CARY, N.C. — Thanks to smart meters, phasor measurement units (PMUs) and the forecasting challenges of renewable generation, utilities and RTOs are becoming increasingly voracious consumers of data.
“Instead of getting SCADA data every four seconds,” notes Stephen Rourke, vice president of system planning at ISO-NE, “we’re getting PMU data every two cycles.”
But some are not using the information as well as they could, speakers said at the RTO Insider/SAS ISO Summit at SAS headquarters last week.
“The amount of operations data that’s being created is just incredible,” said Bill McEvoy, industry principal for OSIsoft. “And a lot of it is still being created in silos.”
That’s a mistake, said Jill Dyché, vice president of best practices at SAS. While many companies perform only “random acts of analytics,” forward-thinking organizations have created analytics “Centers of Excellence,” she said.
“Analysis is a collection of very distinguished skill sets that may not exist elsewhere in the organization, so there’s an argument for leveraging those in a sustained way through some kind of COE or marketplace,” she said. “For energy companies, the potential is not just in optimizing our business but also becoming data businesses. There’s a huge potential in using our data in fresh new ways.”
Data Quality
Most companies fail to measure the cost of poor, missing or inaccurate data. “Typically when I get a ‘yes’ on that question, it’s after the fact,” Dyché said. “We realize that a business initiative failed because we didn’t have the data, or the data was wrong,” she said. “Data quality can make or break some pretty serious decisions these days.”
“I think it’s wise to watch where your numbers come from,” said Brad Lawson, a SAS industry consultant. “Working in the utility industry, we could never get customer numbers to match. You went to one group and there was a customer count of whatever. The next group may be 10,000, 15,000 more. So we finally got a group together to talk about, what is a customer? What we found within this utility was that we had about seven different definitions of ‘customer.’”
Similar disparities exist in data on solar capacity and generation, he said, complicating utilities’ forecasting challenges.
Forecasting EV Charging
Electric vehicles are a growing concern for utility forecasters, particularly in California, which has more than 40% of the EVs in the U.S.
“The utilities would like to be able to manage that charging,” said Ralph Masiello, senior vice president of Quanta Technology. “In other words, if everyone comes home from work [and] plugs the car in at 6 p.m., that’s right when that duck curve is ramping the worst. So it’s the last time that you want another 1,000 MW of EV charging.
“The big data need for the utilities is how do they know when those customers are going to plug in? And the answer is they’ve got to monitor [the California Department of Transportation] for traffic conditions. Because a traffic accident on Interstate 405 can mean 1,000 Teslas plugging in a half-hour later than they normally would.”
Data Volumes Taxing Hardware
As one of the biggest users of data analytics at ERCOT, Manager of Demand Response Carl Raish is looking forward to a refresh of the ISO’s hardware platform. “I’m hopeful that this hardware change is going to make my life better. I’ve done what I could with software in terms of trying to leverage capabilities that are in SAS to make code run better. But it’s really the volumes of data [that are challenging] at this point.”
Helping to provide answers to RTOs’ challenges is the Electric Power Research Institute. EPRI’s Market Design research group has created webcasts and an ISO/RTO Market Design Tech Forum, in which technical market designers discuss the challenges of changing markets. Its Market Design and Operations Research Program provides analytical support for research projects.
Erik Ela, senior technical leader of EPRI, said the organization is tackling the industry’s biggest research and development challenges, including providing adequate compensation to prevent retirement of resources that are not used often; incentives to encourage system flexibility; pricing schemes; and incorporating policies that favor technologies for reasons other than cost.
ISO markets currently dispatch resources based on reliability and cost, Ela noted.
“But there are a lot of other things that we don’t do at the ISO. We don’t have an environmental [input in market clearing engines]. We don’t care about job preservation. … Fuel diversity is very hard to quantify. So there’s a lot of these other aspects out there that a lot of the states have a lot of incentive to try to keep … [But] that’s not built into the way we clear our markets.
“So how do we interact with these policies in the way that we are running the markets? That’s a big area and [one] I think that we’ll see more and more questions about.” (See related story, Ott Seeks ‘Resilience’; Clark Handicaps ZECs.)
CARY, N.C. — Despite a late spring Nor’easter that closed airports and forced some speakers to participate via phone, dozens of RTO and ISO officials journeyed to SAS’ snow-free campus in North Carolina last week for a discussion on data and technology challenges. Here’s some of what we heard at the RTO Insider/SAS ISO Summit.
Duck Curve, Meet Armadillo Shell
The duck curve — which came out of California to describe the ramping challenge provided by solar resources — has since been adopted as a term by other regions, including ISO-NE. (See “New England’s Duck Curve,” Overheard at NECA Renewable Energy Conference.)
But not in Texas, if Kenan Ögelman, vice president of commercial operations for ERCOT, has his way. Texas, which has led the nation in wind development, is starting to make strides with solar as well.
So Ögelman is pitching an alternative description: an armadillo on its back. “The belly of the duck is the shell of the armadillo,” he explained.
As in California, solar generation stops just as demand is rising to its daily peak. But Texas’ width may make it a bit easier to manage the ramp. “Because most of our load centers are in the center and the east … of Texas, and most of the highest potential solar is in the west, we might be able to buy ourselves … an extra hour there potentially because Texas is so big.”
