Page 1027 – RTO Insider

June 17, 2019November 29, 2023

Counterflow – Fuel Security: PJM Does ‘Seinfeld’

By Steve Huntoon

Setting the Stage

PJM’s capacity market (the “Reliability Pricing Model”) reversed a deteriorating reserve margin, efficiently assuring resource adequacy years into the future while integrating demand response and renewable resources.

It’s been a bulwark against bailout claims for coal and nuclear units by enabling a transition from dirty coal and inefficient nuclear to cleaner natural gas and clean renewables. And the Capacity Performance refinement to RPM incents resources to be available when needed, further enhancing reliability.²

Notwithstanding all this, the coal/nuclear bailout lobby has created doubt about the “security” of generation resources that lack fuel on site, i.e., natural gas generators without oil storage backup and of course renewable (intermittent) resources generally. This has led to a new buzzword, “resiliency,” as something other than “reliability” and resulted in a broad inquiry into “fuel security” at PJM.

Solution in Search of a Problem

Let’s start by putting “fuel security” as a risk in context. Please recall what the Rhodium Group figured out for us in 2017 and nobody has refuted (emphasis added):³

“Between 2012 and 2016, there were roughly 3.4 billion customer-hours impacted by major electricity disruptions. Of that, 2,382 hours, or 0.00007% of the total, was due to fuel supply problems. Interestingly, 2,333 of those customer-hours were due to one event in Northern Minnesota in 2014. And it involved a coal-fired power plant.”

Thanks again, Rhodium Group, for this great emperor-has-no-clothes exposé.

Risk, or Lack Thereof, in PJM

So how can PJM come up with a “fuel security” problem? PJM acknowledges there’s no problem now. But it creates worst-case scenarios for a potential problem in the future, say 2023-2024.

Here’s how it goes. PJM created 324 scenarios, and in some of the most extreme, it found load shedding (outages) could occur.

Let’s look at the worst of the worst-case scenarios, where PJM finds that there could be 83 hours of load shed for an average of 2,452.8 MW. Now 83 hours sounds like a lot, but we need to remember that load/demand during this peak period is about 140,000 MW. So when load shed is spread across the system, it’s an average of 1.5 hours for any given customer.⁴ So this worst of the worst-case scenarios is tiny.

Now, how likely is this worst of the worst-case scenarios to occur in any given year? For starters it’s based on a 1-in-20-years extreme-winter condition. And it’s based on a “high pipeline disruption,” meaning the loss of an entire pipeline flow in a right of way. This is an extremely rare event and has never caused a major detrimental gas supply loss to PJM generation,⁵ but let’s be very conservative and assume there’s a 1-in-10-year chance of that both happening in PJM and happening in the winter. Now, what’s the chance of that disruption occurring at the same time as the extreme 14-day winter condition? About 1 in 6, because 14 days are about one-sixth of a three-month winter period.

OK, here’s the math: 1/20 times 1/10 times 1/6 equals 1/1,200. Yes, you got that right. Once every 1,200 years we might experience a tiny 1.5 hours of outage for the average PJM customer. We should live so long.

But Wait, There’s More

If you can believe it, this tiny risk overstates the real risk. Here’s a few reasons why:

1. 1. Winter generation capability is much more than summer capability. PJM doesn’t appear to gather that data, but we know from New England that aggregate winter capability is about 8% more than aggregate summer capability.[6] In PJM, 8% more than summer capacity amounts to about 13,300 MW,[7] which is more than five times the 2,452.8 MW of projected average load shed in the worst of the worst-case scenarios discussed above.
  2. It is not clear how PJM reflected, if at all, (1) load reductions in response to what would be very high prices in its worst-case scenarios, or (2) load management under PJM’s direct control.[8]
  3. PJM assumes system load reduction from voltage reduction is 1 to 2%, but elsewhere it says system load reduction capability is 2 to 3%.[9]
  4. PJM assumes no load reduction from public calls for voluntary conservation. This is not reasonable, especially in the context of the hypothesized emergency conditions.
  5. PJM’s assumed forced outage rate includes historical data that are obsolete in the wake of CP incentives/penalties that have increased generation availability.[10]
  6. PJM appears to assume no import assistance from neighboring regions despite a history of such assistance, such as during the polar vortex.[11]

Even if there were a realistic scenario that projects load shed, we would then need to ask what it would cost to avoid an incremental X MWh of lost load relative to the value of lost load of those megawatt-hours. It would be obvious that making consumers pay for more “fuel security” makes no sense.

And it’s more than just money. Devoting time and attention to things that don’t matter takes time and attention away from things that do, like cybersecurity.

At the end of the day, PJM has hypothesized a tiny risk that has a tiny chance of happening and could not possibly justify significant consumer costs.

Columnist Steve Huntoon, principal of Energy Counsel LLP, and a former president of the Energy Bar Association, has been practicing energy law for more than 30 years.

1- https://www.youtube.com/watch?v=EQnaRtNMGMI.

2- https://www.pjm.com/-/media/library/reports-notices/capacity-performance/20180620-capacity-performance-analysis.ashx?la=en (see for example conclusion at pdf page 34).

3- https://rhg.com/research/the-real-electricity-reliability-crisis-doe-nopr/.

4- The math is 83 load-shed hours times average load shed of 2,452.8 MW divided by 140,000 MW of peak load.

5- “In general, the interstate pipelines have experienced very few major line failures over the last several decades. The frequency and severity of disruptions have not created any major detrimental loss of natural gas supply to PJM generation, in part because the majority of events have occurred during the time of year when demand on the natural gas system is low.” https://www.pjm.com/-/media/library/reports-notices/fuel-security/fuel-security-technical-appendix.ashx?la=en (pdf page 12). I am aware of only one “high pipeline disruption” in PJM, the 2016 explosion on a Texas Eastern line in Westmoreland County, Pa.; this event apparently did not affect generation.

6- https://iso-ne.com/static-assets/documents/2018/04/2018_celt_report.xls (“Seasonal Claimed Capability” in Table 1.1 (Summer) and Table 1.2 (Winter). Monthly capability reports are here, https://www.iso-ne.com/isoexpress/web/reports/operations/-/tree/seasonal-claimed-capability.

7- If we assume that summer capacity resources are only equal to the reliability requirement of 166,355 MW, https://www.pjm.com/-/media/markets-ops/rpm/rpm-auction-info/2021-2022/2021-2022-bra-planning-period-parameters.ashx?la=en, then 8% of those resources is 13,308 MW.

8- PJM does, of course, include programmatic DR as a resource but does not include any other load response to what would be very high prices. With regard to direct control load management, there are 2,593 MW of such summer capacity, some but not all of which is air conditioning load control not relevant to the winter https://www.pjm.com/-/media/library/reports-notices/load-forecast/2019-load-report.ashx?la=en (pdf page 65, column for year 2013-2014).

9- https://www.pjm.com/-/media/training/nerc-certifications/gen-exam-materials/gof/20160104-capacity-emergencies.ashx?la=en (slide 46). After that range was developed, American Electric Power added voltage reduction capability in Ohio.

