Reforms to CAISO’s congestion revenue rights auctions will come only after painstaking analysis of what is causing the auctions to pay out significantly more money than they take in as revenue, the ISO official leading the effort told stakeholders Tuesday.
“We really want to lay down what’s going on and understand the dynamics of the auction,” Guillermo Bautista Alderete, CAISO director of market analysis and forecasting, said during a May 16 Market Performance and Planning Forum. “We want to understand what are the drivers [of revenue shortfalls] and have an informed set of data that can guide us into what the policy’s going to be.”
Any policy changes are likely to prove contentious among market participants with a stake in the auctions.
The CAISO Department of Market Monitoring insists that the ISO-sponsored auctions should be replaced with a bilateral market that doesn’t leave utility ratepayers as unwilling counterparties in losing deals.
On the other side stand the Western Power Trading Forum and DC Energy — a firm specializing in trading CRRs and other financial instruments tied to power and natural gas markets — which argue that the auctions provide the only liquid market for hedging congestion risk in the ISO’s wholesale market.
Most stakeholders, including the ISO’s load-serving entities, sit somewhere in the middle of the debate but tend to agree the auctions require significant changes, if not dissolution.
CAISO is seeking to understand why the ISO’s congestion revenue rights auctions have been a consistent money-loser for California ratepayers. | CAISO Department of Market Monitoring
Bautista Alderete said the CAISO plan for examining the CRR auctions was shaped by suggestions coming out of an April 18 working group convened to kick off the initiative. (See Heated Start for CAISO CRR Reform Initiative.)
The analysis phase will begin with ISO staff picking off the “low-hanging fruit” to be found in the auction results: “Profits, losses, who’s losing, who’s winning over time [and outcomes of] the annual [auction] versus the monthly,” Bautista Alderete said.
A second, “more complex” phase will look at how various auctions were modeled and compare that information to how the transmission system was modeled in the day-ahead markets on which CRR payments are settled. That will require an accounting of transmission outages, and whether they were included in auction models.
“These types of metrics are not that simple” to produce, Bautista Alderete said.
A third, “most complicated” phase will delve into the transmission system constraint by constraint, focusing on those constraints that did not bind (or show high congestion) in the auctions but paid out to CRR holders in the day-ahead market, as well as constraints responsible for the largest payouts.
“That is the type of analysis that we want to take on to understand the efficiency of the auction, because once we can understand what is behind the specific divergence between day-ahead and [the auctions] — the specific driver for revenue insufficiency — we can really start putting the pieces together for why we landed there, [for] why we have a systemic constraint that is always on the winning side or the losing side,” Bautista Alderete said.
In order for the findings to be “meaningful,” he added, the ISO must undertake a time-consuming process of examining constraint data going back to the start of the auctions, which will include determining how nomograms modeled in the CRR auctions may have changed in the corresponding day-ahead market.
Bautista Alderete expects the first round of “straightforward” data analysis related to auction results and settlements to be complete in two months. He provided no timeline for the other two phases.
“Once we complete the analysis phase, then we’re going to start moving into the discussion of the policy — what we need to do. Do we need to scrap the auction? Do we need to tweak the auction? That is the piece we need to reach only when we have determined, based on the analysis, what we need to do.”
It typically takes “two or three or four things” to occur for CAISO declare a grid emergency, according to Tim Beach, an operations shift manager with the ISO.
“Which is what played out here on May 3,” Beach said during a May 16 Market Performance and Planning Forum, at which he recounted why CAISO on that day declared its first Stage 1 emergency in 10 years.
The causes on this day: high temperatures, a generator failure, no-show imports and a rebuff from suppliers.
Although May 3 was forecast to be one of the warmest days of the year to date, it was considered a day with “pretty normal” conditions, Beach said. Los Angeles area temperatures ranged from the mid-80s downtown to the mid-90s farther inland and to the north.
System loads began to diverge from day-ahead forecasts about 1 p.m. “That’s not unusual,” Beach said. “We typically see a lot of that. We’ll see it diverge and we’ll also see it come back and converge again at peak or after peak.”
About 10 minutes later, a 330-MW unit at AES’ gas-fired Alamitos generating station in Long Beach shut down unexpectedly, taking with it 270 MW of energy production that had been awarded in the day-ahead market.
The unexpected shutdown of one unit at AES’s Alamitos generation station was one of a handful of events that precipitated CAISO’s May 3 “Stage 1” emergency. | California Energy Commission
Still, conditions remained normal throughout the afternoon, and the ISO was carrying ample reserves by the time load peaked at 5:45 p.m.
No Shows
But a short time later, about 1,150 MW of imports scheduled in the day-ahead market didn’t materialize. The hour-ahead market then awarded 1,230 MW of supplemental energy on the interties for the hour ending 8 p.m. But about 830 MW of the awards were declined by the suppliers.
“So going into hour ending [8 p.m.], we’re over the peak. We’ve got solar ramping off very quickly. It’s starting to look pretty tight,” Beach said.
At 6:42 p.m., with solar quickly coming off the system, the shift manager on duty began canvassing the utilities for available DR.
“That’s a typical procedure we do,” Beach said. “We go out and look and make sure we have a number that we can operate to.”
Within 15 minutes, the shift manager determined that the ISO’s area control error — the difference between actual and scheduled generation — was at 750 MW. With solar continuing to roll off the system, the manager was forced to deploy reserves, which then fell to about two-thirds of the 1,870-MW requirement.
Emergency Declared; DR Called
About 7 p.m., CAISO declared the Stage 1 emergency, simultaneously calling for 843 MW of DR from the utilities.
“And at [7:34 p.m.], with the DR deployed, our ACE was up to 34 MW on the plus side,” Beach said. “So we recovered briefly, but solar is still ramping off — but the load’s ramping off at the same time.”
By 8 p.m. the situation had stabilized. The ISO called off the emergency an hour later.
Brian Theaker, director of market affairs at NRG Energy, asked how much of the 843 MW of DR deployed by the ISO actually responded to the dispatch call.
“I can’t establish that at this time,” Beach said. “I think the market analysis [will provide] the exact number or a close number. We’ll rely on some of that to come from the utilities as well.”
Wei Zhou, senior project manager at Southern California Edison, asked whether transfers from the Western Energy Imbalance Market (EIM) assisted during the event.