When solar is wanting to dispatch and use the grid, that isn’t necessarily overlapping with wind as much so there might be some … complementary ability to use the grid.”
California, meanwhile, will be releasing a new version of the duck curve soon, said Lorenzo Kristov, principal for market and infrastructure policy for CAISO.
The new curve is necessary, Kristov said, because solar has grown so fast that the duck curve is playing out four years ahead of projections.
“We actually hit 11,000 [MW] net load last year — that’s just below what we forecasted for 2020,” he said. “And we actually hit this very steep ramp — the 13,000 [MW] that was … the projection for 2020 — we hit it in December 2016.”
The California Energy Commission’s 20-year forecast for rooftop solar adoption is updated every two years. “And invariably the forecast they did two years ago is way lower than the forecast when they revise it two years later,” Kristov said.
One other development: Peak demand is coming later in the day. “The solar starts to reduce the magnitude of the normal peak hours, leaving a residual peak that happens a little bit later because the air conditioning is still running, but the sun has now gone down,” he said.
RTOs, Retail Choice Help Walmart Meet Renewable Goals, Cut Costs
As Walmart’s director of markets and compliance, Chris Hendrix is charged with controlling energy costs while meeting the retail giant’s goal of obtaining half of its electricity needs from renewable power by 2025.
That has led the company to set up its own energy supply company to power its 4,500 Walmart and Sam’s Clubs locations in the U.S. It also has invested in more than 400 renewable generation projects, including wind in Texas and solar in California, Arizona, Massachusetts and Connecticut. “In ERCOT, about 30% of our load is [served by] wind. It’s going to grow over time,” Hendrix said, citing two projects under construction.
“Not only are we buying power, we’re also a market participant in all the ISOs. … We have a retail supply license in 11 states, plus the U.K. We just act like everybody else, your Direct Energy, your Constellations of the world. The only difference is … I don’t have a sales force and I don’t have customer parallel on the backside.” His customers are the store managers.
“Every single market, every single co-op, every single utility, we’re there. So we have a good cross-section of the U.S. markets,” he said. But only ISO/RTO markets and states with retail choice give him all the tools he needs to do his job, he said.
“The only way that we’re able to buy large-scale renewables is through an ISO,” he said. And ISOs and RTOs with retail choice provide transparent LMPs that allow price hedging.
“Where we run into problems is in parts of California, where we don’t have choice, [and] SPP [and] MISO, where we’re exposed to an average price. It may not even be a time-of-use price. … So that’s not really setting the right price signal for us to implement renewables or energy efficiency or demand response, because all I have is a flat price of 7 cents/kWh.”
Alberta Capacity Market to Create New Forecasting Challenge
There will soon be one less energy-only market in North America. The Alberta Electric System Operator is planning to introduce a capacity market to ensure it has sufficient firm generation supply as the province seeks to add renewables and eliminate coal generation by 2030.
That means new challenges for Steven Everett, forecasting manager for AESO.
“Whether it’s two or three or five [years] — or however many years out our capacity market is — our load forecast will determine what will be the size of that market,” he said. “So there’s going to be new layers of scrutiny on that forecast.”
NYISO Teaching QA Staff Hacking Skills
No electricity conference is complete without a discussion of cybersecurity. Top technology officials from PJM and NYISO took part in a conversation with moderator Stu Bradley, vice president of SAS’ cyber business unit.
Jonathon Monken, senior director of system resiliency and strategic coordination for PJM, noted that an RTO’s challenge is different from that of utilities.
“We are very, very [information technology] heavy. We have a very small amount of physical infrastructure at PJM and a massive IT infrastructure. What that means … is that the attack surface area is significant. It’s huge.”
NYISO Executive Vice President Rich Dewey, who oversees operations, markets and information technology, said the ISO is spending more on training to enhance its defenses and address the shortage of IT security experts.
“Typically in the energy space, 5% of your IT budget is kind of the norm [for training]. … We actually spend probably a higher percentage of our budget on training in the security space. We look at it from two areas: One is trying to close that skill gap of trying to find qualified individuals on the market. There’s not a lot of them.”
The ISO also is training some of its quality assurance team, which tests software before it is put into production, “how to hack,” Dewey said.
“Every time we’re getting ready to put a new piece of software into production, they try to break into it. They try to go through the standard list of the most well-known vulnerabilities and try to see if they can actually get into the system and compromise the security of the system.
“It’s been kind of eye-opening. … We’ve taken delivery of production-ready software. We set it up in our QA environment, we let our QA guys loose on it and before you know it we’ve discovered five or six vulnerabilities — pretty common vulnerabilities — that they didn’t even realize that their own software had. And we work with them to patch those [holes].”
Monken said the electric industry is working with the Defense Advanced Research Projects Agency (DARPA) on a “rapid attack detection and characterization system” for industrial control systems. “That’s something that [the Defense Department] has the money and time to invest in because they see it as a threat factor for national defense. It might not be a tool that we use with great frequency, but being able to provide some tactical expertise from the industry side to the development side tool is something that has significant benefits to us later on as that moves past the prototype stage and into something that can be utilized in the industry.”