10- “During the cold snap of 2017-18, Capacity Performance resources’ forced outage rates were significantly lower than the same resources’ outage rates during the 2014 polar vortex (5.5% vs. 12.4%).” https://www.pjm.com/-/media/library/reports-notices/capacity-performance/20180620-capacity-performance-analysis.ashx?la=en (pdf page 4).

11- “Data Request for January 2014 Weather Events,” Letter from PJM Counsel James M. Burlew to FERC Representative David J. Burnham, Jan. 10, 2014 (pdf pages 18-19).

June 17, 2019March 20, 2024

An End to the Universal Service Model?

By Rich Heidorn Jr.

PHILADELPHIA — Has weather become so extreme that utilities should end the universal service model and stop serving at-risk locations?

It’s something that should be considered, Margaret Peloso, a partner in Vinson & Elkins’ Environmental & Natural Resources practice, told the Edison Electric Institute 2019 meeting last week.

Peloso cited the National Oceanic and Atmospheric Administration’s National Climatic Data Center, which found that between 1980 and 2018, the U.S. averaged 6.2 extreme weather events per year that resulted in $1 billion or more in damages (inflation adjusted to 2019). In 2014-18, the count of $1 billion events doubled to 12.6 per year, and in 2018 alone, there were 14 such events, including hurricanes, severe winter storms, floods and wildfires.

“We are seeing an increase in these really big, really high-dollar-value events,” Peloso said. “When you start to look at our structures for disaster relief and how we socialize disaster costs, we’re going to run out of money. And it raises the question: Who should pay for it?”

Peloso said the problem is a combination of climate change producing more severe events and more people living in high-hazard areas because of poor land use policies stemming from “misaligned” incentives. Local governments, which control zoning, benefit from an increased tax base and thus tend to be permissive and reluctant to risk litigation by denying landowners the right to build on their properties. And when there are losses from flooding or wildfires, much of the cost is externalized to the state and federal government.

In addition, research has shown that people underestimate risk and underinvest in insurance and risk mitigation, Peloso said.

“If you’re really looking at managing the risks for your company, as the CEO, I think it’s time to reconsider the universal service model and ask: Are there some areas that are just too exposed to natural hazards and risk to really be served?

“There’s actually a small utility in California … that couldn’t get general liability coverage this year because of wildfires,” Peloso said. The utility identified about 600 customers in high-risk areas. “They gave them all generators. And they said, ‘We’re going to shut your power off’” at times. (See related story, Fire Season Starts in Calif. with Power Shutoffs.)

“Let’s try to move away from this paradigm … of putting things exactly back where they [were],” she said. “Maybe that’s not where we really want people to live.”

Combining Efforts

The consequences of the current policies are stark. After a wildfire is extinguished, “we’re left with a landscape that’s going to take, in many cases, several decades to recover,” said Barnie Gyant, deputy regional forester for the U.S. Forest Service. “In some of the cases where we’ve had really large fires … it will be 100 years before we have a forest again.”

Gyant said government agencies need to work more closely with utilities and the owners of forest lands to coordinate preventive measures. In California, he noted, his department manages more than 60% of forested landscape and 20% of the landmass, giving it overlapping responsibilities with state and federal fish and wildlife agencies and utilities.

He cited the 2017 memorandum of understanding the Forest Service signed to improve coordination with Sierra Pacific Industries, which manages nearly 1.9 million acres of timberland in California and Washington. Other industrial landowners have signed the MOU since.

“Most everyone has five- or 10-year plans, but those plans are done in a vacuum. They’re not connected,” Gyant said. “When you look at the amount of money and resources those different entities have, I think we can make a difference with the fires in California. … We’re not saying we’re going to stop fires. But I do think we can be strategic in where we place our treatments to reduce the size of those fires, help protect communities and help protect infrastructure.”

Peloso agreed, saying policymakers should resist “throwing dollars at things like management per mile as opposed to trying to be smart about where the highest risks are.” Spending should be based on “where you get the most meaningful risk reduction instead of doing things [that] we think will generally reduce threats,” she said.

Resistance to Vegetation Maintenance

Former Florida Public Service Commissioner Ronald Brisé, now a government affairs consultant for Gunster, said utilities and regulators often meet resistance from local government over vegetation management efforts.

“Some cities will tell you … I’m going to sue you if you cut my trees,” he said.

Some areas that suffered outages following Hurricanes Irma and Wilms “are the same cities [where] their citizens are reacting because of vegetation management.”

IDACORP CEO Darrel Anderson, who moderated the discussion, complained of having to deal with separate sets of rules for his company’s operations in Idaho and Oregon.

In Idaho, the company can use a soil sterilant to prevent vegetation growth around its poles, a technique he said is proven to reduce the impacts of fire on electric lines. “In Oregon, we can’t do that unless we do a separate environmental study on each pole,” he said.

June 17, 2019

CPUC Concerned About New PG&E Board Members

By Hudson Sangree

The California Public Utilities Commission on Thursday asked for more information on Pacific Gas and Electric’s new corporate directors, with some commissioners expressing doubts about their safety expertise and ability to fully focus on their jobs.

The latest effort — in which the CPUC adopted an administrative law judge’s proposed decision — is part of the commission’s ongoing investigation into the safety culture at PG&E, a company blamed for catastrophic wildfires and a deadly pipeline explosion in 2010. (See CPUC Expands Probe into PG&E Practices After Deadly Fire.)

Jeffrey Bleich, a former special counsel to the White House, was named chair of PG&E’s utility subsidiary Pacific Gas & Electric. | *PG&E*

During the CPUC’s meeting in Sacramento, President Michael Picker said he’d met with Jeffrey Bleich, the new chair of utility PG&E, and intended to meet soon with Nora Mead Brownell, chair of parent company PG&E Corp. Bleich, an attorney, is a former ambassador to Australia, and Brownell is a former FERC commissioner.

“While both of these individuals have very impressive resumes, it’s not immediately clear from their record that they have the appropriate qualifications for the task at hand,” Picker said. “In addition, they may not have enough time in the day, given their other commitments, to dive into the full governance of PG&E.

“The corporate governance of PG&E really demands the whole attention of qualified people and not just the splintered attention of otherwise well-meaning people,” he said.

Former FERC Commissioner Nora Mead Brownell is the recently appointed chair of the PG&E board of directors. | *PG&E*

Brownell serves on at least one other board and co-founded an energy consulting business, according to the utility’s web site. Bleich serves on two other corporate boards and chairs the Fulbright Foreign Scholarship Board, it says.

Neither could immediately be reached for comment.

PG&E said in a statement that its new board members, named in April, “possess the important qualifications — including and especially safety expertise — to lead PG&E going forward.”

The “PG&E Corp. board’s Nominating and Governance Committee explicitly added safety expertise to the variety of experience and skills we require for our directors,” it said. “The directors include industry leaders who have dedicated their careers to safe and reliable utility service — including as federal and state regulators, and as board members and executive officers of other energy companies.”

Picker, backed by three of his fellow commissioners (one was absent), said the CPUC needs to “dig deeper” into the board to “find out who’s making decisions, how qualified they are and whether we have the right leadership at PG&E.”

