Page 1210 – RTO Insider

August 11, 2019

NERC Weighing Concerns on Reorg.

By John Funk and Rich Heidorn Jr.

NERC’s plan to streamline its top technical committees appears to face limited opposition, although officials indicated Thursday they are considering proposals to increase sector representation and lengthen the transition.

The new structure, to be discussed in detail at NERC’s quarterly meeting in Québec beginning Tuesday, would merge the Planning, Operating and Critical Infrastructure Protection committees into a new Reliability and Security Council (RSC). While the three technical committees have almost 120 voting members, the proposal would limit the RSC to 33.

Only two stakeholders made comments during a webinar Thursday on the proposal, both questioning why NERC hasn’t quantified the proposal’s supposed benefits. But NERC also has received written comments from a dozen stakeholder groups, who were nearly unanimous in calling for a longer transition and an increase in the number of sector representatives in the new organization. Some also questioned whether security issues should be combined with operations and planning.

The collapse of the existing committee structures aims to save time and money and reduce the “silos” and inefficiencies that some NERC members believe the three existing committees have created over time.

Exelon’s Jennifer Sterling, vice chair of the Member Representatives Committee (MRC) and co-chair of the Stakeholder Engagement Team (SET) that made the proposal, led the webinar.

“The idea is that we pivot quickly and focus resources rapidly,” she explained in her opening remarks. “You are all aware that our world and our industry are changing quickly and that the pace only continues to accelerate. We need to be agile. We need to be readily deployed to address these emerging issues.”

Existing subcommittees and task forces would remain intact for the time being and report to the RSC. Subcommittees that do not have recurring tasks would be eliminated or combined with others. “The whole idea is that every subcommittee should understand what their task is,” Sterling said.

Reassurances

Sterling acknowledged some stakeholders have expressed fears that the overhaul could unintentionally eliminate networking, workshops, lessons-learned sessions and similar interactions that have developed over the years.

“That was never our intention,” she said. “We would expect that the [RSC] would continue those activities going forward.”

Sterling also addressed concerns that reducing the number of committee members would diminish transparency and stakeholder involvement. “We are committed to making sure the meetings are held in spaces that are open and that provide enough space for everyone who wishes to attend,” she said.

Potential Changes

Sterling also indicated NERC is considering potential changes to the plan based on stakeholder feedback.

The SET proposed a “hybrid” of the regional representation used by the CIPC, the sector-based membership of the PC and OC, and the at-large membership of the MRC and Reliability Issues Steering Committee (RISC).

The RSC would include one voting member from each sector (except for the regional entities), 20 at-large members, a chair and a vice chair. Members would be selected by a nominating committee of NERC officers and approved by the Board of Trustees, with selections based on interconnection diversity, subject matter expertise, and a mix of small and large entities.

“Let me emphasize the word ‘proposed’ here,” Sterling said in prefacing her description of the proposed RSC makeup.

“We have gotten a number of comments that perhaps people would like to see more sector representatives. Right now, we have one per sector, but people have asked for two. And also, there have been a number of comments that they would like to see the sectors elect their own representatives. … These will all be discussed at the upcoming [SET] meeting, and I’m sure it will be discussed next week at the MRC.”

Sterling said her team also has heard stakeholder concerns that the proposed timeline — which calls for nominating RSC members in the fourth quarter and completing the transition in the first quarter of 2020 — may be too aggressive.

Stakeholders also have expressed concern that the RSC’s name could cause confusion with the RISC. “Essentially, the RISC will be developing the lists of risks on a strategic basis,” Sterling explained. “That RISC report, along with other reports, would then be used by the RSC to develop their tactical work plans.

“There were some people who thought that name, the RSC, might be confusing,” she acknowledged. “So, we’ll talk about that as a group at our August meeting.”

Cost-benefit Analysis

Only two stakeholders had comments during the workshop. Barry Jones, of the Western Area Power Administration, asked why the plan did not include an “impact analysis.” Keen Resources’ Robert Blohm, a member of the OC, said the proposal might not produce the promised efficiencies.

“What we have now are three groups simultaneously dealing with three parts of the overall issue, saving a lot of time,” he said. “I would have been more comfortable seeing this [proposal presented in] a more objective or less presumptive fashion, where cost-benefit arguments, pro and con, are listed quite clearly.”

Sterling said the SET’s goal was achieving efficiency, “and hopefully cost savings will result.”

Mark Lauby, NERC chief reliability officer, said the revamping would increase NERC’s effectiveness at addressing issues in a holistic manner. “Going from 120, 130 people to whatever the size of this group ends up being, that will certainly be less of a burden and cost to industry,” he added.

Written Comments

The Policy Input Package for the August quarterly meetings includes written comments from 12 sets of stakeholders, including industrial consumers, cooperatives, generation owners, transmission owners, utilities and RTOs.

In addition to calling for an increase in sector representation, many of the commenters also recommended eliminating the requirement that RSC members have “executive leadership experience,” saying that subject matter expertise is more important.

The Canadian Electricity Association was among the most skeptical of the proposal. “While evolving reliability issues faced by the industry may require solutions and expertise that expand across traditional operating frameworks, many companies are still internally structured through a planning/operations/security model,” said CEA, which represents generators, transmission and distribution companies. “This reality may make it challenging to identify RSC members who can bring the necessary breadth of knowledge and experience to work across these industry areas.”

It also said issues addressed by the RSC must be “well-prioritized, while also guarding against dilution of attention due to a higher number of issues being overseen by one group rather than three.”