North Carolina Utilities Commissioner ToNola Brown-Bland said those seeking regulatory changes to accommodate new technologies should consult with regulators to seek tailored solutions.
“The lawyers in the room and the regulators don’t want to be ‘No.’ We want to help get to ‘Yes.’ But … the current regulatory regime [has] served us very well. … You don’t necessarily want to throw it [all] out.”
Solar for All: San Antonio’s Strategy
Tim Fairchild, director of SAS’ Global Energy Practice, asked CAISO’s Kristov how to make solar more than what Microsoft founder Bill Gates has termed “a toy for rich people.”
“There are a lot of things that don’t make sense from a societal perspective, one of them being the incentive to size your solar installation to the needs of your house,” responded Kristov. “Many houses have shade trees. We don’t want you to cut down shade trees to put on solar panels. But if you have sunny rooftops, why not make those a resource for the entire community, sized to the maximum size you want, and sell the excess?”
That’s the approach San Antonio’s municipal utility has taken. “Essentially, they viewed all sunny rooftops as an asset and they paid for the solar panels — paid rent in the form of a per-kilowatt-hour [fee] to the residents of the house. And then all the energy generated just became part of the supply resource portfolio of the utility.”
Storage
Although California was the first state to mandate utilities obtain energy storage, the “value stack” compensation method for DER is still a “work in progress” at the state Public Utilities Commission, according to Kristov. New York regulators this month introduced the “value stack” concept to replace net metering for distributed energy resources. (See NYPSC Adopts ‘Value Stack’ Rate Structure for DER.)
“If [storage is used] for peak shaving and capacity deferral on a distribution feeder — to put off the day when you upgrade the conductors — you need to be able to use it off-peak on something else to get a little extra funding for it,” said Ralph Masiello, senior vice president of Quanta Technology. “You see that in study after study. One or 2 or 3% of the feeders can be justified on capacity deferral alone. But if you can do the capacity deferral plus time arbitrage year-round — even when you’re not overloaded — then the economics improve to 10% of the feeders or more.
Meanwhile, “storage is on a declining cost curve, as PV was, and it will become more and more attractive for more applications. Today we’re adding storage to the market models in an incremental fashion — not changing the paradigms; making it look like a generator. But if we thought more broadly and towards the future when it was cheaper and more plentiful, this needs to be part of a capacity planning exercise. Ask the question: How much storage is good, is right, for a given market?”
Kiran Kumaraswamy, market development director for AES, foresees storage displacing peaking plants with 4 to 5% capacity factors. “Based on what we’re seeing in the solar space, I think there’s going to be utility-scale storage and there’s going to be consumer storage as well,” he said. “Exactly to what level it’s going to happen in the future is anybody’s guess.”
Plug for EIA
The Trump administration’s proposed federal budget announced last week would cut the Department of Energy’s spending by 6%. Chuck Newton, president of Newton-Evans Research, said it is essential that the department protect its Energy Information Administration. “It’s very important that we give good data to Congress,” he said. EIA “has to continue in place.”
CAISO’s Board of Governors last week approved an ISO request to designate two Calpine natural gas-fired plants in Northern California as reliability-must-run despite criticism from several stakeholders. Acknowledging concerns, ISO officials pledged to avoid “case-by-case” designations in the future.
At the board’s March 15 meeting, Carrie Bentley, a consultant speaking on behalf of the Western Power Trading Forum (WPTF), said the organization “does not at all oppose” designating the units as RMR.
“Obviously, though, after years of the ISO saying they’re not going to use the RMR Tariff authority anymore — and that they’re going to rely on the capacity procurement mechanism — we were really surprised,” Bentley said.
CAISO sought RMR designations for Calpine’s Yuba City and Feather River plants after determining that both 47-MW peaking facilities would be needed to support local grid reliability after they fall off their current contracts with Pacific Gas and Electric at the end of the year. (See CAISO Seeks Reliability Designations for Calpine Peakers.)
CAISO’s Board of Governors approved reliability must-run designations for Calpine’s Yuba City and Feather River peaking plants after the December 2017 expiration of their contracts with Pacific Gas and Electric. | Calpine
Calpine had informed CAISO in November that capital planning requirements required that it be apprised of any reliability need for the plants before this fall, when the ISO releases its 2018 resource adequacy (RA) assessment. The assessment will determine what plants would be eligible for longer-term resource adequacy payments under CAISO’s capacity procurement mechanism (CPM).
‘Purgatory’
“When a unit is facing retirement, or a continued need for operation, we’re in a state of purgatory,” Mark Smith, Calpine vice president of government of regulatory affairs, told the board. “We’re in a position where we can’t make investments that we know that we will never recover and we may not be able to take actions to redeploy those assets elsewhere where they might be more valuable.”
Neil Millar, CAISO executive director of infrastructure development, emphasized that the ISO would seek to implement the RMR contract for Yuba City only if it is not shifted into the CPM program following the assessment.
Feather River will not be eligible for a CPM designation because it is not needed for capacity but to provide voltage support for its local area by absorbing reactive power from the system. Millar said the ISO is working with PG&E to develop “longer-term mitigations” on both the transmission and distribution to come up with a way to reduce reliance on gas-fired generation for voltage control in the area.