June 17, 2019

Overheard at EBA Northeast Annual Meeting 2019

WASHINGTON — The Energy Bar Association’s Northeast Chapter held its annual meeting last week in a small conference room within the offices of law firm Baker Botts. Members discussed the state of the offshore wind industry, RTO analyses of fuel security and the ongoing tension between markets and state policies. FERC Commissioner Richard Glick gave a keynote luncheon talk.

Here’s some of what we heard Thursday.

Transmission for Offshore Wind

The Northeast has a combined goal of 21.9 GW in offshore wind procurements, a number only expected to grow as Maine and Delaware both consider their targets, and New Jersey contemplates upping its own.

Transmission planning on land is already challenging enough for RTOs. The nature of offshore wind facilities make planning their interconnections even more so.

John Marczewski, vice president of utilities and consulting for EN Engineering, gave an overview of the physical challenges. Each turbine in a wind farm connects to a collection substation in the ocean. “Substation engineers are not used to building electrical substations that sit on, effectively, what is an oil platform,” he said. “A lot of design challenges [are] involved in that.”

From the collection station, an underwater transmission line runs to a substation on land. The distance from the shore also presents design difficulties. An AC line is typically limited to 600 MW and 35 miles per circuit, so more circuits need to be added to transmit more power. Alternatively, designers could opt to use a DC line, but both the off- and onshore substations would need to be equipped with AC converters.

“It’s very hard to actually get … cables from platforms out in the ocean to these interconnection points,” said Theodore Paradise, senior vice president of transmission strategy for Anbaric. “There isn’t unlimited space across the ocean floor.” He advised using HVDC systems, not only because adding more AC lines requires more trenching and thus harms the ocean environment, but because it’s more expensive.

EBA — Offshore wind goals by state | *Anbaric*

Tackling Fuel Security

Matt White, ISO-NE’s chief economist, reminded the audience of the RTO’s chief concern: During extended periods of extreme cold, natural gas pipelines become severely constrained, and building heating gets priority over fuel for electricity generation, resulting in about half the RTO’s gas generators simply not being able to run.

“If you went to much of this country and told the system operator, ‘Half your gas generators can’t get fuel,’ they would say, ‘The lights are out,’” White said. “Today we’re making this work — for now.”

Like the rest of the U.S., renewable resources are growing in New England. “And if the renewables produced high levels of output all the time when the weather was cold, we’d probably have no problem,” he said. But in the winter, the region is “latitudinally challenged” when it comes to solar, and wind output is highly variable.

White then went over the details of ISO-NE’s proposal, ordered by FERC after it allowed the RTO to enter a cost-of-service agreement with Exelon to keep its 2,274-MW Mystic plant running. The proposal, due Oct. 15, was rejected by the New England Power Pool in March. In May, FERC agreed to hold a public prefiling meeting with the RTO, NEPOOL and the New England States Committee on Electricity. (See related story, NEPOOL MC Debates Energy Security Models.)

EBA — Leaseholds in BOEM wind energy areas | *Anbaric*

Glick: FERC Creating Legal Risks, Uncertainty

FERC commissioners remain entrenched in their positions on emissions, and they have yet to rule on PJM’s capacity market proposal. Each issue is generating legal risks for natural gas infrastructure developers and the RTO, respectively, Glick said.

EBA CEO Lisa Levine opens the meeting. | © *RTO Insider*

“The courts have twice now told us … that when those [emissions] effects are reasonably foreseeable … we have to consider that as well” in an environmental impact statement, Glick said, referring to the D.C. Circuit’s 2017 Sabal Trail decision and a more recent decision earlier this month.

On June 4, a three-judge D.C. Circuit Court of Appeals panel upheld FERC’s approval of a compressor station in Tennessee as part of Tennessee Gas Pipeline’s Broad Run Expansion Project, though not without scolding the commission for failing to ask the company for data on downstream effects of the station.

The plaintiffs — local activists represented by former FERC attorney Carolyn Elefant — argued that the commission violated the National Environmental Policy Act by not considering those effects. But the court said it was forced to reject the complaint on procedural grounds, as the plaintiffs did not argue that FERC’s failure to seek the data violated the law.

While FERC argued that asking for such information “would be an exercise in futility,” the court countered that “We are troubled, as we were in the upstream-effects context, by the commission’s attempt to justify its decision to discount downstream impacts based on its lack of information.”

“What we’re really doing to pipeline developers is we’re creating an enormous amount of legal risk,” Glick said. He noted that the 4th U.S. Circuit Court of Appeals has prevented the construction of the Atlantic Coast Pipeline because the U.S. Forest Service and National Park Service “essentially didn’t cross their t’s and dot their i’s, and I think that’s what we’re doing here.”

“At some point, the courts are going to be clear and say, ‘Nope, FERC, we’re sending that back to you; you have to consider it again.’”

Glick also elaborated on the comments he made on Capitol Hill regarding PJM’s capacity proposal the day before. (See related story, FERC Probed on RTO Governance, Market Issues.)

FERC has found that PJM’s current capacity market rules are unjust and unreasonable. If PJM runs its Base Residual Auction in August “under those same terms and conditions,” Glick said, “my question is — and I don’t know the full answer to this, but I think the courts would say, ‘How could that auction be just and reasonable…?’

“We’ve done a great disservice, not only to PJM itself, but to a lot of the stakeholders who are either participating in the auction or are going to be impacted by the auction, because we’ve created a great level of uncertainty.”

June 17, 2019

Battle over FTR Reform Shaping up in PJM

By Christen Smith

A battle over the future of the financial transmission rights market looms for PJM as stakeholders dig into the causes behind the GreenHat Energy default and consider ways to prevent such an event from ever happening again.

In one corner, the Independent Market Monitor, the Organization of PJM States Inc. (OPSI) and some RTO staff believe reforms should extend beyond credit and risk management policies to the FTR market structure itself, as suggested in the PJM-commissioned review of the conditions that allowed the situation to unfold. (See Report: ‘Naive’ PJM Underestimated GreenHat Risks.)

In the other corner, stakeholders and staff argue the FTR market structure remains sound and is vital to keeping costs low for consumers because it allows market participants to appropriately hedge congestion risk. Their interpretation of the independent probe concludes that failures in PJM’s credit and risk management practices and unresponsive leadership allowed this small, unknown trading company to amass the largest portfolio of FTRs in RTO history in just a few short years — more than doubling the positions held by the second-largest market participant that had been building its folder for at least a decade.

The Energy Trading Institute stands in favor of keeping FTRs around. In a white paper released Wednesday, the policy group urged the PJM Board of Managers to ignore overtures from the Monitor and OPSI to reform the market, insisting the groups are just trying to distract from the real causes of the default.

“What matters for consumers is getting the lowest price possible in the competitive retail markets or standard offer/default service auctions where consumers actually lock in the cost of their electricity,” said Noha Sidhom, ETI executive director. “By eliminating or reducing FTRs, OPSI and the Market Monitor would significantly increase the risk premium needed by retail service providers to serve customers in their specific locations.”

FTR — Size and tenor of GreenHat’s portfolio versus others. | *PJM*

PJM Monitor Joe Bowring said Monday that modifying the existing structure — including increasing auction frequency, reducing the number of paths to auction and eliminating long-term FTRs — would help return the FTR market “to its fundamental purpose.”

