Page 1523 – RTO Insider

May 18, 2017

Retiring CAPS Head Dan Griffiths Feted at Annual Meeting

By Rich Heidorn Jr.

CHICAGO — The PJM Annual Meeting marked the swan song for longtime consumer advocate Dan Griffiths, executive director of the Consumer Advocates of the PJM States.

Dan Griffiths state consumer advocates — Griffiths | © *RTO Insider*

PJM officials and stakeholders feted Griffiths on Monday at the annual meeting between the PJM Board of Managers, environmental groups and state consumer advocates. Griffiths, who became CAPS’ first executive director in September 2013, is being replaced by Greg Poulos, former director of regulatory affairs for demand response provider EnerNOC. (See CAPS Hires EnerNOC Alum as Executive Director.)

state consumer advocates dan griffiths — Poulos | © *RTO Insider*

PJM CEO Andy Ott called Griffiths “a tremendous friend for many years.”

“Thank you very much for all you’ve done to bring CAPS to a level that it’s at,” he said. “The fact that there’s 22 [consumer advocates] here discussing these issues is a tremendous message of engagement. The desired outcome of these discussions is to make sure we understand each other, to communicate with each other and we move forward in a cooperative way.”

Griffiths responded with praise for the PJM stakeholder process. “The collegiality — even for people that I almost always disagree with — is fantastic,” he said. “I have never seen this anywhere else.”

Metrics

Griffiths started his career in 1979 at the Pennsylvania Public Utility Commission, developing metrics for utilities’ consumer services performance. He began specializing in electricity after restructuring in 1997, with several stints in private industry before returning to state government in 2000 as an assistant under then-Consumer Advocate Sonny Popowsky, a vacancy created when predecessor Denise Foster joined PJM. He retired from state government at the end of the Ed Rendell administration in 2010 as a deputy secretary of the Department of Environmental Protection’s Office of Energy and Technology Deployment.

He later served as DR provider Comverge’s delegate to the PJM stakeholder process. He was in that role when the newly formed CAPS selected him as its first executive director, using proceeds from Constellation Energy’s settlement with FERC in a market manipulation case. (See Consumer Advocates Name Director.)

Griffiths said the idea for CAPS began with conversations among him, Popowsky, West Virginia Public Advocate Jackie Roberts and Maryland Senior Assistant People’s Counsel Bill Fields.

CAPS’ biggest accomplishment during his tenure was helping state consumer advocates become engaged in PJM’s stakeholder process, he said in an interview at the Annual Meeting on May 15. “The first purpose was to make them understanding enough so that they could make decisions, so that they could vote in the stakeholder process … and be able to make thoughtful filings as opposed to ‘just say no’ filings.”

The engagement has been illustrated in the recent Capacity Construct/Public Policy Senior Task Force (CCPPSTF), he said.

“We had a one-hour meeting today to discuss it. We’ve probably had eight hours of phone calls … over the past several months to talk about it,” he said. “The CAPS members — the state consumer advocates — really do have a drive to understand the policy now and be part of creating, rather than reacting to it.”

Permanent Funding

The Constellation money would have run out next year, so PJM’s decision to provide permanent funding — via a bill surcharge similar to that used to fund the state regulators’ Organization of PJM States Inc. — was crucial to its future.

FERC approved an initial annual budget of $450,000 in 2016. In addition to paying for the executive director, the funding also is used to cover advocates’ travel to PJM meetings. (See FERC Approves PJM Funding of Consumer Advocates.)

“We have ongoing funding and we’ve got [an] executive director who is outstanding: creative, ambitious, excellent in outreach and coalition building … and articulate,” Griffiths said. “And so I think that CAPS will be better after me. I think I’m leaving at the right time.”

Griffiths said the 13 states (and D.C.) in CAPS understand the impact of PJM on their customers’ electric bills.