“We do need a better process moving forward than bringing these [RMR proposals] forward on a case-by-case, one-off basis,” Millar said.
Bentley recounted recent steps taken by CAISO that should support RA prices, including submitting comments to the California Public Utilities Commission supporting a reduction in the amount of wind and solar that can count as RA and a 2018 local capacity requirements study showing increased capacity needs in some local areas.
“WPTF therefore encourages the board and ISO leadership to take this as an opportunity to step back and ask if there’s anything else the ISO already has Tariff authority to do to help orderly economic retirement and support the RA bilateral market prices,” Bentley said. “A turnaround in prices can only occur in a functioning bilateral RA market.”
‘Sufficiently Visible’
For “sufficient prices” to materialize, Bentley contended, market signals must be “sufficiently visible” to both suppliers and load-serving entities.
Eric Eisenman, director of ISO relations and FERC policy at PG&E, agreed that there was a reliability need for the two plants and that the ISO was the “appropriate venue” for addressing the matter.
“With that said, PG&E encourages the ISO to work with stakeholders [and] PG&E to enhance and improve the process for analyzing and reviewing risk-of-retirement issues for generation,” Eisenman said. “The expedited process of the last two weeks was, quite frankly, not ideal. We all need to do a better job at that.”
Eisenman said his company wants to more closely examine the trade-offs between the CPM and RMR processes.
“I’m actually encouraged by what I’ve heard here today — to some extent,” said Jan Strack, transmission planning manager at San Diego Gas and Electric, adding that the RMR matter was something warranting a deeper look.
Strack noted that the ISO has a lot of aging gas-fired generation. “We’ve got to figure out a way to let that stuff go,” he said, adding that RMR contracts should be “a measure of last resort.”
“In the current instance, I think we feel there has not been enough light shined on all the various alternatives that could be looked at, rather than just going into an RMR contract,” Strack said.
Millar called the Feather River decision “strictly a matter of timing,” with the RMR providing CAISO time to determine the best solution for local voltage support.
“Putting it bluntly, three months with no opportunity for any stakeholder process doesn’t give us that time,” Millar said, referring to the “compressed timeline” in which the ISO needed to notify Calpine about the RMR decisions. The company had requested a decision by the end of March in order to have adequate time to draw up a cost-of-service proposal and perform the required capital maintenance.
Signs of Market Failure
| CAISO
Governor Ashutosh Bhagwat wondered if there were any other ISO mechanisms available to ensure the plants’ availability other than RMR.
Keith Casey, CAISO vice president of market and infrastructure development, said the RMR option provided CAISO more flexibility in dealing with Calpine’s near-term need to make capital investments than the CPM, which functions as the ISO’s standard “backstop” for needed plants at risk of retirement. Still, Casey said it would be “unfortunate” for the ISO to find itself facing a “proliferation” of RMR agreements.
“If we now find ourselves ramping up in that, that’s a sign we have a market failure,” Casey said.
CAISO CEO Steve Berberich said the RMR issue was “symptomatic” of the fact that the RA processes that both the ISO and PUC have in place “are starting to fray at the edges a little bit.”
“Of course, the ISO has advocated for a longer-term resource adequacy program so that we don’t have this year-by-year emergency situation that we always have to go through,” Berberich said.
Berberich pointed out that the current RMR issue is part of an “evolving grid.”
“Take a step back — why is voltage high at Feather River?” Berberich asked rhetorically. “The voltage is high because of light-load conditions. We have substantial distributed generation on the system.”
He suggested that the voltage issue — rooted in distribution-level changes that are affecting the low-voltage network — could possibly be better managed by a distribution-level solution rather than a transmission-connected resource such as the Feather River unit.
“This is a very complicated issue,” Berberich said. “I’d like to tell you that this is the last time we’re going to talk about RMR, but I don’t think that’s going to be the case.”
Maryland Gov. Larry Hogan said Friday he will support a ban on fracking, potentially making the state among the first to enact a statutory ban on the oil and gas extraction method.
Hogan
In making the announcement, Hogan, a Republican, departed from his previous stance that he would support the practice and that he believed it could be done in an “environmentally sensitive manner.” His new stance is the exact opposite, that it’s impossible for the process to occur without unacceptable environmental risks.
“I’ve decided that we must take the next step and move from virtually banning fracking to actually banning fracking,” he said. “The choice to me is clear: Either you support a ban on fracking, or you are for fracking.”
He made the announcement alongside state Sen. Bobby Zirkin (D-Baltimore), the lead sponsor of SB 740, which would establish the ban. The House of Delegates passed a ban on the practice by a veto-proof margin two weeks ago.
“Larry Hogan just took a big step for Maryland and the nation in moving us toward” solving global climate change, Mike Tidwell, the executive director of the Chesapeake Climate Action Network, said in a news release.
The controversial process of high-volume fracking has never been used in Maryland, but the state’s two-year moratorium is due to expire in October. Parts of western Maryland sit atop the Marcellus shale, a rock layer several thousand feet below ground laden with natural gas that runs from Ohio to New York. New York and Vermont already prohibit fracking.