Several commenters said that while they agree with combining the OC and PC, they saw less synergy in combining them with the CIPC, which focuses on security.

The Electricity Consumers Resource Council (ELCON), which represents large energy consumers, recommended replacing the OC and PC while retaining a separate security committee. The ISO/RTO Council said that while “there is reasonable justification” for combining operations and planning, “including security matters in the combined group does not improve efficiency.”

The Cooperative Sector said its members were split on the restructuring. It was also critical of NERC’s transparency, saying some of its members “found it challenging to understand the deliberations of the SET meetings and that meeting notes/minutes were not provided to industry. Additionally, the proposal states that the current technical committee members were surveyed for input on the existing committee structure, but the survey results were not made public.”

Only one set of comments, from stakeholders representing state, municipal and transmission-dependent utilities, opposed the RSC proposal (Option 2) outright, saying they preferred Option 1: keeping the three committees and adding a steering committee above them.

“Option 1 provides oversight by refocusing the OC, PC and CIPC, while retaining the benefits those committees bring to NERC and the industry,” it said. “If it is not acceptable as a long-term solution, Option 1 should be adopted as the mechanism for achieving an effective and efficient transition.”

Most of the commenters called for a slower transition. Said ELCON: “Change management at this scale often takes about six months to complete.”

August 11, 2019

Forecasting, Cooperation Key to Calif. Climate Challenges

By Robert Mullin

California must find new approaches to long-term forecasting and collaboration to keep pace with the accelerating effects of climate change on the state’s energy system.

That was the key takeaway from a California Energy Commission workshop Thursday focusing on developing strategies for climate adaptation in the state’s energy sector.

For California, adaptation is currently focused on the threat of wildfires and the role power lines can play in igniting them. The fire season is becoming longer in duration, increasingly destructive to natural and built environment, and more disruptive — and deadly — for the state’s inhabitants. (See California Regulators OK Utility Wildfire Plans.)

“The motivation behind this whole effort is really the stuff that we’ve seen in the news,” said David Saah, managing principal and co-founder of Spatial Informatics Group (SIG). “We’ve seen a bunch of extreme wildfire events that impact the grid, and as it impacts the grid, it impacts all of us in terms of costs, safety [and] reliability.”

The Rim Fire is an example of California's climate challenges — Rim Fire | *U.S. Department of Agriculture*

SIG describes itself as an “environmental think tank” that combines spatial analytics with ecological, economic and social sciences to gauge the impact of policy decisions on ecosystems. The group is working with the state’s Cal-Adapt team to “deliver updated wildfire models for improved electric utility grid resiliency and safety” and support California’s next Climate Change Assessment.

Saah, an associate professor at the University of San Francisco and director of its geospatial analysis lab, explained that while much of the science behind wildfires is well understood, there are still a lot of “known unknowns,” including how to fit California’s recent large outbreaks of tree mortality into existing wildfire models to understand how “large, dead trees” affect wildfire behavior.

“We also know that our existing fire weather forecasts underestimate really severe or extreme wildfire events,” he said. “Part of that is due to the scaling; part of that is due to the technology; part of that is due to the way we have our measurements built. We know we need to deal with that.”

Saah said that current wildfire models do not forecast “a long-term trajectory of where we’re going” and therefore fail to provide investor-owned utilities a roadmap that can inform their long-term planning.

“And all this is really needed by not only the IOUs to be able to predict these overall impacts to the way they operate their systems, but it’s also needed by the taxpayer, the resident, the environment that we all have here in California,” he said.

But Saah said development of new models is not enough: Industry stakeholders must incorporate them into scenario planning.

“Our state is changing. We have this whole wildland-urban interface that we need to think of, and that interface is changing, and where it’s locating, it’s [also] growing. And the way fire behavior moves through those communities — again, it’s one of these places that we need to do better in.”

To address that shortcoming and others, SIG is developing a three-pronged approach to wildfire planning.

The first part seeks to improve the situational awareness of extreme fire weather and tree mortality through “optimal configuration” of weather stations, examination of past extreme events, and analysis and mapping of tree mortality. The second part incorporates new scientific findings into near-term forecasts and long-term projections, while the third would create models that provide IOUs and other stakeholders with “actionable information” applicable to the time scales contained in those forecasts and projections.

Once those models are developed, Saah said their “source code” should be opened to the industry and wider public for critical examination.

“The more critics that we can get hammering away at it, the more learning we can actually get,” he said.

Shifting Paradigms

California regulators have lauded San Diego Gas & Electric as a model for how the state’s utilities can prevent wildfires in their service areas. (See Calif. Regulators to Scrutinize De-energization.) The utility credits its extensive weather monitoring system for the fact that its service territory hasn’t experienced a major fire since 2007.

Brian D’Agostino, SDG&E’s director of fire science and climate adaptation, said the utility isn’t resting on its laurels. The utility is instead effectively rebuilding what was once the world’s largest utility weather network. (The state’s larger IOUs are now poised to surpass SDG&E’s network as part of their wildfire plans.)

California Climate Challenges have required utilities to closely monitor weather — San Diego Gas & Electric credits its intensive weather monitoring with preventing major wildfires since 2007. | *SDG&E*

SDG&E plans to expand its network from 177 weather stations to 225 by the end of next year, with a focus on new installations along the wildland-urban interface that can provide data every 10 seconds to support emergency operations. The new stations will be positioned to perform a new function: minimizing the customer impact of power safety power shutoffs (PSPS) undertaken during periods of high fire danger.