“They wouldn’t be here if their [state] offices didn’t make a decision to dedicate resources to the PJM process. I think everybody understands now just how important that is. In a competitive state like Pennsylvania, you might have 70% of your electric bill that comes through the PJM process. You cannot mitigate that by doing things at the state level, no matter how much you want to. And even in … [vertically integrated] West Virginia, 50% of their process is coming through the PJM process.”

“Pennsylvania uses … about 138 million MWh. [Actually more than 146 million MWh in 2015, according to the PUC.] And if the pricing is [increased] by a buck, that’s a $138 million hit to the Pennsylvania economy. … There are Market Monitors out there who think a few bucks here or there is like, ‘Okay, that’s fine.’

“It’s not fine,” Griffiths continued. “Consumers are hurt even by small pricing errors, and so it’s important for [Independent Market Monitor] Joe Bowring to be able to continue to do his job and PJM to be vigilant about making sure that the prices are right. There’s people [on the supply side] who have a natural incentive — they have a fiduciary responsibility — to make prices go up.”

Asked what advice he had given Poulos, Griffiths responded: “There’s all these pieces [that] work together. You cannot just [focus on] the markets because it seems like that’s where [the money] is. If you have a [load] forecast that’s one level and it could be 2.5% less — as we found over the last couple of years as PJM changed its forecasting process —that’s 2.5% of a whole lot of money. You can’t neglect any of this stuff because the scale is so huge and it interacts. Energy market performance affects capacity, offer caps. And so it just keeps rolling along.”

Going Solo

Poulos, who previously worked as an assistant in the Office of the Ohio Consumers’ Counsel, has been working for CAPS under Griffiths since the OPSI annual meeting in April. So is he ready to go it alone?

“Absolutely not,” he laughed during an interview Wednesday, describing the last several weeks of Griffiths’ tutelage as “drinking from a firehose.”

“But I’m in a really good position. He was so helpful with all the information. He has such a wealth of knowledge, even about the stakeholder process.”

“He was a true champion for consumers. That is very clear. He’s done a great job of advocating on behalf of the advocates and consumers. At the same time, he was a true friend and colleague to all [in the stakeholder process],” Poulos continued. He taught “the value of being a part of the community and making sure you participate and get to know everybody.”

On some issues, such as the cost and transparency of transmission expansion projects, CAPS is likely to have a unified position. But Poulos said there are times when his role will be less a lobbyist than a facilitator, providing information for individual state advocates.

In preparing for FERC’s May 1-2 technical conference on tensions between state actions and wholesale markets, “it was very clear that we at CAPS did not have a position and could not have a position,” he said. Some advocates “wanted to [accommodate] state actions and others want a true market where state actions aren’t considered.”

Off to Europe

Griffiths left the annual meeting early Tuesday to begin a month-long trip to Austria, Switzerland and Italy with his wife, Maureen Mulligan, a retired solar energy and energy-efficiency activist.

He hasn’t closed the door to returning to the industry in some fashion but has no plans. “I cannot come back here and work for anybody on the supply side … because their interests are so different than [consumers] and I think people … would think I was being hypocritical,” he said.

“I talked to folks a little bit about [doing] things outside PJM but I’m not dying to travel. I’ve done a lot of travel in my years. You know, after a while there’s no glory in travel. It’s just the torture you go through to do your job.”

May 18, 2017

CAISO: Analysis Needed Before Reforms on CRR Auctions

By Robert Mullin

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.

The shortfalls have cost California ratepayers more than $560 million over five years, according to the ISO’s internal Market Monitor. (See CAISO Monitor Proposes End to Revenue Rights Auction.)

“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.

bautista alderete congestion revenue rights auctions caiso — 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.”

May 17, 2017

CAISO Recounts Tense Hours Leading to May 3 Emergency

By Robert Mullin

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.

The emergency triggered the use of demand response programs managed by the ISO’s member utilities. (See California Grid Emergency Comes Days After Reliability Warning.) A more critical “Stage 3” signals the threat of blackouts.

Warm Day

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.”

May 17, 2017

MISO Reaffirms 2023 End Date for Market Platform

By Amanda Durish Cook

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 market platform — 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.