Geologic Map of Western Maryland | Maryland Department of Natural Resources; click image for original
Hogan said his decision was partially based on the state legislature failing to implement rules proposed last year that he said would have been the most stringent in the nation and made it “virtually impossible for anyone to ever engage in fracking in Maryland.” Because the legislature didn’t enact the regulation, Hogan is now supporting a statutory ban.
Prior to Hogan’s announcement, the ban looked unlikely to be approved this session. Legislators feared a veto from Hogan and instead favored extending the moratorium. Sen. Joan Carter Conway (D-Baltimore) had proposed extending the moratorium for two years and requiring each county and Baltimore City to hold referendums next year on whether to ban the practice locally. As the chair of Senate Education, Health and Environmental Affairs Committee, she will decide if the ban bill receives a vote before the moratorium expires.
CARY, N.C. — Stephen Rourke, vice president of system planning at ISO-NE, worries distributed energy resources will force RTOs to change their focus.
“We’re so used to operating at the wholesale level. We dispatched 350 generators for the last 40 years. Now there’s 108,000 solar installations. So we’re kind of getting dragged, whether we like to or not, from a wholesale view of the power system, to a retail view,” he said during the RTO Insider-SAS ISO Summit at SAS headquarters last week.
“What we won’t have [visibility of] is if everybody who has solar panels in their houses puts a 4-kW battery in their garage — and there are hundreds of thousands of those. So that’s going to be a data challenge.
“If you’re 5 MW or greater, you need a [remote terminal unit], you have to have a leased telephone line. Those are thousands of dollars to buy and hundreds of dollars a month to lease the phone line. Your 500-kW solar panel can’t afford to do that, but we have thousands of them. So how do we get the data and how do we process the data? It is … a challenge for us. So we’re going to need help from others certainly with the technology platform.”
‘Layered Control Structure’
Layered Control Structure for DER | Lorenzo Kristov
Lorenzo Kristov, principal for market and infrastructure policy at CAISO, says it doesn’t have to be the RTO’s headache. He has proposed what he calls a “layered control structure” in which the distribution utilities would aggregate DER data for their RTOs.
“Each tier in this hierarchy only needs to see interchange with the next tier above and below, not the details of what’s going [on] inside because the optimization is happening locally,” he explained. “The ISO then focuses on bulk system integration, while the distribution utility … coordinates the operation of the DERs. The layered control structure reduces complexity, allows scalability and increases resilience and security. And finally the fractal structure mimics nature’s design of complex organisms and ecosystems.”
Kristov urged DER aggregators to bring “use cases” to CAISO to aid it in updating its market rules.
Currently, the ISO uses one of two models for DER: the demand response model and the non-generation resource used for storage. “When you’re charging, you’re using energy at retail; your ability to provide services to the ISO is very limited.
“Several parties have signed up as [DER] aggregators, but they haven’t brought in the resource yet,” he said. “Part of what we’re trying to figure out is what do we need to do to improve those rules. So I would say more active engagement in our stakeholder process [is needed] to bring us specific use cases. How do we want to operate in your markets? What is it we want to do? What are our capabilities? There’s a lot of technical detail that we can’t figure out because it’s the developers who have these things in mind.”
DER also needs standards, said Ralph Masiello, senior vice president of Quanta Technology. He cited the aftermath of Superstorm Sandy in New Jersey in 2012.
“Too many of those [solar] installations did not disconnect when the distribution circuit went dead and so restoration was held up by the need for utility linemen to come verify that the line was dead before the tree crews could start clearing the debris,” he recounted.
“Normally the utility knows from its SCADA that the line is dead. But if you have just one … PV panel that didn’t de-energize, it’s enough to put high voltage on a downed line and make it dangerous. So there’s kind of a big data opportunity there. The utility needs to know where are those panels and what is their status.”
Solar PV could create a role on distribution systems for synchrophasors that previously have been used mainly in transmission, Masiello said, citing a Department of Energy project testing whether PV panels can be used to develop “synthetic inertia.”
“Can you take a smart inverter on PV — it’s already got communications and … time-synch capability — and build the synchrophasor into that smart inverter? And then you can use it as a key to developing local synthetic inertia from the panels.”
Masiello also said his company is beginning to get requests to do forecasting on the distribution systems.
One need, he said, is identifying distribution lines subject to solar “backfeeding” onto the transmission system, as has become common in Germany and begun happening between 10 a.m. and 2 p.m. in Hawaii.
“In other words, there’s not enough load on a segment of line to be able to absorb all of the solar that’s being generated,”
he explained. Utilities “may have to move some customers from one distribution segment to another.”
Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees 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
2. PJM Manuals (9:10-9:25)
Members will be asked to endorse the following proposed manual changes:
A. Manual 13: Emergency Operations. Revisions developed in response to new NERC standards.
Members will be asked to endorse the proposed shortage pricing and operating reserve demand curve solution and associated manual revisions. (See “Order 825 Implementation Moves Forward,” PJM Market Implementation Committee Briefs.)
Members will be asked to endorse a proposed problem statement and issue charge by Bob O’Connell of Panda Power Funds regarding calculation of opportunity costs for units with less than three years of historical LMPs. The initiative would evaluate whether the opportunity cost calculator included in PJM’s Markets Gateway produces the same results as that used by the Independent Market Monitor, Monitoring Analytics. It also would consider updating the calculators to reflect the nonperformance penalties under Capacity Performance. (See “Stakeholders Deny Replacement Capacity Initiative; Consider Other Incremental Auction Changes,” PJM Markets and Reliability and Members Committees Briefs.)