“It’s not just where we find the windiest areas or where this weather information will best improve our fire models, but a big part of it is we have to work with the electric engineers on the system for PSPS events,” D’Agostino said.

SDG&E has also synchronized its fire behavior models with census and building data to identify the highest-risk areas with respect to population density.

D’Agostino also pointed out that SDG&E is also incorporating its database of 455,000 trees into its fire behavior modeling systems in order to identify every tree that has the potential to hit a power line. The utility is also simulating more than 10 million fires every day to determine the risks to its entire system.

“There is a lot of room for improvement, as we’ve heard [from Saah], so we’re looking closely to continue to collaborate with the ongoing statewide projects,” D’Agostino said, expressing excitement at the “open source” nature of the effort.

Speaking during a Q&A session at the end of the workshop, CEC Commissioner Andrew McAllister noted his agency must perform 10-year forecasts to help guide development of the state’s energy system. Pointing out that the CEC increasingly relies on scenario modeling as the effects of climate change “happen more quickly than anticipated,” he asked D’Agostino how SDG&E is considering higher-than-expected temperature increases as it maps out its own long-term transmission and distribution investments.

D’Agostino said he couldn’t directly speak to the utility’s funding priorities, but that as the head of meteorology, he could point to what his department is doing differently, including adopting an approach of focusing on only the most recent years’ weather data — rather than a long historical time horizon — to predict future temperatures and weather patterns.

Another change had to do with load forecasting. D’Agostino explained that SDG&E’s peak loads have historically occurred during periods when the hot, dry Santa Ana winds blow off the desert to the east of Southern California’s population centers. But a new pattern has emerged over the last 10 years in which hot, humid air masses coming from the south are accompanied by unusually warm water currents.

“Last year, we didn’t set a new [peak] load, but our water temperature off San Diego was supposed to be about 68, 69 degrees, and it was close to 80 for almost three weeks in a row, which kept our nighttime temperatures [from] even coming down to what our normal daytime high was,” D’Agostino said. “And that went on for weeks last summer and caused a lot of challenges in operating the electric system. So, we’re seeing a new type of load.”

Reiterating the point about the speed at which climate change is occurring, CEC Vice Chair Janea Scott asked, “What kinds of things do we need to do in this space to make sure that we’re doing our best to keep up or even get out ahead of things?”

“We’re entering into this no-analog scenario,” Saah responded. “We have no idea how this thing’s going to work. If you look at the way our scientific infrastructure’s been built for a long time, it’s been built around competitive science. I think that era’s over. I think we really need to get into collaborative science. And the place where we learn from each other as quickly as we can, we [will] change things as quickly as we can.”

D’Agostino said he seconded that view: “Our ability to work with each other at this point is really going to help us move faster.”

August 8, 2019

Grid Innovation Waiting on DER Rule, Group Says

By Amanda Durish Cook

Nearly 1,000 days have passed since FERC issued a Notice of Proposed Rulemaking to remove barriers to entry from aggregated distributed energy resources participating in the country’s wholesale energy markets.

And since then, potential participants in a major grid modernization have been waiting for their cue, top executives with Advanced Energy Economy told RTO Insider in an interview.

“It’s a long time,” AEE Director Dylan Reed said. The NOPR was issued Nov. 17, 2016. The commission also proposed the same treatment for energy storage resources, which eventually led to Order 841 in February 2018, but it said it needed more information on the DER portion before it could take action, opening a separate docket (RM18-9). (See FERC Rules to Boost Storage Role in Markets.)

“We’ve had members that say, ‘We’d love to participate in these markets, but we can’t or are not going to because we don’t know what the rules will be.’ … It’s regulatory uncertainty that harms investment.”

AEE is a D.C.-based trade association representing a gamut of industry players, including those involved in energy efficiency, demand response, solar, wind, electric storage, electric vehicles, fuel cells, combined heat and power and enabling software — as well as large corporate buyers of clean energy (Microsoft, Amazon, Nest and Tesla are among its members).

The group is on a mission to identify and eliminate structural barriers to participation in U.S. wholesale energy markets, which it estimates would allow the country’s high-tech energy market to expand by $65 billion.

AEE argues that many wholesale market rules are not technology-neutral and have become too outdated to be inclusive. A FERC ruling on aggregated DER participation could jumpstart a more inclusive wholesale market, it says.

Jeff Dennis, the group’s managing director and general counsel, contends RTO market rules are still generally rooted in the past and designed with older generation in mind.

“These barriers to participation come in various different forms today,” Dennis said.

“Some are explicit barriers, but a lot of them are implicit barriers,” Reed added.

Reed pointed to MISO’s Tariff, which explicitly prohibits wind and solar generation from providing frequency regulation, spinning reserves and supplemental reserves — one of the 21 case studies AEE reviewed in a May report on real-world barriers to wholesale market participation by clean energy resources.

“It sounds like a small thing, but if you’re undercutting that, it can put financing for projects at risk,” Reed said.

Dennis also pointed to emerging proposals that could create barriers to participation, such as Study Challenges PJM Energy Storage Rule.)

“You can get a lot of capacity value out of two or four hours of discharge during that peak day. It would unfairly devalue that resource,” Dennis said.

No Risk to Cooperative Federalism

For wholesale markets to foster true competition on a technology-neutral basis, all resources should be allowed to compete on price and performance, AEE argues.

“One of the things we point out is that the markets are designed for large resources to provide lots of a product, but in the future, you’re going to have collections of smaller resources providing smaller but high-performing chunks of services,” Dennis said.

