Page 1266 – RTO Insider

March 25, 2019

MISO Seeking Multiple Vendors for Market Platform Redesign

By Amanda Durish Cook

NEW ORLEANS — MISO will attempt to divide its ongoing market platform replacement into a series of smaller agreements with vendors rather than one large contract with an outside party — a move that could affect the project’s timeline.

The RTO says the move will avoid overreliance on any single vendor, and that it is continuously evaluating possible impacts to the timeline and scope of the platform redesign. It had planned to begin to move its system from a server-based platform to the cloud in 2020. (See New MISO Platform Headed to the Cloud.)

The MISO Board of Directors meets on March 21. | © *RTO Insider*

MISO Vice President of Market System Enhancements Todd Ramey last week said the RTO can “lean on” its legacy platform system a little longer than originally anticipated if necessary. It was planning for a complete swap-out by 2023, under some pressure from existing platform vendor General Electric, which originally said it would also end IT support for the platform around that time.

However, GE is now willing to support the existing platform through 2030 at no additional costs to MISO, Ramey said. He said MISO and GE have “proactively negotiated an annual cost to run the existing platform until 2030 in advance should it be needed.”

“So quite a bit more runway if we need to do that,” Ramey said during a Board of Directors meeting Thursday.

Director Barbara Krumsiek half-jokingly asked for assurances that it won’t take until 2030 for a complete replacement.

“We’re working hard to make sure we can make the transition much sooner,” said Ramey, adding that MISO’s goal is to stick to its original timeline. He stressed that the RTO has not yet found any reason to extend use of the legacy platform and hasn’t made any such decision.

The multi-contract move will negate MISO’s earlier plans to reveal a chosen single vendor at the beginning of 2020 after finishing an evaluation of alternatives to GE.

MISO will provide its next update on the platform redesign to the board in June. Ramey said staff are already training members on how to work on the new platform.

Noting that cybersecurity was one of the reasons MISO cited for moving to a new platform, Director Thomas Rainwater asked RTO executives to include an update on how they will bolster cybersecurity measures if they prolong the use of the legacy system.

At a March 19 meeting of the board’s Technology Committee, Director Baljit Dail asked if GE might have any expectations of a single, large contract. MISO Executive Director of Market Development Jeff Bladen said GE was in agreement about moving forward with a series of smaller agreements.

March 25, 2019

Stakeholders Mixed on MISO Seams To-do List

By Amanda Durish Cook

NEW ORLEANS — Stakeholders last week gave MISO leadership mixed signals on what they expect from seams policy, though they generally agreed the RTO shouldn’t strive for exacting consistency in how it deals with different neighbors.

For some, the conversation also dredged up memories of when PJM, not SPP, was a source of seams policy frustration.

Kevin Gunn urges candidness at the March 20 hot topic discussion. | © *RTO Insider*

In opening the quarterly “hot topic” discussion during MISO Board Week on Wednesday, moderator Kevin Gunn, energy attorney and former chairman of the Missouri Public Service Commission, urged sector representatives to speak freely about what they’d prefer in seams relationships.

“I don’t want to say this is a safe space because the press is here,” Gunn joked.

MISO today has markedly different seams relationships with PJM versus SPP.

The Organization of MISO States (OMS) and SPP’s Regional State Committee (RSC) have been meeting since mid-2018 to discuss interregional coordination, which has never produced a major transmission project, frustrating some stakeholders and causing market inefficiencies.

MISO has said there may be “philosophical differences” on either side of the seam.

OMS and the RSC recently released a joint white paper on the seams issues and have asked Potomac Economics — MISO’s Independent Market Monitor — and SPP’s Market Monitoring Unit to conduct analysis to monetize some of the issues. (See MISO, SPP Monitors to Conduct Seams Analysis.)

The MISO-PJM seam is a different matter. The RTOs have created a new smaller interregional project type called targeted market efficiency projects (TMEPs) and have approved two rounds of transmission projects and upgrades in two years. (See MISO, PJM Endorsing 2 TMEPs for Year-end Approval.)

