring at the end of their useful life;
continued fleet change, in which the grid develops according to the trends of the past decade;
accelerated fleet change, driven by a strong economy that increases demand and motivates carbon regulations and increased renewable use; and
a future in which distributed and emerging technologies become more widely used.
Veriquest Group’s David Harlan questioned whether the scenarios still capture the “bookends” of possibilities in the future. He pointed out that MISO could approve a major transmission project that looks useful under all four futures but proves not to be as beneficial as expected.
“There is a fairly large appetite to think about updating futures for the next cycle,” Harlan said. He also asked for MISO to provide more transparency into how it assembles futures assumptions.
The Union of Concerned Scientists’ Sam Gomberg said the futures “continue to underestimate the pace of renewable generation deployment across the region.”
In written comments submitted to MISO, the UCS said, “In particular, the limited fleet change future presents an unreasonably low assumption. … While we agree with MISO’s assertion that there have been no significant changes to state or federal policies to warrant new futures narratives, other significant drivers of renewable deployment have emerged in recent years and continue to accelerate renewable energy penetration levels.”
But NextEra Energy said, “Extensive updates to the base data are warranted.”
“The most significant economic changes have been cost reductions and technological improvements for wind, solar and battery storage generation. This has fundamentally changed the long-term value proposition of these technologies,” NextEra said. The company also pointed to 10 MISO utilities that have significant renewable or carbon reduction goals.
On the other hand, DTE Energy and American Transmission Co. said MISO’s plan to merely refresh its futures’ base data for MTEP 20 was appropriate. WPPI Energy said didn’t see an urgent need to revamp the futures for MTEP 20, but it asked MISO to plan an extensive retooling for 2021.
Consultant Roberto Paliza questioned whether MISO was properly considering recent climate change studies, electric vehicle expansion, corporate promises to get energy sourced from renewables and several utilities’ decarbonization commitments in the next decades.
There’s a “new potential reality,” he said. “I’m concerned that major transmission expansion will be made without focus on future possibilities that are not covered by these futures.”
“Today that hasn’t been hard-baked into the futures, but it’s an important conversation to have,” agreed MISO Planning Manager Tony Hunziker.
Hunziker said that even though MISO’s goal is to reuse the MTEP 19 futures for 2020, the RTO could incorporate some minor changes if “there’s critical mass on agreement” and it has the manpower, technical capability and time to make them.
But Minnesota Public Utilities Commission staff member Hwikwom Ham said the main uncertainty is load growth, more so than retirements and renewable penetration.
MISO will hold another workshop on the subject next month and expects to finalize MTEP 20 futures sometime in June.
MISO last week released draft Tariff language that would allow energy storage resources to compete for projects in the RTO’s annual Transmission Expansion Plan (MTEP).
The provision would allow storage-as-transmission assets (SATA) to pursue consideration in all classes of RTO transmission projects, including baseline reliability, market efficiency and multi-value projects, as well as market participant-funded upgrades.
During a Planning Advisory Committee meeting Wednesday, MISO Director of Planning Jeff Webb said the RTO would work with stakeholders on full Tariff revisions through May.
| Invenergy
The rules would apply only to storage assets functioning strictly as transmission. Those assets would be able to bid for all transmission project types and be eligible for any associated MTEP cost allocation methodologies. MISO had originally proposed that SATA only be allowed to solve transmission reliability needs but changed course last month at the urging of stakeholders. (See MISO Opens Storage Proposals to All Tx Project Types.)
However, some stakeholders from the Transmission Dependent Utilities sector still contend that storage should be restricted to solving just reliability needs.
“Our feeling is that this is a significant expansion of the [original] scope,” WEC Energy Group’s Chris Plante said. “Expanding this to market efficiency projects is perhaps a bit much in the first phase of this.”
“The reason we’re doing this is stakeholders implied it was discriminatory to carve out reliability services from the FERC policy statement,” Webb said, adding that he didn’t think it appropriate for MISO to “call the shots” on the types of transmission projects available to storage.
MISO currently has “at least one” battery up for evaluation in MTEP 19 to solve a reliability issue, Webb said.
“I think it’s going to be challenge,” Webb said of the SATA modeling and selection process. “I think it’s a reality that we may never select a storage facility, and by that I mean [meeting] the planning, modeling and evaluation process. … We’re going to have to have a compelling reason to provide cost-based recovery, cost allocation to a storage device that can also provide market services.”