Reed added that such a grid transformation is dependent on a change in RTO market structures.

“That’s when we’re going to see a shift,” Reed said. “We’ve created these rules for all these existing resources, but the resources are changing.”

Dennis said good participation frameworks will give RTOs visibility into DER behavior and generation. He also stressed that no one is expecting perfection in early participation plans.

“There will certainly be a learning curve. I don’t want to be too hard on the RTOs,” Dennis said. But he is adamant that resources on the distribution system will be useful in providing wholesale services.

“It’s going to certainly require coordination between state and wholesale operators. FERC can play a role in ensuring that the RTOs set up frameworks for that communication and coordination,” he said.

Dennis also said distribution utilities can ask FERC to approve tariffs that allow them to recover any verifiable costs they incur from DERs participating in the wholesale markets.

“It’s not an insurmountable barrier,” he said, adding that FERC has already taken this approach with regard to distributed storage, adopting a brand of “cooperative federalism” that ensures greater utilization of those resources.

“I do worry that we’re hearing some utilities claim that FERC setting up this framework is somehow destructive to cooperative federalism,” Dennis said. “FERC has long respected state authority when it comes to wholesale participation by resources connected to distribution, and it continued to do that with storage.”

Dennis noted that, under their retail ratemaking authority, states can restrict DERs participating in retail programs from also participating in wholesale markets, which would still provide DER owners a choice of where to participate. He expects that as states gain experience with DERs, they will see the benefit in allowing wholesale DER transactions.

Despite that vision, Dennis expects the distribution system will still fundamentally serve the purpose of delivering energy to customers and not become like federally regulated transmission.

“We don’t think we’re going to see so many distributed resources participating at wholesale that it swamps the distribution system and creates a situation where [distribution and transmission] perform the same function,” he said.

In the Meantime

AEE says RTOs can take effective steps now while they wait on a FERC order, particularly in alleviating the need for DERs to undertake separate processes to interconnect with both the distribution and transmission systems.

Dennis praised PJM’s examination into how it can streamline its interconnection process for distributed resources and NYISO’s pre-emptive FERC filing to integrate DERs. AEE, however, did t ake issue with parts of the proposal, including proposed metering practices, buyer-side mitigation measures, a capacity value derate provision and a strict, six-second telemetry requirement (ER19-2276).

“I certainly appreciate that New York has gone ahead with something knowing that it’s needed, particularly in response to New York state policy,” Dennis said.

The AEE leaders say they will be pleased if FERC’s final DER rules come close to Order 841.

“I think it will look a lot like Order 841,” Dennis predicted. “We’re hoping for a rule that allows distributed energy resources to provide all the services that they’re technically capable of providing.”

AEE says that while not perfect, RTO compliance plans for storage resources are thorough and well thought out. “All of them have taken the potential of energy storage very seriously,” Dennis said.

He also expects the RTOs’ compliance with a DER rule will be as varied as their responses to Order 841. Importantly, he said, RTOs will begin that work under a FERC deadline and with commission guidance on a workable framework for participation.

“They’ll comply in their own unique way, but we’ll have markets thinking about how they can include these DERs.”

August 8, 2019

Lacking Quorum, FERC OKs ISO-NE Energy Security Plan

By Michael Kuser and Rich Heidorn Jr.

ISO-N E’s controversial proposal to compensate resources for maintaining inventoried energy during the winter months is now effective “by operation of law” because of inaction by FER C stemming from a lack of quorum (ER19-1428-0 0 1).

The commission issued an unusual Chapter 2B notice Tuesday, saying, “Pursuant to Section 205 of the Federal Power Act, in the absence of commission action on or before Aug. 5, 2019, ISO-NE’s proposal, as amended, became effective … May 28, 2019. The commission did not act on ISO-NE’s filing because of a lack of quorum at this time.”

“Since we know Commissioner LaFleur has been recused from ISO-NE matters, that means one of the other three is either (1) recused or (2) choosing not to participate for some reason. If (2) is what’s happened, that strikes me as very rare,” tweeted former FERC attorney Jeff Dennis, now general counsel for Advanced Energy Economy.

Sierra Club spokesman Brian Willis issued a statement calling FERC’s action “odd and infuriating.”

“Back in May, FERC gave ISO-NE a laundry list of what was wrong with its controversial market proposal that would have forced New England ratepayers to shell out about $150 million a year for several years to uneconomic fossil fuel plants through a ‘inventoried energy program.’ The inventoried energy program was broadly opposed by New England stakeholders, who presented evidence that ISO-NE’s program was discriminatory and unnecessary. ISO-NE refused to provide any of the additional information requested by FERC. In light of this, it appeared likely FERC would reject the inventoried energy program outright or order ISO-NE to rewrite its rules based on new principles, legal precedent or with greater consideration for costs to ratepayers.”

Dennis, however, had a different perspective. “Some version of the inventoried energy program has been approved every winter for MANY years now. No one likes it, FERC always wrings its hands when it approves it, but it always does.”

“The ISO will move forward with implementation of the short-term program as we continue working on the long-term, market-based solutions to the region’s energy security challenges,” ISO-NE spokeswoman Marcia Blomberg said in a statement. (See “Assessing ESI Risk Premiums,” NEPOOL Markets Committee Briefs: July 30, 2019.) She pointed to the RTO’s June 6 response to FERC’s request for additional information.

Chatterjee, Glick Split

Section 205 of the FPA requires each commissioner to explain his or her views with respect to the Chapter 2B changes. On Thursday, the commissioners filed their comments, with LaFleur and Commissioner Bernard McNamee indicating they had not participated.