“There were about 500 MW of transfers around that time, so it was helping us,” said Guillermo Bautista Alderete, CAISO director of market analysis and forecasting.
Why the Rejections?
Bautista Alderete was unable to address a question about exactly why suppliers on the interties declined the 8,300 MW of awards ahead of the event. Such declines are not unusual, but “not to this level, not to this volume,” he responded.
“This is somehow an action that [suppliers] can take and this is something we have to discuss further as to how we can enhance the procedure that we have,” Bautista Alderete said. “Because usually you don’t want to see them decline when you need that [energy] most.”
“Was it a lot of different entities that made up the 830 [MW of declines] or was it just a few?” asked Carolyn Kehrein, a consultant for Energy Users Forum.
“I would love to give you an answer on that,” Bautista Alderete said. “We haven’t completed the full analysis, so I would like to hold off on that answer.”
Additional research has reinforced earlier projections that MISO’s market platform will become obsolete in five to seven years, RTO executives told members of the Board of Directors on Tuesday.
Ever-evolving cybersecurity standards are contributing to the system’s end and MISO’s vendors plan to stop supporting its platform by 2023 as they shift to newer technology, officials said. The RTO has predicted that with “limited investments,” its market platform can only accommodate a “modest increase in complexity” and has five to seven years before it can no longer clear the day-ahead market.
“The market systems’ likely end of life is in sight, and our studies have only confirmed that we’ll need a substantial upgrade,” MISO Executive Director of Market Design Jeff Bladen told directors on a May 16 conference call of the board’s Technology Committee.
MISO began a stress test study last fall examining how the performance and security of its critical operating system would hold up over time. (See MISO to Study Aging Software; Market Improvements Planned for 2017.) Since then, MISO has completed nine one-on-one workshops with vendors to discuss the overhaul.
Recommendations Due in June
Bladen’s staff is drafting near- and long-term upgrade recommendations and will issue them, and post-2018 budget estimates, during the board’s June week of meetings in Branson, Mo.
A business case recommending a specific course of action for a long-term platform upgrade will come in two to three years after multiple viability tests, Bladen said. MISO wants the replacement platform to employ a modular architecture, allowing replacement of individual components without affecting the rest of the system.
MISO Director Baljit Dail asked if the end of vendor support at the end of 2023 is a hard and fast date. MISO Technology Executive Kevin Caringer said vendors have agreed that the end year might be extended if absolutely necessary. “It’s not a date that we can negotiate out forever, but there is some flexibility,” Caringer said.
Directors asked for a special meeting in front of MISO membership and the full board to discuss the technology study and a range of possible improvements. Staff said the meeting could be scheduled sometime in October. A more detailed rundown of MISO technology improvements and goals was reserved for the committee’s closed session following the meeting.
Heavy Demands from CIP Standards
MISO said NERC’s Critical Infrastructure Protection standards are outstripping the adaptions it can make. Compliance with the standards will require investment in near-term improvements in 2017 and 2018, MISO Chief Information Officer Keri Glitch said.
MISO expects more new NERC standards in 2019, among them tighter requirements for control center communications and supply chain risk management, requiring verification of vendors, neighboring ISOs and market participants.
MISO’s Carmel. Indiana Control Room in 2013 | MISO
“We know the speed of change is not going to slow down,” said Glitch, pointing to the seven versions of CIP standards rolled out since 2008.
Painting the Golden Gate Bridge
“At what point does this become painting the Golden Gate Bridge, where there’s just so much stuff we can’t keep up?” Dail asked.
Glitch said MISO is already preparing for its 2018 audit, which isn’t slated to begin until the fall. “We’re in a continual cycle because of the audit process.”
More than 975 cyber assets and 59,500 pages of evidence will be scrutinized in the NERC audit next year, Glitch said — almost three times the volume examined in the 2012 audit. “The electric industry has undergone tremendous change to critical infrastructure standards,” she said.
Director Michael Curran also asked if staff from NERC itself can keep up with the corporation’s accelerated rate of new compliance standards and changes to existing standards.
“That’s a loaded question,” Glitch said. “I do see that they’ve made improvements over the last few years. From a MISO perspective, are they making all the improvements MISO would like to see? Perhaps not, but they are more open to suggestions.”
“The answer I heard is ‘No, they haven’t kept up, but they’re listening,’” Curran replied.
Ransomware Attack
During the meeting, MISO directors stressed the importance of cybersecurity in light of the massive, ongoing WannaCry ransomware attacks, which have been linked to North Korean IP addresses.
“NERC compliance does not equal security. Just because you’re NERC-compliant does not mean you’re not going to have an attack,” Glitch said.
GROTON, Conn. — The best strategy to deal with change in the energy sector is to embrace it. So said some of the more than 250 participants at the Northeast Energy and Commerce Association and Connecticut Power and Energy Society’s 24th New England Energy Conference last week.
NECA President Tina Bennett, a principal consultant with Daymark Energy Advisors, said that the electric markets should “accept disruption” from new technologies by creating a new regulatory landscape.
“The model today is not really conducive for where we want to go in the future,” Bennett said, citing the growing impact of distributed energy resources. “What are the things we can do today from a regulatory perspective and from a business model perspective that can open up possibilities for the disruption to happen?”
Former Massachusetts Undersecretary of Energy Barbara Kates-Garnick, now a professor of practice at Tufts University, agreed.
“We are going to have to accept disruption, but that is something that we as the energy industry haven’t been easily able to accept,” she said. “The future is not linear, it’s not a straight line, and we’re going to have to design processes that have off ramps and that also enable rewards for those people and those entities that take risk.”
Angela M. O’Connor, chairman of the Massachusetts Department of Public Utilities, said her state is “at a crossroads. We’re number one in the nation in energy efficiency, but our programs are also the most expensive in the country. When lighting requirements change, what will the next programs and the benefits look like?”
RTOs are trying to automate their grids, but high penetration of distributed energy resources means they have to operate their feeders with less flexibility at times depending on renewable penetration levels, or “hosting capacity,” said Scott Higgins, director of distributed energy and microgrids for Schneider Electric.
The job of managing the grid is complicated by different market participants — independent power producers, utilities and behind-the-meter “energy prosumers” — each having different goals, contracts and control systems.