May 16, 2017

MISO Market Subcommittee Briefs

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.

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.

MISO Market Subcommittee cost recovery gap — Benbow | © *RTO Insider*

“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.”

MISO forecasts a 79.3% probability that it will again call up LMRs this summer. (See MISO Slims Summer Reserve Prediction.)

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.

— Amanda Durish Cook

May 16, 2017

Overheard at the IPPNY Annual Spring Conference

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.

The Independent Power Producers of New York’s 31st Annual Spring Conference was held at the new Albany Capital Center, where the IPPNY logo was displayed in lights in the ceiling. | © *RTO Insider*

New Venue, Tighter Security

IPPNY demand curve carbon policy — Donohue | © *RTO Insider*

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.”

Problems with New Demand Curve

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).

May 16, 2017

PJM Differs with Monitor in State of the Market Response

By Rory D. Sweeney

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 state of the market report — | *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 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.

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.”

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.

May 16, 2017

Stakeholder Soapbox: Organized Markets for the Future

By Rob Gramlich

As soon as new commissioners are seated at FERC, they will have fundamental and controversial market design questions to resolve.

mandatory capacity obligations FERC technical conference — 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.

May 16, 2017

Hydro, Solar Boost CAISO Summer Outlook; Aliso Concerns Remain

By Robert Mullin

CAISO should have sufficient generation to meet peak demand this summer, although questions still linger about the adequacy of Southern California natural gas supplies in the face of a heat wave.

The ISO’s 2017 Summer Loads and Resources Assessment, which describes the grid operator’s preparedness for California’s season of peak electricity usage, paints a generally promising picture. Under “normal” summer conditions, operating reserve margins will average 19.5%, compared with the 15% required by the Public Utilities Commission.

hydropower aliso canyon natural gas — The continued closure of the Aliso Canyon natural gas storage facility remains an issue for the summer readiness of the Southern California grid.

About 52,785 MW of capacity is expected to be on hand to meet this summer’s predicted peak load of 46,877 MW, which would be 0.6% more than the weather normalized peak for 2016.

“The slight overall demand increase is a result of projected modest economic and demographic growth over 2016, tempered by utility projections of new behind-the-meter solar installations over the past year,” the report said.

Summer peak demand could spike to 48,845 MW under conditions that occur only once every 10 years, CAISO said.

The ISO expects 3,090 MW of new generation will have entered commercial operation during the 12 months leading up to this June, 2,566 MW of which is in the southern part of the system — service territories controlled by Southern California Edison and San Diego Gas and Electric.

Nearly three-quarters of the new resources consist of solar (74%), followed by natural gas (23%), storage batteries (3%) and a fraction of a percent each for hydro and biofuel.

California’s hydro conditions have “vastly improved” over last year, the ISO noted. On April 28, statewide snow water content stood at 158% of normal for April 1, typically the peak date for Sierra Nevada snowpack. The state is also experiencing a near record year for precipitation.

“This abundance of rain has nearly all reservoirs near capacity and needing to spill water to make room for spring snow runoff,” CAISO said.

But uncertainty still looms over the outlook for Southern California, where gas-fired generators confront a second summer of fuel supply restrictions stemming from the closure of the Aliso Canyon storage facility. (See Aliso Canyon Gas Restrictions Cloud Summer Outlook.)

The ISO pointed out that its analysis is a “system level” assessment and does not account for gas curtailment risks associated with emergency restrictions on the pipeline system operated by Southern California Gas, owner of the facility north of Los Angeles.

“There are limitations in attempting to shift power supply from resources affected by Aliso Canyon to resources that are not affected because of certain factors such as local generation requirements, transmission constraints and other resource availability issues,” CAISO said in its report.

A joint agency report to be released later this month will address the ongoing risks to the grid posed by continued prohibition on gas injections into Aliso Canyon. The report’s authors include CAISO, the PUC, the California Energy Commission and the Los Angeles Department of Water and Power.