Chairman Neil Chatterjee said he would have approved ISO-NE’s filing, saying it “provides reasonable interim compensation, which can serve as a bridge to development of the longer-term market solution.”

“It is well settled that the entity filing a proposal need only demonstrate that the proposed revisions are just and reasonable, not that the proposal is the most just and reasonable proposal,” he said. “While some parties argue that ISO New England’s previous winter reliability programs are less expensive and may be more effective than the proposal in this proceeding, those programs are not the subject of this proceeding and are not before the commission.”

Chatterjee said the program “also aims to ameliorate the misaligned incentives issue” that prior programs did not address.

But Commissioner Richard Glick said he would have opposed the program as “patently unjust and unreasonable.”

“The program will cost New England consumers as much as $300 million without any evidence to suggest that it will actually improve the region’s fuel security or that any improvement is likely to be worth the cost. Indeed, the program goes so far as to hand out substantial payments to nuclear, coal and hydropower generators with no indication that these payments will change their behavior in the slightest,” Glick wrote. “That is a windfall, not a just and reasonable rate.”

FCAs 14 & 15

The RTO’s fuel security program is an interim plan for its 14th and 15th Forward Capacity Auctions, covering the capacity commitment periods of 2023/24 and 2024/25. In March, it filed Tariff revisions; the commission on May 8 said the filing was deficient; and the RTO submitted its response on June 6.

At a July 15 technical conference, New England regulators and stakeholders told FERC that ISO-NE’s fuel security proposal could increase costs without solving the region’s winter supply concerns and urged the commission to postpone the RTO’s Oct. 15 filing deadline and require it to provide more analysis before drafting Tariff changes. (See FERC Staff Hear Doubts on ISO-NE Fuel Security Plan.)

Jeff Bentz, the New England States Committee on Electricity’s director of analysis, testified the schedule could be delayed by six months without impacting the proposed implementation.

New England Power Pool Chair Nancy Chafetz, of Customized Energy Solutions, asked the commission to “keep an open mind” on the proposals. Although NEPOOL has the “jump ball” right to propose an alternative to the RTO’s proposal, Chafetz said the stakeholder body wouldn’t have an official position until it votes in October.

According to an email from Day Pitney attorney Pat Gerity, “while NEPOOL intervened in the Chapter 2B proceeding, it took no substantive position, and absent express direction from the [Participants] Committee, will not challenge the Chapter 2B Notice.”

Gerity noted FERC had previously been unable to act on an ISO-NE filing, but Congress has since stepped in to allow such non-action by the commission to be challenged on rehearing and appeal. “Specifically, the ‘Fair Ratepayer Accountability, Transparency, and Efficiency Standards Act’ was included as part of ‘America’s Water Infrastructure Act of 2018’ (Oct. 23, 2018), the result of which will be to treat the Chapter 2B notice for purposes of rehearing to be an order issued by the FERC accepting the changes,” Gerity said, adding that any request for rehearing of the Chapter 2B notice will be due on or before Sept. 4.

Section 205 of the FPA requires each commissioner to explain his or her views with respect to the Chapter 2B changes, though none has yet filed a written comment.

In a related matter, the New England Power Generators Association asked the commission Tuesday to reverse its decision to require generators needed for fuel security to offer at zero in FCA 14. It asked the commission to issue a rehearing order by Sept. 26, “before key deadlines lapse” for the auction (ER18-2364-001 and E L 18-182-002).

August 8, 2019

NYISO Manual Changes for New SRE Penalty OK’d

In a brief teleconference meeting Wednesday, the NYISO Business Issues Committee approved manual changes to accommodate a new penalty scheme to improve the ISO’s ability to call on external capacity resources.

The revisions to the Installed Capacity Manual and Transmission and Dispatch Operations Manual, aligning them with the external supplemental resource evaluation (SRE), passed without opposition.

Under the new scheme, any external resource that fails to meet delivery criteria would be subject to the penalty, which is equal to 1.5 times the applicable spot price multiplied by the number of megawatts of shortfall and the percentage of the SRE call hours to which a supplier fails to respond.

LBMP import transactions use an external proxy bus as the source and the NYISO reference bus as the sink. | *NYISO*

External capacity suppliers would not be subject to the penalty if their failure to deliver is beyond their control. The ISO would calculate deficiencies monthly, using the total number of SRE call hours in a given month that the resource could be available and the total megawatt shortfall in that month.

The market operations report was not included in the BIC meeting materials because the data had not yet been compiled. It will be added to the meeting materials once completed, said Robb Pike, director of market design and product management.

— Michael Kuser

August 8, 2019

Earnings Soaring, NRG Prepares for Tight ERCOT Supply

By Michael Kuser

NRG Energy’s profits jumped sharply in the second quarter, boosted by a surge in earnings for the company’s power generation division.

The rise was “driven primarily by higher wholesale power prices, offset by higher retail supply costs and mild weather,” NRG CEO Mauricio Gutierrez said in a call with analysts on Wednesday.

The company repor t ed second-quarter earnings of $189 million ($0.75/share), compared to $27 million in the same period last year.

NRG’s generating arm earned $618 million for the quarter, up 145% from a year earlier, while losses from the retail division grew from $84 million to $280 million.

The company said that generation gains on hedge positions this year were partially offset by losses on retails hedges, “both driven by large movements in gas prices and ERCOT heat rates.”