To illustrate the challenge, Higgins mentioned the use of battery storage to shave a “prosumer’s” peak in the middle of the day. “But we also have a demand response event coming up later in the afternoon and the control system will need to recharge the battery for that. The DR event benefits the prosumer, but it is initiated by the utility, so at some point the control algorithm decides to stop peak shaving and to charge the battery. What if the prosumer has an economic interest in peak shaving longer and foregoing the demand response event that day? Contracts and control systems both have to draw the line at some point between serving one customer constituent and another.”
With the huge investments needed in upgrading transmission and developing renewables, “we can make use of that grid; we don’t need to be trying to escape the grid,” said Jeffrey Roark of the Electric Power Research Institute.
Alan Trotta, director of wholesale power contracts for United Illuminating, offered some statistics illustrating the growth of DER. “In 2011 we had fewer than 100 requests for interconnection with distributed generation units,” he said. In 2016 “there were over 3,000 requests and over 2,300 new behind-the-meter generators interconnected.”
For maximum cost-effectiveness of decarbonization of the grid, go big, said Trotta, referring to the difference in customer costs between grid-scale renewables and DERs. “The economies of scale are real and we see it in actual procurement results.” Speaking about the evolving role of the grid, Trotta said, “The grid is changing because the needs of the users are changing, and by users, I mean customers, generators, potential storage developers [and] people in the transportation sector.”
Electric Vehicles
Many in the industry are confident that electric vehicles will cause an increase in loads after years of flat or declining power demand. Martin Stahl, managing director of Germany-based Stahl Automotive Consultants, forecast that EV sales in the U.S. will increase seven-fold to nearly 1.4 million by 2025. The main constraint on EVs, he said, is a lack of charging infrastructure.
Stahl Automotive Consulting
Stahl said utilities are committed to building an EV charging infrastructure in Germany, where the decision to give up nuclear power increased renewable commitments and added stress to the grid.
Well-placed chargers are essential to avoiding excessive spending on public and private charging infrastructure, Stahl said. “But more important is the demand response function, either regulated or behind-the-meter,” he said. Fast-charging equipment is expensive and needs to be connected to higher voltage lines, while at-home charging is almost invisible to utilities. “We are exploring with clients how to ensure that emerging load can be put to a good time of the day,” he said.
Stahl Automotive Consulting
For example, he estimated that with good location planning and optimization, EV charging could decrease the average residential ratepayer bill by nearly 10%, versus a 1.5% increase with no optimization.
Timing is crucial to those who seek to introduce change, Stahl said. “The ones who do that too early are also on the wrong side of the game. We saw that especially with electric vehicles, where the early players did not make it.”
ENGIE North America CEO Frank Demaille said his company and Axium Infrastructure US recently signed a $1.2 billion 50-year contract with Ohio State University to map and implement the school’s energy sustainability strategy. One initial goal is to reduce energy consumption at the 485-building campus by 25% within 10 years. A contract with such a long lifespan means “you can really build something with a strong partner,” Demaille said.
Decoupling revenues from sales is a good start to make utilities “indifferent to increasing energy efficiency on their system,” Trotta said. Referring to the expansion of net metering, however, Trotta said, “We may need to see new rate structures in the future that send the appropriate economic signals to all of the users of the grid.”
There’s no doubt that the market structure and the rate design need to change, O’Connor said. “We want utilities to do much more now under the same rate structure from 20 years ago.”
On whether RTOs’ focus on reliability conflicts with the environmental goals of states, Macky McCleary of the Rhode Island Division of Public Utilities and Carriers said he preferred to acknowledge tension, rather than conflict. “It’s a shared concern, and the ISO can help make it cheaper to achieve those environmental goals,” he said.
“The only resources left to rely on the existing wholesale markets in New England are natural gas generators and old nukes,” said Susan Tierney, senior adviser with The Analysis Group. “Policymakers in the states are making a big bet that those markets will remain sustainable.”
ALBANY, N.Y. — At FERC’s technical conference May 1 and 2, several commenters observed that it is easier to coordinate state policy with wholesale markets when the market is a single state, as in NYISO.
But there was no groupthink on display at the Independent Power Producers of New York’s 31st Annual Spring Conference last week, where industry stakeholders and state and ISO officials debated carbon policy, zero-emission credits for nuclear plants, the closure of the Indian Point nuclear plant and the Champlain-Hudson transmission line.
In particular, the conference highlighted the differences between the administration of Democratic Gov. Andrew Cuomo and the Republican-controlled State Senate, the ISO and IPPNY itself.
Arguably, no state officials are pushing more ambitious changes for the electric industry than New York’s — with the Reforming the Energy Vision initiative — for transitioning to a less centralized, more renewable-based future.
Richard Kauffman, chairman of the New York State Energy Research and Development Authority and Cuomo’s top energy official, began his speech to IPPNY by acknowledging the tensions.
“That was quite a pointed introduction,” he joked when IPPNY CEO Gavin Donohue welcomed him to the podium after laying out the organization’s complaints over the state’s “out-of-market” policies.
Kauffman also acknowledged that “It’s no secret that we haven’t been in very good alignment with the NYISO.”
“I’m sure that Brad Jones keeps a copy of my love letter to him on his dartboard,” he said, referring to the missive he sent last July in response to comments the ISO filed with the Public Service Commission on the state’s Clean Energy Standard.
The letter dismissed NYISO’s filing as “misleading, incomplete and grossly inaccurate” and lectured the ISO on the need to combat climate change. Kauffman also accused the ISO of being “held captive” by stakeholders representing “status quo interest that are threatened by the renewable future” — singling out IPPNY by name.
At the conference, Kauffman declined to offer an opinion on the ISO’s carbon adder plan, saying officials of NYSERDA and the Department of Public Service had just begun to review it. (See related story, NYISO Carbon Adder to Test FERC’s Independence, IPPNY Panelists Say.)
But he made it clear any ISO plan would have to “harmonize” with REV and insisted the state’s actions were justified responses to market imperfections.
“We recognize the valuable role the federal wholesale markets can play,” he said. “But the truth is in our view those wholesale markets are not living up to their potential because of a failure to effectively harmonize with the states’ public policy. … Given the uncertainty in Washington, the state will not cede what it considers its role in energy and environmental policy.”
REV’s Objective
He said REV’s objective is to provide market-based incentives for private capital to build “the 21st century grid” with “a mix of central station production and distribution with distributed nodes; where supply and demand are dynamic and electrons can flow in more than one direction.”