Mild conditions and a series of temporary ISO market measures helped the region’s grid to weather last summer without any major incidents related to constrained gas supplies. FERC last December approved an ISO proposal to extend those measures through November 2017. (See FERC OKs One-Year Extension for CAISO’s Aliso Canyon Gas Rules.)

The ISO last winter also said it would adopt a recently approved West-wide reliability measure to help ensure that it has sufficient capability to transmit power into Southern California via the Path 26 transmission line when needed. The new measure approved by Peak Reliability — the West’s reliability coordinator — allows a system operator to selectively relax a transmission network’s seasonal performance standards in response to “credible multiple contingences” under emergency conditions. (See CAISO to Rely on New Emergency Measure to East Path 26 Transfers.)

May 16, 2017

SPP Members Again Struggle with Solutions to Z2 Credits

By Tom Kleckner

SPP stakeholders’ effort to simplify the RTO’s complicated crediting system for transmission upgrades continues to spin its wheels.

Members once again discussed alternatives to SPP’s cumbersome Z2 process during an all-day meeting in Kansas City on Wednesday, but they adjourned without reaching any major decisions. (See SPP Z2 Panel Sees ILTCRs as Cure to ‘Mess of Complexity’.)

SPP z2 credits — Buffington | © *RTO Insider*

“It feels like we’re going over the same material every time,” said the group’s chair, Kansas City Power & Light’s Denise Buffington. “At some point, we have to get to where we can make a decision. We have to pull the trigger eventually, and it’s clear to me we’re not ready.”

The group did agree to schedule two additional meetings next month to improve its chances of presenting a recommendation in July to the Strategic Planning and Markets and Operations Policy committees.

The task force rehashed the pros and cons of two of the alternatives they have settled on: staff recommendations to replace Z2 credits with incremental long-term congestion rights (ILTCRs) or credit payment obligations (CPOs) under a Tariff schedule. Westar Energy’s Grant Wilkerson has proposed a third alternative, in which only upgrades that create transfer capability would receive credits under the Tariff.

Under Attachment Z2 of SPP’s Tariff, members are assigned financial credits and obligations for sponsored upgrades. The task force is trying to simplify the process while still meeting FERC requirements.

Several stakeholders raised concerns over using ILTCRs to replace Z2 credits, arguing that SPP’s transmission congestion rights (TCR) market is not yet fully functioning. Charles Cates, the RTO’s manager of transmission services, disputed that perception, saying the market is “working very well.”

“Seventy-eight percent of the load entities are fully hedged,” Cates said. “It’s a perception I do not agree with.”

“That’s not a perception OGE shares,” said Oklahoma Gas and Electric’s Greg McAuley, expressing a different viewpoint. “If you dilute a TCR market that’s not fully functional because you’ve never really used an ILTCR yet … I don’t know why you would do that intentionally.

“Z2 is functioning. Some people may not like it, but it’s doing the job it was designed to do. From OGE’s perspective, we’re getting credits for the upgrades that have been put in palace, and we’re also paying for upgrades that have been in place. We have a system that’s in place and working.”

“I’m hearing that we’re trading one set of problems for another set of problems,” NextEra Energy Resources’ Aundrea Williams said. “I want to make sure we don’t lose sight of the ultimate goal of simplification and transparency. I don’t want us to completely discount [that] Z2 can be improved, but the objective doesn’t have to be to get rid of it.”

Cates, who has been tasked with developing the ILTCR alternative, warned against changes to SPP’s market design, saying adding an auction revenue right mechanism connected to financial rights is a disconnect from the original purpose of the design.

“The unintended consequences of going this route could be profound — or not. It’s hard to say at this point,” he said to laughter. “If we’re not careful, the complaints I hear about the TCR market not working — which I personally don’t agree with — could get more loud.”

The moments of levity, while lightening the mood, did not diminish the difficulty of the task before the group.

“The problem I have now is every time I think I understand it, I don’t,” McAuley said. “I don’t have a problem going back to MOPC and saying this is a complicated animal. I don’t want to approve one of these [alternatives] and have a bigger mess on our hands because we didn’t understand it.”