During the quarter, NRG launched its “capital-light” strategy by signing approximately 1.3 GW of solar power purchase agreements at an average length of 10 years, complementing its generation portfolio. The company also highlighted that its 385-MW combined cycle Gregory plant in Corpus Christi returned to service in June.

NRG’s ERCOT data show mild weather impacting power prices. | *NRG*

Gutierrez noted NRG has spent $1.25 billion so far this year on a share buyback program and announced plans to spend $250 million more by year-end.

“We will address our plans for the remaining $259 million of 2019 excess cash, as we usually do, on the third-quarter earnings call,” Gutierrez said, noting that the company is reserving up to a $124 million in capital for the Petr a Nova project. The coal-fired power plant captures carbon dioxide from one of the eight units at the 3.65-GW WA Parish Generating Station southwest of Houston, which is then injected into mature oilfields to release more oil.

In May, NRG agreed to spend $325 million for Stream Energy’s retail electricity and natural gas business, increasing its retail portfolio by approximately 450,000 customers. The acquisition closed on Aug. 1.

Markets Update

Gutierrez said NRG expects ERCOT’s supply-demand balance to remain tight, given strong load growth, previous generator retirements and a lack of new builds. He pointed out that ERCOT’s own projections for its future supply margins rely on its semi-annual Capacity, Demand and Reserves report, which has typically been a “poor indicator of what actually gets built in the current year.”

He noted the report includes 1.7 GW of natural gas-fired generation that has been delayed an average of five years “with no signs of moving forward” and 1.4 GW of thermal generation already set to retire, while little more than half the 7 GW of solar projects listed have posted the financial security needed to interconnect to the grid.

“ERCOT needs a lot of generation … needs a lot of investment,” Gutierrez said. “And even the numbers that we’re providing you are only sufficient to maintain the current load reserve margin that we have.

“Obviously, the implication of that is we expect the ERCOT market to continue to be robust over the foreseeable future but, more importantly, to be pretty volatile,” he said. “This price environment should prove difficult for pure retailers or generators that will be exposed to swings in the market.”

Gutierrez also referred to a recent FERC Halts PJM Capacity Auction.)

“While we’re hopeful a final order will be issued by the end of the year, the timeline for FERC action remains uncertain,” Gutierrez said. “We continue to view a strong [minimum offer price rule] as the simplest and most cost-effective way to reduce the harmful impact of subsidies on the capacity market.”

Call transcript courtesy of Seeking Alpha.

August 7, 2019July 8, 2025

Exelon: Market Flaws Threaten Ill. Carbon Policy

By Christen Smith

Exelon leadership told investors last week Illinois’ transition toward 100% carbon-free power can’t succeed without PJM market reforms to keep the company’s nuclear plants running.

Chris Crane, Exelon | © RTO Insider

“The bottom line is fundamental market reforms are needed in the United States if we want to meet the nation’s clean energy climate goals, maintain fuel security and a reliable system,” Exelon CEO Chris Crane said. “We need to sustain and increase electrification [and] preserve a significant economic value through good paying jobs and property taxes. We’ll continue to work at the state level and the national level with both Congress and the administration to make this happen.”

The company’s quarterly earnings report said its Dresden, Byron and Braidwood nuclear plants in Illinois are “showing increased signs of economic distress, which could lead to an early retirement, in a market that does not currently compensate them for their unique contribution to grid resiliency and their ability to produce large amounts of energy without carbon and air pollution.”

Exelon said PJM’s most recent capacity auction in May 2018 “resulted in the largest volume of nuclear capacity ever not selected in the auction, including all of Dresden, and portions of Byron and Braidwood.”

Illinois legislators enacted a zero-emissions credit (ZEC) program in 2016 to rescue Exelon’s Quad Cities plant along the Mississippi River. The company collected $150 million in ZEC revenue for the second half of 2017.

“We are pursuing a number of market reforms addressing the financial challenges many of our [nuclear] plants face,” Crane said. “Against this backdrop, I can also again assure you we will not operate our unprofitable or negative free cash flow plants. You’ve seen us close money-losing plants in the past. You should expect that discipline to continue if reforms are not enacted.”

In the longer term, Exelon told investors the company hopes energy price formation and carbon pricing will help address the market inequities currently hurting its bottom line.

The company’s lobbying for clean energy has produced mixed results, so far. While New Jersey approved $300 million in ZECs last year, Pennsylvania lawmakers stalled a plan that would have added nuclear energy into its alternative energy portfolio and saved the remaining operating reactor at Three Mile Island.

“Either we have a clear path to securing them or the units will be shut down,” said Joseph Nigro, Exelon’s chief financial officer. “We will not damage the balance sheet sitting around for years with negative free cash flow or negative earnings.”

As FERC mulls PJM’s proposed revision of its minimum offer price rule (MOPR) — which would carve out subsidized generation and then adjust clearing prices as if the resources never left — Exelon continues campaigning for clean energy policies in states throughout the PJM footprint. The company’s executive team told investors in Illinois that a coalition of stakeholders wants to expand the state’s clean energy mandate from 25% by 2025 to 100% by 2030 to match other progressive states across the country.

That could be a monumental task under current laws, however.

Last month, the Illinois Power Agency warned that the state only secures about 10% of its power from renewable resources. In an interview with WTTW, Director Anthony Star blamed rate caps and a 2016 energy bill that ramped up the agency’s procurement responsibilities. He said he hoped legislation would fix both issues.