The new grid must be “both more energy and capital efficient,” he said. “Fifty-four percent average capacity utilization — which is what our entire system is in New York state, a number which is declining — is a low number in terms of capital efficiency.
“We can’t achieve the governor’s mandate of 50% renewables by 2030 by doing things the same way. … We’ve been bolting things onto a system that it wasn’t designed for. Those things include renewables and [distributed energy resources]. … And the same way we’ve been physically bolting renewables and DER onto the grid never intended for these resources, we’ve recognized that we can’t keep bolting on policies onto a policy regime that was not intended for that purpose either.”
Kauffman said he would not answer questions about ZECs because of the suit filed by IPPNY members Dynegy, Eastern Generation and NRG Energy claiming the ZECs intrude on FERC’s jurisdiction. He said only that “the governor did not want to lose ground in carbon emissions by the upstate plants closing.” (See Federal Suit Challenges NY Nuclear Subsidies.)
Donohue concluded Kauffman’s session by imploring him, Jones and Scott Weiner, the DPS’ deputy for markets and innovation, to “keep working to come up with this market fix so that Chairwoman [Cheryl] LaFleur … can help us implement something to save our markets in New York.”
The Cuomo administration’s differences with the State Legislature were also on display as State Sen. Joseph Griffo (R), chairman of the Senate Committee on Energy and Telecommunications, told the conference that the Senate will “carefully vet” Cuomo’s nominees to the PSC. “It’s not going to be a pro forma type of submission,” he said. (See related story, Cuomo Names NYSERDA CEO as PSC Chair.)
New York State Assemblywoman Amy Paulin (D), chair of the Committee on Energy, outlined her objections to the statewide cost allocation of the ZEC subsidies, saying the costs for the upstate generators should not be imposed on her Westchester County constituents. Assembly members were left fuming in March when the PSC and NYSERDA declined to send witnesses to a hearing on the program and Exelon sent no senior executive with knowledge of the subsidy negotiations. (See NY Legislators Frustrated by Lack of Answers at ZEC Hearing.)
Indian Point
Some legislators are also upset with Cuomo’s deal to shut down the Indian Point nuclear plant by 2021. The governor has long opposed the plant because of its proximity to New York City.
In March, ISO and PSC officials told a joint hearing chaired by Paulin and Griffo that they are not concerned about replacing the capacity of the 2,069-MW plant, saying energy efficiency, transmission upgrades and the ISO’s wholesale market will ensure reliability.
IPPNY Chair John Reese, senior vice president of Eastern Generation, indicated in remarks to the conference that he is not satisfied with those assurances. “What does the future look like? We have no idea,” he said.
Reese said the ISO should begin an impact study on the retirement immediately rather than waiting for a formal retirement notice, which might not come until 2020 or later. “It takes a minimum of four to six years to build infrastructure in N.Y. If Indian Point presents an issue on [power] supply, we need to know now.”
Champlain-Hudson Transmission Line
“What should definitely be off the table [among potential Indian Point replacements] is the remarkably uneconomic Champlain-Hudson [Power] Express transmission line,” Donohue said.
Earlier this year, Paulin and Griffo introduced what Paulin called an IPPNY “priority bill” that would prohibit the New York Power Authority from purchasing energy from the proposed line (A07685, S05126.)
IPPNY claims the project — which would transmit 1,000 MW of Canadian hydropower to the New York metro area — could not be built without direct or indirect subsidies, such as “extra-market contracts” with a state entity. The project was proposed by Transmission Developers Inc., which claims the $2.2 billion project would be one of the largest investments in New York state history.
“The state’s view has not changed,” Kauffman said. “TDI is a merchant line. This means a customer or customers need to sign up for the power. … The cost of the transmission line will not be passed along to any ratepayers.”
Since she was appointed to FERC in 2010, acting Chair Cheryl LaFleur has served with seven commissioners and two chairmen, Jon Wellinghoff and Norman Bay.
The chairman sat down for an interview last week with RTO Insider editor Rich Heidorn Jr., a former FERC staffer, about whether the commission can maintain its reputation for nonpartisanship, her reflections on the commission’s May 1-2 technical conference on tensions between state policies and wholesale markets, and the grid security study ordered by Energy Secretary Rick Perry. The transcript below has been edited for clarity and length.
RTO Insider: So first off, a week after the technical conference, are you more or less optimistic about the future of the wholesale markets than you were before?
Cheryl LaFleur: I would say that the conference met our expectations, which I think were difficult to fulfill. We wanted to have all the different views represented and aired in a very transparent way to try to frame the issues and I think that happened. We wanted to get a better sense of what the consequences were of the different potential solutions, and I think to a large measure, that happened. And we wanted to create a sense of momentum behind the issue without having the ability to vote out anything to create a sense of momentum, and I think we did create a sense of momentum that we are now trying to sustain.
Cheryl LaFleur: Well, I don’t think this particular issue of state policies and the markets was really fully framed in 2013. Although I do clearly … Dr. Tierney did allude to it, and I remember at that 2013 conference, her distinctly talking about the Clean Power Plan and so forth, which nobody else was talking about then. I think actually, in my opinion, quite a lot came out of the 2013 tech conference. As part in response to conversations at that tech conference, we saw a settlement achieved in New England, which led to the sloped demand curve and the renewables exemption, which was very clearly discussed at the conference. And in some ways the Capacity Performance, Pay-for-Performance proposals that we saw come out of [PJM and] New England in some ways were generated by things at that conference so I thought that was one of our more productive conferences.
I said at the time of the 2013 conference and it’s still true, that there’s two competing things we hear all the time. The first is: Stop making changes in the capacity markets. And the second is: Make my change please. And I think the concept that when we’ve had a successful tech conference, it’ll be when nothing changes anymore because the world is going to be, as it is may be, illusory. Because I think the issues that are framed now in the 2017 tech conference have evolved.
RTO Insider: So, there was a reference earlier today to the Rick Perry comments and this need to study grid reliability. Isn’t that kind of a slap in the face to what you guys at FERC have been doing for the last couple of years?
Cheryl LaFleur: Well, FERC and DOE we have always worked in parallel or in a complementary way. I mean, they made [us] aware they were putting out the memo. Presumably they’re going to do this study. I don’t remember when the 60 days run out, but it’s relatively soon and it’ll be a piece that’s part of the conversation.