“The current path-based FTR market is inconsistent with LMP and the payment of congestion in a network system,” he said. “Congestion is simply the difference between what load pays and generation receives as a result of transmission constraints.”

In particular, Bowring noted the generator-to-generator path to auction could be eliminated because LMP provides appropriate price signals and the right incentives for location and operation of generating units.

“All congestion belongs to load because load is the source of all congestion revenue,” he said. “Generators do not pay congestion. Generators appropriately receive LMP at their location. FTRs were not designed to ensure that generators receive a higher price than their LMP.”

Sidhom counters that only the “granular and diverse” nature of FTR products provide market participants with enough confidence to protect themselves against congestion risk and diversify their portfolios. Eliminating paths to auction will distort prices and raise risk premiums, she said.

“Limiting the availability of such paths for purchase in the FTR market will limit the load-serving entity’s ability to more exactly target and prevent its exposure to that constraint,” she writes in the ETI white paper, noting that the generator-to-generator path has proved invaluable to the growing share of wind and solar resources coming online. “If you eliminate a generator-to-generator path, the wind generator would be forced to face the financial exposure of its FTR against a load node, zone or hub, when wind output is low. This would be a far less effective and riskier hedge for the wind plant.”

Bowring argued current market design forces load to accept whatever prices FTR buyers offer, which leaves them collecting about 80% of the congestion revenue owed to them — a share that drops even further for long-term FTRs. He recommends that PJM first assign congestion revenue to load and then allow LSEs to sell these rights as FTRs at an agreed-upon price.

“PJM can decide how to structure that auction,” he said. “As with the current FTR auctions, any participant could buy such FTRs including generators and speculators.”

Deeper Review

In a May 24 letter to the board, OPSI President Michael Richard supported a deeper review of FTR market structure, noting that current rules “lack adequate financial protection for load.” The organization declined to comment on the contents of the ETI white paper.

Chairman Ake Almgren said in a June 7 response letter that the PJM board shares OPSI’s view of the importance of reviewing FTR products, but he noted it’s beyond the purview of the recently formed Financial Risk Mitigation Senior Task Force. (See PJM Stakeholders OK Risk Management Task Force.) He said the board instead expanded the charter of the Audit Committee to include direct supervision of risk management and that PJM continues to “actively recruit” for a senior level executive to lead the process.

“The task force is charged with assessing credit risk mitigation and management and not general market design,” he said. “However, we expect the task force will consider whether credit risk can be appropriately mitigated by steps to simplify existing FTR products and increase the frequency of FTR auctions.”

The task force began work last month to consider changes to credit and risk management requirements, market rules, membership qualifications and the stakeholder process in response to an independent probe of the default that uncovered structural flaws. PJM wants stakeholders to form solutions and make recommendations for Tariff and Operating Agreement revisions to the Markets and Reliability Committee and board by the end of year.

“We are committed to examining whether our current FTR product offerings present risk management challenges that outweigh the overall benefits,” Almgren concluded. “However, at the same time, we cannot delay taking actions that might offer near-term opportunity to mitigate immediate risk exposure. Before embarking on broader market design changes, PJM will retain experts, as we have in the past, and our Market Monitor will be an integral part of that process.”

PJM spokesperson Jeff Shields said Monday that RTO management agrees with several of ETI’s points and disagrees with others, though the board will respond “in the near future” and consider stakeholder feedback when deciding what reforms to recommend to FERC.

“As is typically the case with letters to the board, the issues in play are contentious, with strong feelings on all sides of the debate,” Shields said. “PJM and its membership are underway with a comprehensive assessment of better ways to mitigate and manage FTR credit risk.”

June 17, 2019

Overheard at EEI 2019

PHILADELPHIA — In the last two years, oil giant Royal Dutch Shell has purchased a U.K. electric utility and two electric vehicle charging companies. Shell CEO Ben van Beurden and his wife both drive EVs themselves.

“On the other hand, in this country, we have 43,000 zip codes,” oil expert Daniel Yergin said. “One hundred eighty-nine of them — which represent two-tenths of 1% — reflect 25% of all EV sales in the country.”

Yergin, founder of IHS Cambridge Energy Research Associates, offered that statistic to set the stage for a discussion on electrification and decarbonization at the Edison Electric Institute’s annual conference last week. The three U.S. electric utility CEOs who joined him agreed: While the industry has come a long way in reducing its carbon emissions, the road to carbon-free power won’t be a freeway.

Exelon CEO Chris Crane said there are regions, such as Commonwealth Edison’s territory in Northern Illinois, that are 100% carbon free now.

“For Illinois to declare they want to be carbon free by 2030 to 2032, that’s not a stretch. … And it’s because of existing nuclear and the renewables that have been installed without the storage, without the advanced technology. But in other jurisdictions that would be much more difficult.”

Crane said storage technology needs to advance beyond lithium-ion batteries before utilities can take full advantage of intermittent resources. “It’s a ways away from [the] central station being [in] full demise,” he said.

Duke Energy CEO Lynn Good said utilities must remain “the voice of reliability and affordability.”

“We need to recognize that we don’t have all the tools today to operate at scale to achieve a 100% renewable solution in four-season climates and heavy urban areas and areas that don’t have a mix of renewable resources that certain geographies have,” she said.

Xcel Energy CEO Ben Fowke said his company can help customers and communities reach 100% renewables with customized programs but that it will need more advances to reach Xcel’s company-wide target of 100% carbon-free by 2050 and 80% by 2030.

Eventually, the grid will be saturated with renewables and short-duration batteries, he said.

“And at that point, we’re going to [need] those carbon-free dispatchable resources. … Nuclear is one today. So, we’re all about preserving our nuclear fleet. And I think the technologies that will get us that last 20% on our goal … might come from hydrogen. It might come from the next generation of nuclear. It might come from carbon capture. It might come from something we don’t even know — long-term storage for example.”

EEI — From left: moderator Daniel Yergin; Ben Fowke, Xcel Energy; Lynn Good, Duke Energy; and Chris Crane, Exelon | © *RTO Insider*

Chef Says Adaptation is Recipe for Success

Chef José Andrés, the keynote speaker for the June 10 session, talked about how he and others provided more than 3.5 million meals in Puerto Rico following Hurricane Maria in 2017.

Andrés recalled how the effort grew “from one kitchen to 26 kitchens; from 20 friends [the] first day to 25,000 volunteers. We went from 1,000 meals a day the first day to more than 150,000 meals a day every day. We were delivering food in 935 places each day. … At the end, what seemed impossible became possible. What we did was adapt to every circumstance.”

Andrés said his group was initially rebuffed when it asked the Army to deploy its helicopters to deliver the meals to remote locations. “The bosses here would not make it happen, but when I met with the guy who was running the helicopter he said, ‘We’ll find a way to deliver that food.’ We needed to cross rivers without bridges. If I ask here, I never get it. If I ask the officer in charge of a unit of Humvees, boom! Those men and women would be there helping us cross the rivers. [When] we needed a boat to get to Vieques, if I ask over here, it would never happen. In the moment I met the Navy captain, all of the sudden, I had the boat to go every day to Vieques,” Andrés said.