Kathleen Barron, Exelon’s vice president of regulatory affairs, said the Citizens Utility Board, the Clean Jobs Coalition and both the labor and renewable resources industries all stand behind an expansion of the mandate, noting “the consumer advocate is heavily focused on this policy as well because the question of the state having to pay twice for capacity has been very much in the forefront.”

In October 2018, Exelon joined with consumer advocates from D.C. and Illinois, the Sierra Club, the Natural Resources Defense Council, the Nuclear Energy Institute and others to a s k FERC for a fixed resource requirement (FRR) mechanism that would allow load-serving entities to satisfy their capacity obligations outside of PJM’s capacity market by procuring capacity from state-supported resources (EL18-178, et. al.).

“There are a number of parties who will come together in the end to help communicate the message that Chris [Crane] mentioned this is important for the state, but it’s not going to be possible if we can’t allow these resources to count as capacity,” Barron said. “And that’s why the FRR is foundational to getting this policy done.”

Earnings Drop

Exelon reported earnings of $494 million ($0.50/share) for the quarter, a decrease from $539 million ($0.56/share) a year earlier. Adjusted operating earnings dropped to $0.60/share from $0.71/share in the second quarter of 2018 as revenue dropped to $7.689 billion from $8.076 billion.

Crane noted the company has filed distribution rate cases for Baltimore Gas and Electric, Commonwealth Edison, and Pepco.

On July 22, Pepco and other parties filed a settlement agreement with FERC for PECO Energy’s formula transmission rate that includes a 10.35% return on equity, including a 50-basis-point RTO membership adder.

Crane said the company was happy with the Trump administration’s decision not to impose quotas on uranium, which he said “would have jeopardized the continued operation of commercial nuclear reactors” in the U.S.

August 7, 2019

PJM Operating Committee Briefs: Aug. 6, 2019

VALLEY FORGE, Pa. — PJM’s Operating Committee unanimously endorsed clarifications for non-retail behind-the-meter generation (NRBTMG) business rules on Tuesday, completing the first two key work activities identified in a problem statement/issue charge approved in March. (See “PJM Continues Review of non-Retail BTM Generation Business Rules” in PJM Operating Committee Briefs: Feb. 5 , 2019.)

The revision s to Manuals 13 and 14D will clarify the reporting, netting and operational requirements of NRBTMG that will ensure member and PJM responsibilities, processes and procedures are clear and adequately captured, said Terri Esterly, PJM’s senior lead engineer for Capacity Market Operations.

The PJM Operating Committee met on Aug. 6, 2019 in Valley Forge, Pa. | © *RTO Insider*

NRBTMG refers to resources used by municipal electric systems, electric cooperatives or electric distribution companies to serve load. They do not participate as supply resources in PJM markets but can be netted against their wholesale load to reduce transmission, capacity, ancillary services and administrative fee charges.

PJM’s rules on such resources resulted from a 2005 settlement agreement (EL0 5 -127), before development of the RTO’s capacity market and CP constructs. NRBTMG resources can be called upon during the first 10 maximum generation emergencies annually, while CP resources are required to perform during all performance assessment intervals (PAIs). BTM operators that fail to perform face reduced netting benefits. In 2006, the grid operator identified about 400 MW of NRBTMG.

Esterly said the manual updates will not change the terms of the 2005 settlement agreement. She also told stakeholders preliminary data collection suggests PJM’s existing nameplate capacity clocks in around 1,800 MW. Several generators, however, did not submit summer-rated ICAP values, likely contributing a significant undercount.

Operations Reports Staying in SOS

PJM will no longer review systems operations reports during the monthly OC — unless it is answering specific stakeholder questions or highlighting an unusual event, like a polar vortex, Secretary Don Wallin said.

The reports will be posted along with other meeting documents, as usual, but verbal reviews will only occur at the Systems Operations Subcommittee (SOS).

In its last review with the OC, however, PJM said it set a new weekend peak value of 150,454 MW — displacing the 149,644 MW record set on July 7, 2012. This year’s summer peak of 152,315 MW was hit July 19 during a five-day hot weather alert that covered the majority of the RTO’s footprint.

January 2018 Extreme Cold Weather Report

PJM continues its review of recommendations included in the NERC/FERC January 2018 Extreme Cold Weather report and may bring necessary recommendations to stakeholders at the September OC.

FE R C last month called for reliability rules requiring generator owners and operators to winterize their units and provide their reliability coordinators and balancing authorities with information about their preparations. (See FERC Calls for C o ld Weather Reliability Standard.)

The commission issued the directive as a result of a joint FERC-NERC investigation into the abnormal cold and higher-than-forecast demand that caused MISO and SPP to seek voluntary load reductions and nearly forced load shedding in MISO South on Jan. 17, 2018. (See FERC, NERC to Prob e January Outages in MISO South.)

Alpa Jani, PJM’s senior consultant for dispatch, said many of the report recommendations were previously discussed in the context of previous polar vortexes and the capacity market.

August 7, 2019

CenterPoint Q2 Earnings Beat Expectations

CenterPoint Energy on Wednesday beat both analysts’ expectations and its performance a year ago by reporting second-quarter earnings of $165 million ($0.33/share).

The results exceeded Zacks Investment Research’s projection of 31 cents/share and the second quarter of 2018, when the company lost $75 million ($0.17/share). Last year’s loss included a pre-tax write down of $242 million to reflect the company’s investment in Time Warner, which has since been acquired by AT&T.

“It was a solid second quarter,” CEO Scott Prochazka told analysts during a Wednesday earnings call.