7. Modeling Generation Senior Task Force (MGSTF) (10:50-11:00)
Members will be asked to endorse a draft charter for the MGSTF, an outgrowth of the Combined Cycle Owners User Group, which concluded that a more detailed generator model for combined cycle units might also be applicable to other steam units. The task force will consider expanding the model used by PJM to improve the ability to represent components of all generation types.
8. Incremental Auction Senior Task Force (IASTF) (11:00-11:10)
Members will be asked to endorse a draft charter for the IASTF, which will consider changes to the Incremental Auction process and structure, excess capacity sales, and PJM participation in the auctions.
9. Replacement Capacity (11:10-11:40)
Members will be asked to endorse a revised version of a previously rejected problem statement and issue charge regarding procurement of replacement capacity in Reliability Pricing Model Incremental Auctions. (See “Stakeholders Deny Replacement Capacity Initiative; Consider Other Incremental Auction Changes,” PJM Markets and Reliability and Members Committees Briefs.)
CARY, N.C. — PJM CEO Andy Ott said last week the RTO will look for ways to incorporate “resilience” in its markets and system operations, providing hints at a white paper it will release later this month on the issue.
Speaking at the RTO Insider/SAS ISO Summit last week, Ott said the initiative was sparked by fuel security concerns — the risks of sabotage or cyberattacks on grid assets or gas pipelines — and a desire to recognize the reliability value of baseload nuclear and coal plants struggling to compete in the PJM market. Later in the panel discussion, former FERC Commissioner Tony Clark — participating via phone after snow canceled his flight from D.C. — forecast how the commission and the courts may rule on zero-emission credits that provide additional revenues to nuclear plants.
Ott said one possible shift in PJM would be changing contingency plans from replacing the largest single generator to ones that consider the loss of a gas pipeline supplying multiple generators.
PJM CEO Andy Ott wants to find ways to value the fuel security of coal and nuclear plants.
“All the generation connected in a certain section of that pipeline could go off very quickly if it loses pressure because of an explosion or some event. Maybe we should be operating to the loss of that and look at that operational risk inside the market and price that in so the units that didn’t have that kind of fuel security risk would be worth more money,” Ott said. “That would help, of course, the resources that are less dependent on just-in-time fuel” such as nuclear and coal. Ott also said PJM will seek to become more “dynamic” in its management of operations.
Concern over Pipelines, Transmission Corridor
“One obvious [example] is to look at the way we deploy synchronized reserves or operating reserves and expand the contingency set that you’re looking at to include pipeline contingencies. … Or if you have a transmission corridor that you’re very worried about — potentially include that as part of your constraint set. So when you’re dispatching generation or deploying demand response, you’re essentially recognizing that double contingency or triple contingency as part of operations in certain circumstances. Not 8,760 hours [per year] but when you think that vulnerability exists, you can price it in.”
It also could mean system restoration plans becoming less dependent on individual transmission lines or fuel sources, Ott said.
Ott did not offer details on how fuel security would be priced into the markets. The RTO has already taken steps to address reliability concerns with its Capacity Performance rules, which increased penalties for nonperformance and rewards for overproduction during emergencies.
Coal Group Petitions PJM, MISO
On Friday, meanwhile, the American Coalition for Clean Coal Electricity (ACCCE) sent Ott a letter calling on PJM to take steps to prevent further retirements of coal-fired generation and “take into account the likelihood of changes to federal environmental policies.”
“We are confident the new administration will withdraw or rewrite environmental regulations that are causing, or could cause, more coal retirements,” ACCCE CEO Paul Bailey wrote. “These rules include the Clean Power Plan, Coal Combustion Residuals, Effluent Limitations Guidelines, Cross State Air Pollution Rule and Regional Haze.”
Bailey said the Capacity Performance rules were helpful but insufficient. “We do not think these changes go far enough in recognizing the advantages of baseload coal-fired generation. In particular, the changes have not led to higher capacity prices that are necessary to keep coal plants from prematurely retiring,” he wrote.
ACCCE says 121 coal-fired generators totaling 20.1 GW have retired in PJM, most because of environmental regulations, and another 28 plants (8.9 GW) have announced plans to shut down.
Almost 93,000 MW of coal-fired electric generating capacity (558 electric generating units) in 43 states have shut down or plan to shut down over the period 2010 – 2030 | American Coalition for Clean Coal Electricity
The group also sent a letter to MISO CEO John Bear asking the RTO to change rules “to ensure the reliability attributes of coal-fired generation … are properly valued.” MISO has lost 103 coal-fired generators (8 GW), with another 45 retirements (10.5 GW) pending.
Former Commissioner: FERC May Reject ZECs
Nuclear spent fuel pool | Nuclear Energy Institute
Former Commissioner Clark, now a senior adviser at Wilkinson Barker Knauer, said zero-emission credits approved for nuclear plants in New York and Illinois — and under consideration in Connecticut and other states — may be rejected by FERC or the courts because of their impact on wholesale market prices. (See related story, Connecticut Moves Closer to Equating Nuclear with Renewables.)