“You see the men and women are extraordinary people, the military and [the Federal Emergency Management Agency]. But we need to liberate them from rules and regulations that don’t allow them to be successful. Because we are outside the system, we don’t follow rules. We don’t follow the plan. We continuously adapt.”

Andrés also recalled for the EEI crowd his first visit to New York City, when he was a member of the Spanish Navy and his ship docked at 30th Street on the Hudson River. “Last month, I opened a big restaurant … 100 meters away from the dock I arrived on at 30th Street. Do I believe in the American dream? Yes, I do believe in the American dream.”

Natural Gas: Bridge or Destination?

It wouldn’t be an energy conference without a debate about natural gas’s future. EEI’s panel (“Natural Gas: A Bridge or a Destination?”) featured an environmentalist, a representative of gas turbine manufacturer GE Power and two utility representatives.

Mark Brownstein, the Environmental Defense Fund’s senior vice president for energy, said gas’s future in a zero-carbon electric future will depend on the competitiveness of storage in supplementing intermittent sources and the gas industry’s ability to eliminate CO₂ and methane emissions.

If the goal is to be net carbon zero by 2050, gas’s future “has a lot to do with the level of investment in carbon capture and storage, either at the power plant or it may be in the context of producing hydrogen that is then run through combustion turbines,” Brownstein said. “But either way, you have to have some way of capturing that CO₂. The future is really up to you guys.”

DTE Energy CEO Jerry Norcia said his company is doing its part to prevent methane emissions by replacing leaky cast iron pipe with plastic.

Diane Leopold, CEO of Dominion Energy’s Gas Infrastructure Group, said the gas industry also needs to improve its physical and cybersecurity to match mandatory reliability standards for the electric industry. “So, we’ve been investing heavily, thinking of ourselves as the critical infrastructure to be able to be that backup … to achieve these goals of higher electrification and increased penetration of renewables.”

Brian Gutknecht, chief marketing officer for GE Power, said gas will continue to prosper as the cheapest dispatchable thermal energy technology, noting its energy density allows it to produce energy on 50 to 100 times less real estate than renewables.

Carbon capture “for us is the next tier,” he said, adding that GE’s gas turbines can burn 100% hydrogen. “Our customers are buying an asset that early on can accelerate decarbonization [by] burning natural gas, and over time, as the technologies advance, the role of gas is going to change, and our technology is able to change with it.”

Brownstein said the 2015 leak at the Aliso Canyon storage facility, which took four months to plug, is an “object lesson.”

“The methane emissions that came out of that facility … basically [wiped] out all of California’s climate progress for the course of that year, from all measures,” he said. “California learned from that experience … that battery technology was ready, willing and able to deploy to support the electric grid. So, the role that gas was playing in providing peak support in the summertime was taken up by batteries.

“The lesson is when the industry fails to take care of their equipment and emissions result, there are other competitors in the marketplace now … able to take up that slack — so much so that California is really playing with the idea of closing that facility and other facilities like it entirely. The options that we have to deliver reliability and resilience … are growing. It’s not the case that natural gas has a corner on that market.”

Gutknecht acknowledged that gas’s role will change. “It will be doing more firming when renewables aren’t available,” he said. “Batteries are going to play a very important role for shorter duration … storage. So, gas is left to play the longer duration role that may be required at times.”

Addressing Climate Change: A View from the States

At a session on the states’ view of climate change, former Ohio regulator Asim Haque, reflected on how his perspective has changed since joining PJM 12 weeks ago as executive director of strategic policy and external affairs.

Haque said the RTO has gotten whipsawed by stakeholders’ decision in April to explore how to accommodate carbon pricing in its markets. (See “Carbon Pricing Talks Move Forward,” PJM MRC/MC Briefs: April 25, 2019.)

“On the one hand, you’ll get folks within the environmental community who will say, ‘It’s about time.’ On the other hand, you’ll get perspectives — which I’ve already gotten — from states who will say, ‘How dare you engage in policymaking?’ This is the Catch-22 that the organization finds itself in.”

Haque knew what he was getting himself into when he took the job, however.

“From an outsider’s perspective, PJM is a very convenient punching bag,” he said. “Politically it’s so intelligent to utilize PJM in that fashion.”

The 13 states and D.C. in PJM’s territory have disparate views on climate policy, making it difficult to achieve any kind of consensus, Haque said.

The D.C. Public Service Commission is on one end of the spectrum, required to consider climate change in all decisions. “While states can move the ball … it’s a no brainer that federal action is necessary,” D.C. PSC Chair Willie Phillips said.

EEI — From left: PSEG CEO Ralph Izzo; D.C. PSC Chair Willie Phillips; Asim Haque, PJM; and Sam Robinson, deputy chief of staff to Pennsylvania Gov. Tom Wolf | © *RTO Insider*

With New Jersey planning to rejoin the Regional Greenhouse Gas Initiative and Virginia’s governor considering it, Pennsylvania is at risk of becoming the “donut hole” in RGGI, acknowledged Sam Robinson, deputy chief of staff for Gov. Tom Wolf (D). Republicans, who control Pennsylvania’s House and Senate, contend such a move would require legislative approval.

Although the state hasn’t taken steps to join RGGI, it “is the type of program we would consider,” Robinson said. “It’s something we’re looking at.”

Panel moderator Ralph Izzo, CEO of Public Service Enterprise Group, said the need for grid resilience will only increase in a world of electrification of transportation.

“If you think people are grumpy today when they can’t charge their cell phone after a two-day outage, think of what the future will be like if they cannot drive their car after a two-day outage.”

— Rich Heidorn Jr.

June 17, 2019

NYPSC Dings Utilities for 2018 Reliability, Safety

By Michael Kuser

Four of New York’s major utilities will collectively see their revenues reduced by more than $7 million for failing to meet certain reliability and customer service requirements last year, state regulators revealed last week.

The New York Public Service Commission on Thursday reviewed reports on utility performance in electric reliability, gas and electric safety and customer service in 2018 (Cases 19-E-0169, 19-E-0246 and 19-M-0307). “While most utilities are doing a good job providing safe and reliable service, four utilities have fallen short of our expectations in certain areas, and we will continue to act aggressively to ensure utilities improve performance,” PSC Chair John B. Rhodes said. “Additionally, as a result of this analysis, it is clear that utilities must be ready to address more frequent and powerful storms.”

NYPSC reviewing the reliability and safety of NY's utilities — The PSC held its regular monthly session in New York City on June 13.

The utilities being dinged for their performance include New York State Electric & Gas, Central Hudson Gas & Electric, Orange and Rockland Utilities, and National Grid’s Long Island gas operation.

Major storms last year accounted for more than 80% of the total customer-hours of electric service interruptions and 36% of the overall number of customers affected. New York experienced 36 separate major storm events in 2018, with the five largest occurring between March 2 and May 20, said Mary Ferrer, of the Department of Public Service’s Office of Electric, Gas and Water.

Last year ranks third in customer-hours of interruption in the last 20 years, behind Hurricane Irene and Tropical Storm Lee in 2011 and Hurricane Sandy in 2012.