The Houston-based company said its performance was driven by its utility operations and cash contributions from non-utility businesses such as Enable Midstream Partners, a joint venture with OGE Energy and ArcLight Capital Partners. The pipeline company reported $74 million of equity income for the quarter, a $16 million improvement over last year.

Prochazka said CenterPoint no longer intends to sell common units of Midstream, as “much has changed since we first considered the sale.” He said Midstream, which has contributed $1.7 billion in cash distributions to CenterPoint since 2013, “now reports a smaller percentage of our earnings” with the closing of the $6 billion Vectren merger in February.

Vectren contributed $25 million in operating income.

CenterPoint’s stock opened at $28.85/share Wednesday morning but quickly dropped to $27.47. The stock recovered to close at $28.14, down 2.5%.

— Tom Kleckner

August 7, 2019December 12, 2023

SERC Draws Lessons from Arkansas Sabotage

By Rich Heidorn Jr.

SERC Reliability used part of its quarterly open forum last week to provide lessons learned from a series of attacks on Arkansas’ power grid in 2013.

Bill Peterson, SERC’s manager of outreach and training, told the story of Jason Woodring, who was sentenced to 15 years in prison for attacks on grid facilities in the state between August and October 2013.

“We’re trying to share some awareness topics [that will] help you proactively consider some security enhancements to protect your substations,” Peterson said.

Peterson prefaced the presentation with a reference to the April 2013 attack on Pacific Gas and Electric’s Metcalf substation, in which a sniper shot 17 transformers, causing outages in nearby neighborhoods and forcing grid operators to reroute power. (See Substation Saboteurs ‘No Amateurs’.)

The attack ultimately led to NERC reliability standard CIP-014-1, which requires utilities to protect transmission facilities whose loss could cause instability, uncontrolled separation or cascading outages. The standard led utilities to add fencing, cameras and alarms to their facilities. At Metcalf, PG&E removed vegetation near the substation boundary and replaced a chain link fence with a concrete wall to prevent a line of sight into the substation.

Woodring, a pool maintenance worker with a methamphetamine habit, told the court in June 2015 he wanted to cause a power outage to “get everybody’s attention” to what he saw as the deterioration of society. He said he had noticed how people united during an emergency.

“When I went up there on that 500,000-volt power line, I actually thought I was going to be helping people,” he said in his guilty plea.

Woodring’s sabotage began when he attempted to topple an Entergy transmission tower adjacent to a rail line in the city of Cabot, spending weeks removing about 100 steel bolts that secured the tower to its concrete foundation. He then strung a steel cable from the tower to a tree on the other side of the tracks, hoping that a passing train would hit the cable and pull the tower down.

But the cable — insulated with blue plastic hosing used for pool maintenance — was snapped by a train without causing the tower to budge.

On Aug. 21, Woodring returned, climbing the tower armed with a hacksaw, which he used to cut the connectors holding one of the 500-kV lines, and the line itself, which fell onto the track.

“What he was trying to do apparently is get the cable to itself attach to a bypassing train in an attempt to pull the entire tower down,” Peterson said. Later that morning, a Union Pacific freight train struck the line, blacking out nearby homes. Again, the tower did not come down.

The FBI offered a $20,000 reward for the person responsible, speculating that the attacker must “possess above-average knowledge or skill in electrical matters.”

Less than a month after the first incident, Woodring broke into an Entergy extra-high-voltage substation in nearby Scott after surveilling it for several days.

Using bolt cutters to get through a fence and padlocks on the door of the control house, he dumped a gallon of gasoline and oil on the control panel and the floor before setting it ablaze. The building was destroyed.

He left a cryptic, crudely written message: “YOU SHOULD HAVE EXPECTED U.S.”

“Local law enforcement assumed that he was trying to hide his identity and show that it was a [foreign] terrorist attack instead of somebody local,” Peterson said.

A week after setting the fire, and after the FBI raised its reward to $25,000, Woodring used a chain saw and an axe in an attempt to cut through a distribution pole near his house in Jacksonville. After that failed, he discovered an unattended tree maintenance vehicle near his house and drove it back to the poles, dragging one of them down and blacking out 10,000 customers of First Electric Cooperative.

“How easy is it to access these vehicles? Are keys … just left in them? Are there fences around these vehicles? Are they parked in certain locations?” Peterson asked. “What other types of equipment do you use that could be used against you?”

Woodring was arrested after a fourth attempt at sabotage when he used a fishing pole to cast a piece of wire over the power lines near his home, causing an explosion.

That led law enforcement agents to Woodring’s house, where they discovered blue plastic hosing like that found at the scene of the transmission tower sabotage. He confessed.

Woodring was sentenced to 15 years in federal prison and ordered to pay almost $4.8 million in restitution to Entergy and almost $49,000 to First Electric Cooperative.

Peterson said the Woodring story “brings up a couple areas for us to … think about improving our awareness of our infrastructure.”

“Stay in contact with local law enforcement. Make sure you preserve evidence if you do think there’s a disruption or damage done to a facility. … Keep in mind that could become a crime scene.”

Audit Evidence

The quarterly forum also featured a tutorial by SERC officials on best practices for providing audit evidence.

Asked whether audit documentation was improving or getting worse, SERC’s Clay Shropshire said it depends on the entity.

“There are entities that we go to and they really seem to get it. And we can even be asking for something a little different and before we even finish the question they go, ‘OK, I know exactly what you want.’ And they go run off grab it and they come back. [And we say], ‘Yeah that’s what we need.’

“There are other entities we ask for [evidence] six or seven times and we finally run out of time.”