Clark called ZECs the third iteration of states’ efforts to build or preserve generation within their borders. Last April, the Supreme Court rejected Maryland’s contract-for-differences with the developer of a combined cycle unit, saying that by tying the contract to PJM capacity prices, the state had violated federal jurisdiction.
In May, American Electric Power and FirstEnergy withdrew power purchase agreements that Ohio regulators had approved with their unregulated generation after FERC indicated it would review the deals for violations of affiliate abuse rules. “The merchant generators basically did a very surgical strike in [their] filing at FERC” in requesting the affiliate review, Clark said.
With ZECs, “the states … have really gotten craftier about how they can [preserve at-risk generators],” said Clark, noting that they were designed to be similar to state renewable energy credits (RECs).
“Merchant generators have … said these RECs are an out-of-market subsidy [that] distort prices. And the commission has said, ‘OK, theoretically we understand what you’re saying.’ But there wasn’t enough provable harm for the commission to really do anything about it,” Clark said. The RECs “were either conceptual at the time of the challenge … or it was a small enough part of the market … that it didn’t seem like it was a big enough issue that the commission could act on. So effectively the commission could punt on that issue.
“Now if you’re talking about certain regions of the country where nuclear units are 20%, 30% of the market, or if you’re talking about other out-of-market interventions like in the Northeast — you’ve heard about long-term power contracts … with Canadian hydro — that might be 30% of the state’s energy needs.
“Well that does have a very material impact on the market themselves, so that will be a challenge for the commission to see if this is a zero-sum game, or the commission will have to declare in some ways these things federally jurisdictional and carve the states out. Or is there a way to thread the needle? That’s what each of the ISOs that’s dealing with this is doing.
“Here’s where it will get to be very tricky for the commission,” Clark concluded. “I’m not sure exactly how it will end up dealing with it.”
North America’s independent grid operators released a report Thursday that concludes the “ongoing effectiveness” of renewable technologies will depend directly upon the electric system’s ability to “accommodate them.”
The ISO/RTO Council (IRC)’s report, “Emerging Technologies: How ISOs and RTOs can create a more nimble, robust bulk electricity system,” concludes the future of the North American power grid depends on effectively adding renewables, the accuracy and availability of data from behind-the-meter resources and coordinating these distributed energy resources at the grid-operator level to preserve reliability.
The report captures the results of a study conducted by the IRC’s Emerging Technologies Task Force (ETTF), which was formed in 2015 to review the deployment of new technologies and identify where that deployment intersects with operational and policy considerations.
The report notes more than 80% of North America’s wind and solar capacity lies in regions served by IRC members. These technologies face a serious challenge, the report said — the electric system itself.
SPP CEO Nick Brown, the IRC’s current chair, noted grid operators from different geographic regions “overlap … in their thinking” of the role emerging technologies will play.
Technology Precedes Policy
“Here’s the challenge: Technology always precedes policy,” Brown said during a panel discussion last week at the RTO Insider/SAS ISO Summit. “And as technology presents things, then we have to understand how to manage them [through] appropriate policies.”
The IRC is an affiliation of nine nonprofit grid operators that serve two-thirds of electricity consumers in the U.S. and more than half in Canada.
“Any time the IRC speaks with strong consensus on a matter like it has done here, I hope our industry takes notice,” Brown said in a news release.
“Each of the IRC member organizations is unique,” said ETTF Chair Edward Arlitt, of Ontario’s Independent Electricity System Operator. “One ISO or RTO may have greater solar capacity in their region, another may be farther along in their handling of DERs, and all of us have regulatory and operational constraints unique to the provinces, states and regions in which we serve.”
Western Interconnection renewable capacity with transmission investment to support high renewable penetration (2020-2025).
The task force used a straw poll to determine that handling emerging technologies was the highest-ranked priority among IRC members.
‘Imperatives’
The task force’s research produced what it called imperatives necessary to ensure the grid’s continued reliability and efficiency as the penetration of emerging technologies increases:
Manage the variability of supply and increasing levels of renewable integration enabled by emerging technologies. Is there enough “cohesive innovation” happening to integrate renewable generation, grid-scale energy storage and microgrids’ disparate components into the Bulk Electric System?
The IRC said while it is agnostic to specific technologies that may facilitate renewable integration, it supports policies that “accommodate emerging renewable integration technologies” and pursuing “continentwide consensus” on how much integration will be achieved through regional or interregional trade.
Computer-modeled load profiles for CAISO under various future scenarios of 20%-50% PV penetration.
The report recommends avoiding committing too early to specific technologies and calls for a “suitable policy environment” to ensure new technologies and approaches continue to be developed, tested and applied to renewable integration.
Address the IRC members’ lack of consistent, reliable, DER-related data as the grid becomes more distributed and less predictable.
The report says the lack of consistent and reliable data — such as between SCADA systems and new phasor measurement units (PMU) — should not constrain “situational-awareness arrangements” across transmission/distribution connections. It also says RTOs should have access to basic, static DER data series in their service territories. The task force said location, size and technological capabilities are examples of data needed to manage an increasingly distributed system.