Last year saw more customer-hours of interruption when including major storms than calendar year 2017; however, excluding major storms, the statewide interruption frequency and duration performance for 2018 declined compared to the previous year and the statewide five-year average, primarily because of fewer outages from equipment failures and tree contacts, Ferrer said.

‘Right Kind of Oversight’

The commission relies on two primary metrics to measure electric performance: the System Average Interruption Frequency Index (SAIFI), and the Customer Average Interruption Duration Index (CAIDI). By compiling the interruption data provided by the individual utilities, the average frequency and duration of interruptions can be reviewed to assess the overall reliability of electric service statewide.

reviewing the reliability and safety of NY's utilities — Benjamin Dunton

NYSEG had its worst performance last year since 2007 with an average duration of 2.17 hours, above the target of 2.08 hours. Central Hudson’s frequency performance of 1.50 did not meet the target of 1.38.

The duration and frequency target failures mean NYSEG shareholders will see a negative revenue adjustment of $3.5 million and Central Hudson shareholders will see a negative revenue adjustment of $2 million, the commission said.

All the utilities complied with safety standards in 2018. Manual stray voltage testing performed on approximately 1 million utility facilities statewide identified 396 stray voltage situations, more than in 2017, though incidences of the more severe category over 4.5 V declined. Most such incidents on utility-owned facilities stem from street lighting, DPS staff member Benjamin Dunton said.

In response to a question by Commissioner Diane Burman about why the more serious stray voltage readings were down from the previous year, Dunton said, “More awareness on the part of people doing construction work and digging.”

DPS staff member Sonny Moze delivered the report on customer service quality, which found that most utilities met or exceeded the standards for customer service for 2018, with the exception of O&R, which failed to meet its target for calls answered by a representative within 30 seconds.

“This is the right kind of oversight,” Rhodes said of the customer service report. “I appreciate that O&R is responding to the evidence and will appreciate it even more when their performance improves to the standard that we expect.”

O&R’s shareholders will be required to pay $450,000 for the performance shortcoming.

“I do think it’s important that we have more meat on the bone when it comes to the 30 seconds for calls answered,” Burman said. “The utilities point out why it’s taking longer to answer the call, so we might need to work on that.” O&R, for example, cited higher-than-normal call volumes.

Barring ESCOs?

The PSC also announced steps that could prohibit five energy service companies (ESCOs) from further marketing and enrolling new customers in New York. Only one of the five companies, Atlantic Power & Gas, currently has any customers.

“I think it’s important to identify that we are looking at potential violations of the Uniform Business Practices [adopted for ESCOs], and really relating to filings that haven’t come, and there are no customers there,” Burman said. “Two of them have voluntarily discontinued practicing in the state because they failed to report to us. The other two are orders to show cause, but again there are no customers involved.”

The commission has the authority to regulate ESCOs’ access to utility distribution systems, including the power to require them to meet price caps set at utility prices.

The PSC directed that Atlantic explain why the commission should not ban it from operating in New York or take other remedial action (Case 16-M-0618).

In March 2017, the commission ordered Atlantic to cease marketing to and enrolling customers. On March 4, DPS staff identified apparent violations of the order.

Atlantic does business in the service territories of Central Hudson, Consolidated Edison, and National Grid’s KeySpan Gas East and Brooklyn Union Gas. It has 30 days to counter the DPS findings.

Further, the commission also directed that Clear Choice Energy, Amerigreen Energy, Bluesource Energy and Got Gas? — none of which has customers — explain why they should not be barred from operating in New York for failing to file their annual compliance filings.

Sayre Farewell

Rhodes read a resolution of appreciation for Commissioner Gregg C. Sayre, likely attending his last session as commissioner, as the New York State Senate is soon to vote on Gov. Andrew M. Cuomo’s nomination of Tracey Edwards, a Long Island Democrat, to a seat on the PSC. State law sets a maximum of five members of the commission, of which only three can be members of the same political party.

The PSC currently has four members: three Democrats and one Republican.

June 17, 2019

NEPOOL MC Debates Energy Security Models

By Michael Kuser and Robert Mullin

ISO-NE floated a portion of its long-term market proposal to address fuel supply constraints, and five stakeholders presented their own concepts at the June 10-12 meeting of New England Power Pool’s Markets Committee.

The RTO faces an October deadline to file a market design with FERC that permanently addresses the regional fuel supply issue — specifically winter scenarios when natural gas supplies are limited.

In March, the RTO filed an interim proposal with the commission to address winter energy security for the commitment periods covered by Forward Capacity Auctions 14 (2023/24) and 15 (2024/25). That plan would “provide incremental compensation to resources that maintain inventoried energy during cold periods when winter energy security is most stressed” (ER1 9-1428). (See ISO-NE Filing, Whitepaper Address Energy Security.)

The interim proposal consists of five core components, including a two-settlement structure, a forward rate, a spot rate, trigger conditions (such as extended cold snaps) and a maximum duration for compensation. But some stakeholders have found the plan to be unduly complex, with the Massachusetts attorney general contending it represents the most dramatic change to the energy and ancillary services markets since their inception.

Keeping it ‘In Market’

ISO-NE’s proposed long-term solution looks to be no less complex — and transformative — than its short-term one. Senior Market Designer Andrew Gillespie’s presentation last week focused on just a portion of the plan — a proposal to create day-ahead ancillary services products intended to ensure that in-market processes begin to cover more of the RTO’s next-day operating requirements.

“Meeting these requirements via ‘in-market’ awards improves resources’ incentives to arrange energy supplies facing uncertainty,” the presentation said.

ISO-NE’s proposal calls for the creation of an hourly energy call option: option sellers would offer resources in hope of clearing in the day-ahead option market. As the buyer of the option, the RTO would specify an option price for each hourly interval before submission of option offers, which would occur in concert with submission of hourly energy offers. A resource could submit offers for both options and energy for the same hours, subject to limitations based on its physical parameters.

A resource with a cleared day-ahead option would then have an option position open for a given interval, which would be “closed out” at the real-time LMP for that interval.

“If the real-time LMP is greater than the strike price, the unit will be debited an amount equal to the product of the option quantity and the difference between the real-time LMP and the strike price,” the presentation explained.

The resource would also be credited for real-time energy and reserves supplied at applicable real-time prices.

NEPOOL — Day-ahead headroom is the difference between the sum of day-ahead schedule amounts and the sum of real-time economic maximum values for the winter on-peak hours. | *ISO-NE*

ISO-NE expects that the total volume of call options it procures will meet day-ahead ancillary services requirements.

“These amounts would be based, at a minimum, on the procedures currently applied by the ISO in developing a reliable next-day operating plan,” ISO-NE said.

From a supplier’s perspective, Gillespie’s presentation points out, the option is on real-time energy — not a specific real-time ancillary service; regardless of why the option was awarded, it will still be settled against the real-time LMP.

The RTO commissioned Analysis Group to provide some context on how the proposed changes might affect energy market outcomes. Company principal Todd Schatzki on Wednesday said its study concluded that the proposed improvements could change the way market participants make resource decisions and change economic offers in ways that improve energy security.