The draft language also notes that MISO is not yet detailing how a storage asset could function as both transmission and generation. “Subsequent phases of policy development will address those issues necessary to permit mixed-mode operation of providing both transmission and market services,” MISO said. Webb called the language a “temporary prohibition” and said future discussion would focus on how SATA could also maintain a market presence.
Load-shedding Considerations
But some members asked if MISO would leverage fully charged SATA during a maximum generation event to avoid shedding load.
“I think that’s an extremely interesting question. I think MISO would be doing a disservice if they didn’t take advantage of that,” WPPI Energy’s Steve Leovy said. “I think we should use fully charged batteries to avoid load shedding whether they formally have the title of … SATA.”
“I’ll have to think about that,” Webb responded. “What we would not want to do is use the resource as a generation asset to relieve a resource adequacy issue.” He said MISO would probably use the asset merely to resolve transmission constraints in order to keep the lines between generation and transmission distinct.
No non-TO Authorization
MISO’s draft proposal also stipulates that SATA can be owned only by those designated as transmission owners. It did not address last month’s proposal by DTE Energy to allow non-TOs’ storage assets to be eligible for cost recovery for providing transmission services. (See “Non-TO-owned SATA?” MISO Opens Storage Proposals to All Tx Project Types.)
After the February discussion, PAC leadership determined that DTE’s request raised complicated and out-of-scope cost-recovery questions. They directed the topic to the Steering Committee, where new topics in the stakeholder process are assigned to corresponding committees.
“We were really interested in seeing the follow-up to that discussion,” Clean Grid Alliance’s Rhonda Peters said.
“This has other elements beyond even treating storage as traditional transmission or generation. People can disagree with that assessment on our part,” Webb said.
MISO plans to revamp its annual Transmission Expansion Plan (MTEP) report to emphasize the justifications and analyses behind the list of proposed projects while removing some planning process narratives.
Director of Strategy Jesse Moser said Wednesday that the streamlined MTEP report will focus more sharply on the business cases for transmission projects.
“We think some of these changes will make the report more user-friendly with a few resource efficiencies along the way,” Moser said during a March 13 Planning Advisory Committee meeting.
MISO’s last five MTEP reports have typically stretched to about 200 pages.
“Over time — I think the first MTEP report was MTEP 03 — it’s grown and grown to include everything related to our transmission planning process,” Moser said. He said the report currently includes “a lot of repetitive, boilerplate” descriptions of the planning process that could be relocated to MISO’s website. He added that some compliance-necessary language must remain.
MTEP 18 full report cover | MISO
Moser said last year’s report included a late addition of load shape forecast changes, which “wasn’t necessarily tied to transmission projects being approved in that cycle” and ultimately delayed the PAC’s vote to recommend the report.
Instead of detailing the planning process, MISO could create a more exhaustive executive report that explains industry trends and summarizes important stakeholder decisions in the year, he said.
MISO is also proposing to scrap the report’s first draft review before the PAC that historically takes place in early August. The committee would get its first look in September under the proposed changes.
“What we’ve found historically is that it’s pretty early in the process and we’re still wrapping up the report. Sections of the report vary in terms of completeness. We’ll have a more complete product for review,” Moser said.
Moser said one less review would also cut down on stakeholders’ workload.
Consultant Roberto Paliza asked if stakeholders found the current report “tedious or impenetrable,” or if MISO staff are introducing the change independently.
“This is our initiative. We’ve had this in mind for several cycles now,” Moser replied.
But some stakeholders said the existing format provides a good historical — and preserved — record of reasons behind transmission project decisions.
“The problem of including website links is they’re volatile,” Paliza said. He pointed to MISO’s 2017 website redesign where, in some cases, web pages and previously accessible information were lost. “I think it provides a very important memory of what went on in the system of MISO.”
Other stakeholders said they were concerned the new schedule excises an entire month of stakeholder feedback and compresses the time allotted for stakeholder review from four months to three.
But staff said putting an incomplete draft report forward for review creates more confusion than necessary.
“When you get the report, it should be substantially complete,” Director of Planning Jeff Webb said.
“I think it’s probably good for the stakeholders and the board to have a very focused MTEP report,” PAC Chair Cynthia Crane said.
However, Crane asked for a more detailed discussion on what exactly would be removed from the report.
Moser said he would return to the April PAC meeting with more specifics. He also said the move will be discussed before the Board of Directors next week to outline what a more streamlined report might look like.