RTO Insider: So, would it surprise you if they came up with anything you haven’t already talked about?
Cheryl LaFleur: I can’t surmise that. I mean, there’s always new things under the sun.
RTO Insider: So let’s talk about the quorum news. How well do you know Powelson and Chatterjee?
Cheryl LaFleur: I know both of them. In general, I’m saying I’m very happy that we got the news. I appreciate the White House making the announcement. I appreciate Sen. [Lisa] Murkowski [R-Alaska, chair of the Senate Energy and Natural Resources Committee] saying she was going to act on them quickly. I tried to sort of in general not comment on individuals. But I do know these gentlemen. I’m very happy to see this news this week.
RTO Insider: And do you have any sense of when the player to be named later [third Republican nominee] may be named?
Cheryl LaFleur: I read in the press soon, but hopefully soon.
RTO Insider: What came out of the conference that perhaps most surprised you?
Cheryl LaFleur: Nothing was really surprising, but I think it was very important and informative to hear the different views of the different states, and we only saw [a] microcosm. I believe we had three of the PJM states there, and it was interesting to see where they were coming from I thought. Hearing the New England states — their representatives were very honest about some of the things they would and would not accept. I think that in itself, if that’s all we got out of the day, that would’ve had value. Because I mean they chose to come into a forum that was a FERC forum and express those views and that was very important.
RTO Insider: How does that play out when, let’s say, you get that filing from ISO New England for this two-tier capacity auction? Does having heard from the states give you some sense of, well here’s what the political realities are and we have to kind of take that into account?
Cheryl LaFleur: Well I would first of all hope that in the process that’s going to ensue between now and whenever any filing is made that there would be a discourse with the states as they go along. I feel like I’m on a little bit of a tour now because I’m in New York, doing PJM in a few weeks and then I’m going to [the New England Conference of Public Utilities Commissioners’ Annual Symposium]. And I know between the NECPUC meeting and then the [New England Power Pool] summer meeting, ISO New England will be talking a lot to the states. Certainly here in New York, one state, one ISO, so I would hope a lot of that would happen as they go along and it wouldn’t be a case of picking up a filing and finding out a state was unhappy that I didn’t know before.
RTO Insider: In other words, them filing an intervention.
Cheryl LaFleur: Or I mean I would hope that we would’ve known where the states were on the issues as we went along. Because really, as I said at the conference, the regional markets exist because of changes in state policy that gave rise to them. And they exist with the support of the states so they’re very important constituencies.
RTO Insider: If in fact the capacity market becomes less central to, let’s say operations in PJM, because public power persuades the commission that they should have more latitude, is that necessarily a failure of the markets? Or would you say that the capacity markets have always been kind of a Rube Goldbergian device, and so it’s to be expected some people may want to opt out of it?
Cheryl LaFleur: There are different ways you can do resource adequacy, and a spectrum of different ways you can do resource adequacy, and I try to have an open mind about the ways that the regions do it. If you look at the way the Southwest Power Pool does resource advocacy versus California versus New England, there’s different models.
I feel the only failure would be if we didn’t plan for resource adequacy and stumbled into something. Or if something fell between the cracks in the federal government and the state government. But different systems that different states come up with, I have an open mind.
RTO Insider: How, if at all, do you expect the new commissioners to change the dynamics on the commission? As long as I’ve been following the commission — back to when I worked there under Pat Wood — what I’ve always been impressed by in the FERC building, as opposed to much of the rest of Washington, is the lack of partisanship. We rarely mention commissioners’ party affiliations because you don’t really see that playing out in how they vote. Any reason to think that might change under the new regime?
Cheryl LaFleur: Well I think FERC does have the strong tradition of bipartisanship and making decisions based on the facts and the law, and I certainly hope that we’ll continue and that the new commissioners, as they’re sworn in, will continue in that tradition. I think in terms of the dynamics — not partisanship, just the dynamics in general — we’ll see a change in the commission the likes of which we haven’t seen since 1993, maybe even more. Because generally, you have one commissioner at a time come on, you have the four who were there and one individual comes on. And every time a new person comes, it changes the shape of the whole. But to have up to four come on at a time — including a chairman — that’s a big turnover. In 1993, four came at once, but the chairman was there already. So, that’s a big turnover. But I believe the tradition of — or more than a tradition — the expectation of making decisions by the record and bipartisanship will continue.
RTO Insider: Somebody had floated the notion that the president is not actually required to appoint two Democrats to the other seats. He can appoint three Republicans, but he can appoint independents or what have you. Have you heard anything about that — that there is going to be any change in the way they handle that?
Cheryl LaFleur: No I believe the law says only three of the president’s party. I have heard no changes.
RTO Insider: So you don’t anticipate that’s likely to happen.
Cheryl LaFleur: The White House has not shared with me their plans. I’ve said all along my hope is that they appoint people who are experienced in energy, and so far, they have.
RTO Insider: And along the lines of that, have you been given any indication whether they might continue you in an interim position as chair for a while after the new commissioners are sworn in?
Cheryl LaFleur: No.
RTO Insider: Okay. We’ll all have to wait to find out.
Cheryl LaFleur: I mean there’s so many different ways this can go. I think a lot also is riding on when the third nomination comes, and how these nominations proceed. But, regardless of how long I’m chairman, my focus right now is on getting the backlog and the issues that are pending before us framed in the best way we can to help the onboarding commissioners come up to speed, and helping the work of the commission to move forward. I intend to stay afterward as a commissioner so I’ll be there for the transition. But even if I weren’t, the FERC staff will be there, and many of them have been there through several chairmen.
RTO Insider: Is there anything that I haven’t asked you about that you want to put out there as your message coming out of either the tech conference, or just kind of the state of play right now?
Cheryl LaFleur: Well I guess I would just say on the tech conference, we have not yet issued, I don’t believe, our request for comments, but we hope to hear from voices beyond the ones who spoke at the tech conference. We know there were people who volunteered to speak, and others who might not have volunteered, but have something to say, and we hope to hear from them.
The only other thing you haven’t asked about is Commissioner [Colette] Honorable, which is also, it was only a couple weeks ago that happened. I was very sorry to hear her plans, although it’s obviously up to her. But she’s been a wonderful colleague and a great addition to the commission.