Gillespie also noted that the RTO is reviewing a stakeholder suggestion to develop its proposed Multi-Day Ahead Market (M-DAM) separately, after the rest of the energy security improvements are filed with FERC in October.

Massachusetts AG: Simpler, More Physical

In a proposal prepared by London Economics, the Massachusetts attorney general’s office recommended a simple auction format of sealed bids with a uniform clearing price.

Marie Fagan of London Economics described the Forward Stored Energy Reserve (FSER) proposal as a limited amount of insurance for a limited challenge; she said details on the timing of the auction and other matters would be discussed at the July 8-10 MC meeting.

The pros of a uniform clearing price? Each bidder that clears the auction is paid the same price as the highest-cost clearing bid. Bidders can also submit low bids at short-run marginal cost (SRMC) for low-cost (infra-marginal) plants, ensuring they will be chosen.

But the proposal acknowledged one potential negative outcome of a uniform clearing price — that a bidder could engage in portfolio bidding, raising the bid price over SRMC for plants it expects to be marginal.

London questioned whether ISO-NE’s proposal will be effective from a reliability or cost perspective. It said the FSER is a simple and smaller-scale alternative to the RTO’s complex scheme, helping preserve the market signal when supplies are tight.

NextEra: Reserve Products

NextEra Energy Resources propose d the creation of replacement energy reserve (RER) and generation contingency reserve (GCR) products to be purchased by ISO-NE in the day-ahead market.

NextEra’s Michelle Gardner emphasized that both RER and GCR would be physical products, not financial call options, and as such could increase real-time energy prices when fuel reserves are low.

“Resources that sell the call options would have incentives for next-day fuel arrangements,” NextEra said of ISO-NE’s proposal. “However, the extra incentives are weak at best. They depend on assumptions about lumpy offers and risk aversion. One simply cannot expect a strong response absent a fundamental change to real-time demand.”

If done incorrectly, a seasonal forward market is likely to depress energy market prices and provide the wrong incentives, NextEra said. A physical RER, coupled with the right forward incentives, is key, it said.

Calpine: More Precise; More Cautious

Calpine — which has long suggested that the RTO acted in haste in not allowing the market time to work through its energy security issues — presented an energy security concept dubbed Forward Enhanced Reserves Market, which would procure fuel-secure capacity for the winter months three years prior to the obligation year.

By qualifying resources based on their ability to contract for stored fuel or readily-used stored energy, Calpine proposes that suppliers bid at auction for a total minimum or maximum amount of megawatt-hours they will commit to offer off of stored fuel during an Operating Procedure 21, which is activated when the RTO declares an energy emergency event.

Rebecca Hunter, Calpine senior analyst for government and regulatory affairs, said the benefits of its market design include: fuel security through a diverse pool of resources; timely transition of the evolving resource mix; investment in the existing fuel infrastructure; and market design changes in critical winter months only.

Energy Market Advisors: Use Today or Save for Later?

Brian Forshaw presented a concept by Energy Market Advisors, which has concluded that ISO-NE’s market suffers from:

Misaligned incentives: Resources lack incentive to procure and maintain energy supplies that may be needed in the future.
Operational uncertainty: The system may not have sufficient energy available to withstand extended supply losses during winter.
Inefficient schedules: Energy supplies can be depleted prematurely even when stored energy may be more valuable in the future.

Forshaw’s presentation posed the hypothetical question of whether the RTO should “use stored energy today or save it for later when it may be more valuable?”

“How we answer this question has significant (and differing) impacts for resource owners, system operators and electric consumers,” the company said, concluding ISO-NE should primarily focus on addressing those problems as quickly and efficiently as possible. Forshaw cautioned the RTO against implementing M-DAM and seasonal forward procurement at the same time as day-ahead enhancements, contending that would significantly complicate stakeholders’ development, and FERC’s evaluation of such significant changes.

FirstLight: Filling Buckets

Tom Kaslow of FirstLight, owner of the largest pumped hydro facility in the region, presented his firm’s concept for defining energy security, which asks the RTO to “connect the dots” between fuel security and resource adequacy by ensuring that the latter is backed by sufficient fuel storage. Kaslow’s presentation posed the question in terms of generator fuel tanks, which he termed “buckets”: How many buckets need to be filled, he asked, against how many can be filled?

“If the aggregate gas-only generator winter capability exceeds the region’s capability to access gas to support simultaneous generation at such resources, their actual reliability support to meet winter peak load is less than their aggregate megawatts of capability,” the presentation said.

FirstLight recommends ISO-NE “establish the highest level of aggregate winter gas-only capability that can be simultaneously fueled at winter peak demand” and give capacity credit to gas-only resources that have firm transportation rights or contracted priority to take LNG during winter.

“Limit qualified gas-only winter capacity on the rest of the gas-only fleet to the level of such generation that can simultaneously operate,” FirstLight urges.

By assuring that each procured megawatt can be fueled, FirstLight says, ISO-NE can avoid sending inaccurate market signals at times when winter capacity is actually not in surplus. At the same time, it will provide efficient longer-term signals for resources to install dual-fuel capability, contract for pipeline transportation or obtain priority access to LNG, it said.

June 17, 2019

Fire Season Starts in Calif. with Power Shutoffs

By Hudson Sangree

California’s annual wildfire season kicked off last week with high winds, a heat wave and precautionary power shutoffs by Pacific Gas and Electric to thousands of customers.

A wind-driven blaze called the Sand Fire burned 2,500 acres of hilly terrain 60 miles west of Sacramento, and another fire scorched 1,800 acres of dry grasslands in rural Central California. Neither fire caused serious injuries or property damage, but they underscored the threat of wildfires as vegetation begins to dry out after an especially wet winter.

In response to the hot, windy conditions, PG&E turned off power for a day or two for about 1,700 customers in Napa, Solano and Yolo counties near the Sand Fire and for nearly 21,000 in the Sierra Nevada foothills of Yuba and Butte counties. Last year’s Camp Fire, the deadliest and most destructive in state history, ravaged a large part of Butte and leveled the town of Paradise.

Southern California Edison and San Diego Gas & Electric have shut down power before when Santa Ana winds blew. (See Fire Season Becomes Blackout Time in California.)

PG&E first deployed its controversial Public Safety Power Shutoff program last October, nearly a month before the Camp Fire started Nov. 8 — though it did not use the measure in Butte just before that fire ignited.

Power shutoffs are now part of the utilities’ annual wildfire mitigation plans approved by the California Public Utilities Commission. (See California Regulators OK Utility Wildfire Plans.)

A Portland, Ore.-based utility announced Thursday it was adopting a similar measure, suggesting that intentional shutoffs may spread beyond California. The Pacific Northwest has seen its share of devastating wildfires in recent years.

“This measure would only be taken as a last resort to help ensure customer and community safety,” Pacific Power said in a statement. The utility, a subsidiary of PacifiCorp, serves about 764,000 customers in Oregon, Washington and an area of Northern California near the Oregon border.

The National Interagency Fire Center (NIFC) in Boise, Idaho, predicts an active wildfire season in California, the Great Basin and the Pacific Northwest this year because of a “robust grass crop” from winter rains.