The task force recommended developing an operations data framework flexible enough to handle local differences in DER penetrations.
Noting FERC’s November 2016 Notice of Proposed Rulemaking, which would require wholesale markets to accommodate energy storage and DER, the IRC suggests a formalized framework to help RTOs “harness the capabilities and manage the risks” of intermittent DER growth. (See FERC Rule Would Boost Energy Storage, DER.)
The task force recommends jurisdictions with distribution system operators (DSO) conform to standards that allow safe interaction between DSOs, non-utility entities and the Bulk Electric System. It said it supports policies that ensure if distribution-level variability poses risk to system reliability, RTOs have “appropriate authority” over DERs or mitigate their impact on the grid.
CARY, N.C. — PJM CEO Andy Ott and SPP CEO Nick Brown said last week that FERC Order 1000 is causing their staffs headaches while doing little to encourage transmission development.
“I think the driver behind Order 1000 was to get more people wanting to invest in transmission,” Ott told the RTO Insider/SAS ISO Summit last week, where he appeared on a panel with Brown and former FERC Commissioner Tony Clark, who participated via phone after snow canceled his flight from D.C. “We haven’t had any shortage of [interest]. In fact, everyone wants to invest in transmission because it’s a pretty safe investment. [Order 1000] was almost like a solution in search of a problem. … It’s actually creating more challenges to investment.”
“It created more overhead and more uncertainty at a time when we didn’t need more overheard in order to invest in transmission,” said Brown. “I am thankful that we completed the vast majority of our transmission buildout in a pre-Order 1000 environment.”
Ott said enforcing cost caps on competitive projects and allocating costs for them are tasks that RTOs are ill-equipped to handle. “We’re not a regulator,” he said.
Clark, who joined the commission after the order was issued in 2011, said the intent of the initiative was good, noting that it has pushed regions to conduct joint planning.
“The concern that I always had … is that there is so much process built into Order 1000,” each step of which becomes an opportunity for litigation and delay, Clark said.
“What you end up with is just what Andy and Nick were talking about, which is actually less investment happening than would otherwise happen organically on its own because you’re doing so much to meet the burdens of the process in Order 1000 that you’re sort of losing the forest for the trees.”
Clark said it’s too soon to determine whether the order will be successful in introducing competition into transmission development. “Incumbents have so many natural advantages in terms of building large infrastructure projects within their footprint that I don’t know that that’s something you can regulate away. Nor should we necessarily try to.”
Companies in the RTO Insider Top 30 reported revenues of more than $75 billion in the fourth quarter of 2016, a 7% increase over a year earlier, as all but five companies saw topline growth.
FirstEnergy, Public Service Enterprise Group, NextEra Energy and NRG Energy all reported revenue drops in the fourth quarter while Consolidated Edison was flat.
Similarly, all but five companies were profitable in the quarter. The exceptions were FirstEnergy (a $5.8 billion loss) Entergy ($1.8 billion), NRG ($987 million), Duke Energy ($222 million) and PSEG ($98 million). But the losses were so large they swamped their peers’ earnings, resulting in a cumulative loss of $2.62 billion for the quarter.
FirstEnergy reported a loss of $6.2 billion for the entire year, largely because of asset impairment and plant exit costs related to its decision to leave competitive generation by mid-2018. The company is seeking subsidies for its Davis-Besse and Perry nuclear plants in Ohio to make them attractive to buyers. (See FirstEnergy Seeking ZECs to Aid Sale of Ohio Nukes.)
Despite the fourth-quarter loss, Entergy, which also is exiting merchant nuclear generation, earned $1.27 billion for the year ($7.11/share), beating Zacks’ consensus estimate of $6.83/share. (See Entergy Beats Expectations Despite 80% Drop in Earnings.)
Avangrid’s 29% jump in Q4 revenues and more than doubling of net income reflected the first full year of operations including UIL Holdings, which it acquired in December 2015.
Edison International earned $377 million in the fourth quarter, versus a $50 million loss a year earlier. In February, its Southern California Edison unit joined with other investor-owned utilities in proposing spending $1 billion on transportation electrification. SoCalEd plans to spend $573 million, including pilot projects for electric transit buses and electrification of cargo handling equipment at the Port of Long Beach.
Edison CEO Pedro Pizarro said the company has “scaled back business development” at Edison Transmission because of “limited FERC Order 1000 opportunities in our target markets.” The company will continue its role in the Grid Assurance initiative to pool inventory and develop best practices to support transmission system reliability.
Dominion earned $457 million for the fourth quarter, a 28% jump, thanks to its acquisition of Questar, which added 56 Bcf of gas storage and 3,400 miles of gas transmission to its assets. Due in part to the acquisition, the company announced last month it was rebranding and replacing “Resources” with “Energy” in its name. The company now does business in 18 states. (See Dominion Resources Changing Name to Dominion Energy.)
The ISO/RTO Council (IRC)’s 
FirstEnergy reported a loss of $6.2 billion for the entire year, largely because of asset impairment and plant exit costs related to its decision to leave competitive generation by mid-2018. The company is seeking subsidies for its Davis-Besse and Perry nuclear plants in Ohio to make them attractive to buyers. (See