RTO Insider: Well we kind of assumed that prior to Commissioner Bay leaving, that her position would go to a Republican to make the balance. Once he left, in theory she could have stuck around. Do you know if she had an indication from the White House that she would not be reappointed?
Cheryl LaFleur: I don’t know any of that, and it’s not my place to say. While we’re talking about the new guys, she was great. She is great; she’s still there.
RTO Insider: And let me ask you one last question about the criticism of the public interest groups who claim they were not allowed to testify at the conference, and also about a lack of transparency in the RTOs. [See Public Interest Groups Cry Foul over Technical Conference, RTO Transparency.] I just wondered if you had any response on that, any comment on that.
Cheryl LaFleur: Well we tried to balance the panels and have a consumer viewpoint on every one of the panels, and I think we did, but as I said, we’re going to be putting out a request for comments and we certainly hope to hear from others as well.
RTO Insider: Are you happy with the level of transparency in the RTOs?
Cheryl LaFleur: I really don’t have any comment on that. We have an obligation to oversee their stakeholder processes and the way they decide things, and I asked a question about that at the tech conference in fact.
RTO Insider: I must have missed that.
Cheryl LaFleur: I don’t want to prejudge the … I don’t really have any comment. No, I think I picked up on one of the [witnesses] that said something about the stakeholder processes.
RTO Insider: Well thank you very much for your time, appreciate it.
CARMEL, Ind. — MISO last month called on load-modifying resources for the first time in 10 years after it declared an unusual mid-spring maximum generation emergency in the southern part of its footprint.
Unseasonably high loads coupled with a large number of generation and transmission outages precipitated the April 4 event in MISO South, RTO officials said in an emergency review.
| MISO
The region lost almost 1,500 MW of generation just after midnight when a large unit unexpectedly went down. MISO issued a maximum generation alert around 8 a.m., and by 1 p.m., all resources were in use, with LMRs called up about two hours later. To compound conditions, temperatures topped 80 degrees Fahrenheit, exceeding April averages by about 8 degrees and driving unexpectedly high load.
“What we saw is temperatures that were more typical for May,” Rob Benbow, senior director of systemwide operations, said at a May 11 Market Subcommittee meeting.
Transmission outages were also higher than normal, with some lines down from earlier severe weather and seasonal maintenance, stranding generation in some cases. Spring maintenance season also sidelined a large number of generators.
All told, MISO called up about 730 MW of LMRs in MISO South to cover a projected 447-MW energy shortfall, marking the first time the RTO has relied on the resources since 2007.
“It’s the first time we’ve deployed load-modifying resources in quite some time,” Benbow said. “This isn’t unusual where you’ve got a lot of maintenance outages and high load in shoulder times.”
Benbow said MISO’s new emergency pricing floors were initiated during the event and worked as intended. By about 9:30 p.m., emergency operations were lifted.
“I fully support overdoing it,” ITC’s Ray Kershaw said. “When you hit the button, you’re not sure how many peakers are going to show up. … You did your job, that’s for sure.”
MISO is still collecting meter data from the event and will evaluate the performance of the LMRs, Benbow said. Stakeholders asked whether operators of those resources are required to respond to run requests from MISO outside of summer peak conditions, an issue RTO staff said they would investigate.
Benbow credited successful management of the emergency event to MISO’s extensive drills. “You only get this through training,” he said.
MISO Officially Expands ELMP
MISO this month expanded its extended locational marginal pricing (ELMP) program to allow online units with one-hour start-up times to set prices.
The program — now entering its second phase — was previously available only to 10-minute fast-start resources.
The move means that 58% of MISO’s capacity is eligible to qualify as peaking resources, compared with 8% beforehand.
FERC accepted MISO’s filing to expand ELMP in an April 20 letter order (ER17-1081).
Twelve newly eligible resources participated in ELMP price-setting during the first day of implementation, said Concong Wang, MISO market design engineer.
MISO’s second phase of ELMP fell short of its Independent Market Monitor’s recommendation that price-setting be extended to all resources with a two-hour minimum run time. (See “MISO to Expand ELMP Price Setting, but not to IMM’s Specs,” MISO Market Subcommittee Briefs.)
Wang said MISO will present a post-implementation analysis at the December MSC meeting, after collection of about six months’ worth of data.
Additionally, the RTO is planning to discuss a potential new trading hub in Mississippi at the June 8 MSC meeting, Director of Forward Operations Planning Kevin Sherd said.
Proposal Would Address Cost Recovery Gap
MISO will revise its Tariff to address two possible gaps in cost recovery when units are manually redispatched offline.
The new language will allow generators to recover start-up costs and day-ahead margin assistance payments during required minimum down times following an RTO-ordered decommittment.
“We currently don’t allow for recovery of start-up costs when a resource is taken offline,” said MISO Market Quality Manager Jason Howard.
When MISO decommits a day-ahead resource, the day-ahead margin assurance payment does reimburse the resource for minimum down times or start-up costs. (See “Potential Cost Recovery Gap in Manual Redispatch,” MISO Market Subcommittee Briefs.)
MISO will file the language by the end of May and seek a next-day effective date, Howard said.
He also said he would have to follow up on a question by Customized Energy Solutions’ Ted Kuhn, who asked if MISO enforces any limits on a resource’s minimum downtime.
MISO, PJM in ‘General’ Agreement over Pseudo-Tie Congestion Remedy
MISO and PJM are in “general” agreement about using an interim rebate program to handle their overlapping pseudo-tie congestion charges, according to MISO Director of Forward Operations Planning Kevin Vannoy.
Vannoy said PJM is still reviewing a slight modification to the original agreement: that the RTOs exchange information about firm flow entitlements a day before a flow date to better predict the effect of congestion on pricing.
The RTOs proposed the rebate solution in early March as a stopgap. A longer-term solution will involve scheduling pseudo-ties in the day-ahead process. (See MISO, PJM Propose Solution to Pseudo-Tie Congestion Problem.) They have postponed their ambitious June 1 implementation date for the program to early September. Staff from both will review the solution again at the May 23 Joint and Common Market Initiative meeting held at MISO’s Carmel, Ind., headquarters.
ALBANY, N.Y. — About 200 industry stakeholders and state and NYISO officials discussed carbon policy, zero-emission credits, and other pressing and contentious issues at the Independent Power Producers of New York’s 31st Annual Spring Conference last week. Here’s some of what we heard.