“As we go forward into June, those grasses that we see across the landscape are going to dry and cure out … and we’ll see an increase in fire activity especially across California,” said Bryan Henry, assistant program manager of predictive services at the NIFC.

Temperatures soared above 100 degrees Fahrenheit in inland areas during last week’s heat wave. CAISO issued its first “flex alert” of 2019 by calling for residents to voluntarily conserve electricity during peak demand in the late afternoon and evening, when air conditioning use spikes and solar arrays power down.

“Because of widespread heat, the ISO anticipates energy demand reaching a peak of 42,800 MW this evening,” CAISO said in a June 11 news release. “Also, two units with a total generation of 1,260 MW are offline due to mechanical failures. The Flex Alert is being called in response to the high electricity demand and the reduced generation.”

California, which last year mandated greater dependence on renewable energy sources going forward, offset the spike in demand largely with natural gas peaker plants, according to CAISO.

June 17, 2019

PJM PC/TEAC Briefs: June 13, 2019

VALLEY FORGE, Pa. — PJM Planning Committee Chairman Ken Seiler said the new executive director of systems operations, Dave Souder, will replace him as committee chair in July.

Souder currently heads the Operating Committee. Seiler is becoming PJM’s vice president of planning. (See related story, “New Chair Come July,” PJM Operating Committee Briefs: June 11, 2019.)

Seiler’s promotion came during a leadership shake-up with the announcement of CEO Andy Ott’s retirement, effective June 30. (See PJM CEO Andy Ott to Retire.)

PJM’s Planning Committee and Transmission Expansion Advisory Committee met June 13. | © *RTO Insider*

RTEP Poll

Aaron Berner, manager of transmission planning, said after more than six meetings with stakeholders, staff believe they are “close” on tweaks to Manual 14B that address how and when supplemental projects are removed from the Regional Transmission Expansion Plan.

Staff will email two questions to PC members regarding whether they believe the posted manual changes “are on the right track” and what further revisions still need to be made. Results will be presented at the Markets and Reliability Committee meeting June 27. (See “RTEP Removal Language on Track for June MRC Vote,” PJM PC/TEAC Briefs: May 16, 2019.)

The decision was made after stakeholders expressed confusion over how the results of the nonbinding poll would be interpreted. Some felt uncomfortable signaling approval without complete consensus on the language. A few transmission owners remain diametrically opposed to the entire effort and consider existing manual language sufficient as is, possibly skewing PJM’s perception of how willing stakeholders are to adopt changes. (See PJM Rebuffs Stakeholders on Supplemental Projects.)

PJM Developing Hybrid Fee Structure

Stakeholders will soon see PJM’s proposal for a hybrid-fee structure for transmission project cost –containment analyses, Manager of Infrastructure Coordination Mark Sims said.

Currently, the RTO charges nothing for cost-containment reviews of projects $20 million or less. Projects up to $100 million cost $5,000 to review, and larger projects incur a $30,000 fee. Sims said the new formula may include a flat fee, plus itemized study costs. Projects considered the most competitive will accumulate more itemized costs, Sims said, while those considered less viable could pay nothing additional beyond the flat fee.

“The way we are headed, we think, is to keep some flat fee structure plus detailed studied costs,” he said. “It will be somewhere between that zero and $30,000.”

Sims told the PC last month that PJM’s old tiered approach, approved in 2014, doesn’t account for the increased cost of the new comparison framework that involves an independent consultant’s review and legal and financial analyses. (See “New Fee Structure for Cost Containment Needed,” PJM PC/TEAC Briefs: May 16, 2019.)

PJM’s collected project proposal fees versus actual analysis expenses | *PJM*

Generation Interconnection Rules Endorsed

The PC endorsed revisions to Manual 14G to update PJM’s generation interconnection process and clarify the site control requirements. The changes expand rules for demand response in section 1.7 and refers on-site generators used to reduce load that participate as DR to Manuals 11 and 18 for further guidelines. The portion of such generators that inject power past the point of interconnection follow the interconnection process outlined in Manual 14G.

PJM also proposes a minimum site control term of three years — two years for projects of 20 MW or less — commencing on the first day of the new services queue in which the customer submits its request. Extensions must have been exercised by the developer when site control evidence is given to PJM if the initial term is less than the required minimum.

Despite some misgivings about site control extensions expressed during the May PC, stakeholders endorsed the revisions with only one abstention and zero objections. (See “Generation Interconnection Requests Update,” PJM PC/TEAC Briefs: May 16, 2019.)

Market Efficiency Process Enhancement Task Force Charter

The PC endorsed the updated charter for phase 3 of the Market Efficiency Process Enhancement Task Force.

Both the PC and the Markets and Reliability Committee approved phase 3 of the task force last month. Under its new charge, the group will explore possible alternatives to regional targeted market efficiency projects and consider changing the 1.25 benefit-cost threshold to measure energy benefits separately from capacity benefits, as well as other concerns raised with benefit-cost calculations. (See “Market Efficiency Process Enhancement Task Force Gets Phase 3,” PJM PC/TEAC Briefs: April 11, 2019.) The group will make recommendations to the PC by Dec. 12.

Reserve Requirement Study Assumptions

PJM’s assumptions for its reserve requirement study earned unanimous support at the PC.

The capacity benefit margin — the amount of transmission import capability reserved to capture the reliability benefit of emergency sales — modeled in the study will be 3,500 MW. PJM will also use a load forecast error factor of 1% and base load models on assessment work performed by staff and reviewed by the Resource Adequacy Analysis Subcommittee.

Staff will use the PRISM model to develop a cumulative capacity outage probability table for each week of the year except the winter peak. During the winter peak, staff will create a table based on RTO-aggregate outage data collected between 2007/08 and 2018/19 to better account for the risk caused by the large volume of concurrent outages observed during the winter peak week.

The results of this study will be used to determine the forecast pool requirement for the 2020/21, 2021/22, 2022/23 and 2023/24 delivery years. A final report will be presented to the PC in September.

Dayton, Dominion, AEP Solutions

Dayton Power & Light, Dominion Energy and American Electric Power presented proposed supplemental projects during the Transmission Expansion Advisory Committee.

Dayton said AEP will re-energize a dead section of the Stuart-Marquis 345-kV line to bypass the now-defunct Killen substation near Wrightsville, Ohio. The $200,000 project will consist of Dayton installing guy stub poles for tension on the open section of the 345-kV loop.

PJM — Dayton Power & Light and American Electric Power presented a solution to transfer power from the retired Killen substation near Wrightsville, Ohio. | *AEP*

A cheaper solution, Dayton said, would be to de-energize the Killen substation, update relay settings on the Stuart end of the line, install new tie-line meters and work with AEP to complete end-to-end relay testing for a cost of $100,000.

AEP estimates its share of the work — re-energizing the line, upgrading relay at the Don Marquis station and retiring intercompany metering — will cost approximately $1 million.

Dominion proposes installing a 3,000-amp, 50-kAIC circuit breaker to feed a requested new transformer at Chickahominy substation in Charles City County, Va., for an estimated cost of $750,000.

– Christen Smith