This year’s conference was held at the new Albany Capital Center. IPPNY CEO Gavin Donohue is chairman of the Albany Convention Center Authority, which built the $78 million project a block from the state capitol.
Event organizers ordered tighter security than in years past. No one without a registration badge was allowed near the event.
“You know what happened at the last conference,” recounted Donohue, referring to the May 2016 event at the Desmond Hotel, when anti-pipeline protesters took over the stage as then-FERC Chair Norman Bay was speaking.
Energy Policy Under Trump
In a panel on energy policy under President Trump, attorney Steven Croley, a partner with Latham & Watkins who served as general counsel for the Department of Energy under President Barack Obama, led the audience in a “thought experiment” comparing Trump’s energy policy with that of a fictional third Obama term.
Croley said Trump will have a smaller impact than some critics fear, calling the policy differences between the two administrations “susceptible to exaggeration,” Croley said.
For example, he said the scale of LNG exports will be driven by world demand, not any new federal policy.
Neither Trump nor Obama would back federal funding of utility-scale solar projects. The Obama administration funded five such projects, but the falling prices of solar technology made additional federal support unnecessary, he said.
Croley acknowledged that Trump has substantial discretion over how aggressively to enforce existing environmental rules but said that states or environmental groups will likely sue if they believe Trump’s EPA is ignoring major violations.
“[Non-governmental organizations], states [and] state regulators are all important drivers of national policy too. They will fill what is perceived to be a regulatory gap or regulatory inaction to some extent,” he said. “Every White House will create its antibodies. Believe me, that’s how it works.”
Indeed, Kit Kennedy, director of the energy and transportation program for the Natural Resources Defense Council, said her organization has increased its litigation team, which has filed 10 lawsuits against Trump’s efforts to roll back environmental policies. She said the organization is also increasingly looking to state and local governments for leadership.
She was more alarmed than Croley, saying “what the president says and does really matters.”
“We’re seeing an onslaught on bedrock environmental safeguards and laws from President Trump today that we’ve never seen before,” she said. “The situation is fundamentally different” from the Reagan and Bush administrations.
Kennedy engaged in a more vigorous debate with James Taylor, an adviser to the presidential campaign of Energy Secretary Rick Perry and president of the Spark of Freedom Foundation, which promotes natural gas, hydro and nuclear power as “affordable” and “environmentally friendly” sources.
“Renewable is not synonymous with green,” Taylor said, citing the environmental impact of mining for rare earth minerals used in solar panels — which he said is worse than uranium mining.
“Wind turbines kill 1.5 million birds and bats each and every year in this country, including many endangered and protected species. It also requires hundreds of square miles of wind turbines to replace a single conventional power plant. For conservationists, that should trouble us.”
He said federal policy should be based on “full spectrum” environmental impact analyses “that [go] beyond the renewable and non-renewable definition and looks beyond carbon dioxide emissions.”
IPPNY Chair John Reese, senior vice president of Eastern Generation, celebrated the completion of NYISO’s demand curve reset but criticized FERC’s decision to not include the costs of environmental controls for the proxy upstate unit.
“It takes about two years to go through that process and lots of pain and suffering and gnashing of teeth. I think IPPNY did a great job in representing the needs of generators and what it takes to get market investment,” he said.
But he said FERC erred in its January order, which rejected requests by IPPNY and the ISO to assume selective catalytic reduction (SCR) emissions controls for the proxy unit for zones C and F.
In its prior reset, NYISO proposed that the New York Control Area peaking plant operate under an annual operating hours limit in lieu of installing SCR. FERC said that assumption still holds, despite the ISO’s contention that peakers without the controls risk not obtaining necessary air permits. FERC rejected as “speculative” IPPNY’s contention that the state’s Siting Board is likely to require tougher controls in the future. (See FERC OKs NYISO Demand Curve Reset.)
“If you’ve done business in New York — if you have developed projects — to imagine that you could build a fossil generator in upstate New York without State of New York controls is just foolishness,” Reese said. “It just cannot be done.”
IPPNY filed a rehearing request on the issue in February (ER17-386).
While PJM and its Independent Market Monitor agree that its markets “work” and are competitive, they disagree on what might make them better.
Those differences were highlighted last week when the Monitor released its first quarterly State of the Market report of the year, followed by the RTO’s response to the Monitor’s 2016 report.
The quarterly update revised just two of the Monitor’s existing recommendations for Incremental Auctions. It added a proposal that PJM should hold only one IA annually, three months prior to the start of the delivery year.
It also recommended that the RTO release cleared capacity at those auctions “only in cases where the combination of quantities released and associated prices would increase the welfare of capacity market resource owners and load” with consideration for both capacity and energy market benefits.
In response to the Monitor’s original recommendations, PJM agreed “that the structure and format of Incremental Auctions should be reviewed” and pointed to the recently created Incremental Auction Senior Task Force to address those concerns.
But the RTO disagreed with many of the Monitor’s other recommendations, including how to handle demand response resources and uplift. PJM said the EPSA v. FERC Supreme Court case ruled that DR should receive full LMP payments and — despite the Monitor’s recommendation that “any generation component of their retail rate” be subtracted from DR payments — doesn’t plan to challenge the ruling.
| PJM
On uplift, PJM said many of the Monitor’s recommendations were considered by the Energy Market Uplift Senior Task Force, which debated the issue for several years before coming to a consensus on a three-phase plan that was endorsed by members — despite ongoing controversy — during April’s Markets and Reliability Committee meeting. PJM is waiting to submit the plan for FERC approval until the commission has a quorum. (See PJM MRC OKs Uplift Solution over Financial Marketers’ Opposition.)
The largest rift between the Monitor and PJM seems to be whether to allow inflexible units to set LMPs. The Monitor opposes the idea, but PJM argued that “allowing inflexible units to set [LMP] would create an outcome in which [LMP] increases more consistently as load increases.”
| PJM
PJM believes that — along with the addition of a load-following product — allowing inflexible resources to set LMP would reduce uplift, increase system flexibility and promote enhanced gas-electric coordination.
The changes would also benefit what appears to be PJM’s goal of increasing its energy market prices. In its response, the RTO raised concerns about steadily declining prices thanks to cheap, efficient gas units, increasing renewables and stagnant demand growth partially attributable to energy-efficiency improvements.
Recent low prices, combined with hesitancy to invest in the market and public-policy actions in order to address socioeconomic concerns, “test market price formation and long-term viability,” PJM said.
The effects of units not properly incentivized to follow PJM’s dispatch signals, along with an increasing role for the capacity market in resource entry/exit decisions, “accumulate over the longer term to create unintended bias toward low capital-cost resources with high operating costs,” it said.
| PJM
Low prices have created a recent rush to subsidize unprofitable generation, such as through the creation of zero-emission credits in New York and Illinois. PJM and the Monitor agree that’s ill-advised.
“Although some state subsidies may intend to address the financial problems that some generators face due to declining energy prices, paradoxically, the subsidies actually may make the problem worse because they further depress market prices, causing needs for more subsidies,” PJM said. “As the 2016 State of the Market Report indicates, however, subsidies are contagious and could spread. If subsidies do become more widespread, they could deter new entry while the suppressed price could artificially raise demand, causing supply shortages in the long term.”
| PJM
Instead, PJM suggests pricing carbon at the state level if necessary, or implementing its “capacity market repricing” proposal that would allow subsidized resources to be counted toward PJM’s installed reserve margin without impacting the capacity clearing price.
While PJM and the Monitor remain at odds on the role of inflexible units in the market, the RTO is working toward some of the Monitor’s recommendations. The RTO will bring a problem statement to the Market Implementation Committee or the MRC to create comparable flexibility of the operating parameters in the cost-based offer and price-based parameter limited schedule (PLS) with the non-PLS price-based offer. It will also address the Monitor’s recommendation that market participants have at least one cost schedule with the same fuel type and parameters as that of their offered price schedule.
As soon as new commissioners are seated at FERC, they will have fundamental and controversial market design questions to resolve.
Gramlich
Some of those questions will be decided in states in terms of the benefits of those policies to those states, and some will be decided by courts in terms of their legality. For their part, the new commissioners will need to choose sides in the never-ending supplier vs. customer debate on capacity obligations and markets.
Or will they?
The Great Divide
The FERC technical conference on potential conflicts between state policy and RTOs/ISOs on May 1 and 2 revealed the same splits as in 2013 and previous commission reviews of capacity markets. Suppliers believe prices should be higher to attract and retain needed resources, while wholesale customers believe capacity markets fail to serve their needs. The main outcome of the 2013 review, which was to improve price formation, has helped a little, and more can still be done there to reflect scarcity in prices.
Carbon pricing was endorsed by many participants as the best economic policy solution for current market challenges, but that doesn’t seem to be a silver bullet either, as putting it in FERC-jurisdictional tariffs was not widely embraced by states. Searching for a third way, ISO-NE and PJM introduced proposals to raise capacity market prices. But explicitly discriminating between supply sources in terms of eligibility and pricing based on someone’s determination of what is “subsidized” and by how much seems hardly like a way to reduce litigation. The higher capacity prices will also lead to further unneeded entry on top of today’s generation surplus that customers will not be happy about paying for.
So this customer-supplier divide remains. And PJM’s recent Capacity Performance changes, now in litigation, created more capacity market enemies by preventing renewable energy resources from selling their capacity value. No wonder there was so much frustration at the conference.
What if we re-evaluate the fundamental objectives of capacity obligations? Do some of the debates become moot?
Mandatory Capacity Obligations No Longer Necessary?
When FERC reluctantly accepted mandatory capacity obligations on load-serving entities in the early 2000s, it was for three reasons that may no longer exist: 1) “resources take years to develop,” 2) “spot prices that are subject to mitigation measures may not produce an adequate level of … investment” and 3) “regional resources are made available to all regional load-serving entities” with no ability to curtail those customers who failed to procure enough.[1]
Point 1 is no longer true, with demand response and batteries now able to enter markets and provide peak energy within six months. Point 2 can be fixed with scarcity pricing and raising offer caps. Point 3 may not be true any longer either, with improvements in metering, control and scarcity pricing. So maybe capacity markets are only fighting the last battle and failing to solve future challenges.
Resource Adequacy Responsibility in the Future
The commission appropriately wants to make sure someone is responsible for generation meeting load at all times. As with any market in any sector, primary responsibility should be put on customers to procure the supply they need. Wholesale customers today have a range of preferences in terms of resource types, fuel price risk management and environmental attributes.
Some LSEs will be guided or required by states in their resource planning. Either way, their resource choices should be respected and supported to do most of the resource planning work. They have newfound abilities to cover themselves now that batteries can be deployed in six months with exactly as much as is needed, along with DR, in contrast to the past when they had to plan three or more years ahead for lumpy generation assets.
Reliability when Scarcity Conditions Arise
When it comes down to real time, and scarcity exists, RTOs and FERC still need to make sure the system can be balanced. Scarcity conditions may occur at very different times of day and year than in the past, as we are seeing in California and other markets, given different load and supply stack shapes. Reliability during these scarcity conditions can be satisfied if either a) pricing prevents LSEs from demanding more power than is available, or b) the system operator can physically curtail loads that caused the shortage.
We should allow for the possibility that efficient real-time energy markets with today’s pricing and control systems will do the job. RTOs could define short-term products purely according to system requirements and allow all sources to compete on a level playing field. Technology neutrality would help attract batteries, different demand sources and other new technologies to enter to serve system needs. ERCOT is closest to this market vision at this point, though it isn’t fully there.
Completing the Transition
With primary reliance on bilateral contracting for resource adequacy and RTOs focused on their core mission of bid-based security-constrained economic dispatch in real time as a backstop, we can take the competition training wheels off and support a bright, clean, efficient and reliable future power system. We can accommodate rather than work against state policies. We can pull back on RTO mission creep and thereby encourage greater participation in the efficient regional energy markets that are needed for clean energy development in the non-RTO parts of the country. Let’s see if we’re ready to move past the old debates and design the RTO markets of the future.
Rob Gramlich, founder of Grid Strategies LLC, was Economic Advisor to FERC Chairman Pat Wood III in 2001-2005 and Senior Economist in the PJM Market Monitoring Unit covering capacity markets in 1999. Most recently, he was Senior VP for Government and Public Affairs for the American Wind Energy Association.
[1]SMD NOPR, July 2002, par.461, citing Power System Economics by Steven Stoft.