However, MISO and SPP staff and stakeholders recently recommended performing a coordinated system plan study this year, which could result in the RTOs’ first-ever interregional project. (See MISO, SPP Seek Coordinated Plan in 2019.) The two plan to study six possible sites, an effort that still requires approval by their Joint Planning Committee.

Missouri PSC Commissioner Daniel Hall, one of the regulators spearheading the recent OMS-RSC collaboration, expressed optimism regarding the MISO-SPP seam. He pointed to the RTOs’ proposed revisions to their Joint Operating Agreement that would do away with a joint model requirement, eliminate a $5 million cost threshold for projects, add avoided costs and adjusted production cost benefits to project evaluation, and make CSP studies a more regular occurrence. A FERC filing is expected later this month.

“Those changes are significant from our perspective,” Hall said. “I want to applaud MISO for working with SPP.”

Alcoa’s DeWayne Todd, representing MISO’s Eligible End Use Customer sector, reminded the audience that several interregional projects are ultimately deemed not worthy after cost analyses and quantification of benefits. He cautioned against stakeholders using interregional project approvals as a benchmark for successful seams.

“It’s very easy to say, ‘There should be more interregional projects.’ Well, should there be?” Todd asked.

Independent Power Producers sector representative Tia Elliott, of Cleco Cajun, said MISO and stakeholders usually don’t work quickly unless outside pressure exists from regulators, FERC or other entities.

“When OMS and [the Organization of PJM States Inc.] began working together a few years ago, we saw results,” Elliott said, adding that MISO could be prompted into action now that OMS and the RSC are working together.

Director Baljit Dail reminded stakeholders that a decade ago, MISO’s seams with PJM were a source of frustration.

“The first seams discussion I sat in on was about PJM, and there was a lot of angst in the room — a lot. And now it seems like that has been substituted for concerns about SPP,” Dail said. “There has been enormous progress, and we should recognize this.”

Dail said that about 11 years ago, as he sat in on one MISO discussion on PJM seams, he jotted a note : “It takes two to tango.” He asked stakeholders if they think MISO is doing enough outreach and compromise with its neighbors.

“I think SPP has been more willing than MISO to roll up their sleeves and look for projects. To some extent, I think MISO needs to catch up,” Hall responded.

“I don’t want to give anyone the impression that our sleeves aren’t rolled up as high as they should be,” MISO CEO John Bear said. He said the seam is still encumbered by rate pancaking and transmission scheduling issues that must be resolved before some proposed projects can show economic benefits.

Multiple stakeholders said it would be helpful for MISO to place some timelines and deadlines on certain goals.

“At the end of the day, we’re looking for mutually beneficial projects that will solve problems … but we’re not necessarily seeing these problems go away,” said Arkansas Assistant Attorney General Christina Baker, of MISO’s Public Consumer Advocates sector.

MISO-SPP TMEPs?

Hall asked why MISO and SPP couldn’t create the same TMEP-style project type that MISO and PJM have.

“It’s not hard to find the projects. You have to look for market-to-market congestion costs, look if that cost of the project is covered by the congestion savings over the four years. … It’s a pretty simple concept,” Hall said.

He said he’s heard that some MISO transmission owners are critical of TMEPs with SPP, and he asked why.

Transmission Owners sector representative Jeff Dodd, director of transmission and RTO policy for Ameren, responded that MISO’s less mature seam with SPP has not yielded enough historical congestion data to be a foundational basis for projects.

Hall said study by the RTOs’ market monitors will focus on whether TMEPs can be cost-effective and include a cost analysis of the regional contract path between MISO North and MISO South on SPP transmission.

Although it’s too early to confirm, he said, the regulatory organizations might forward the analysis to FERC to open a technical docket on solutions.

“I think the analysis might show that there’s a host of targeted market efficiency projects that could or should be built,” Hall said.

Question of Consistency

Director Theresa Wise asked if the RTOs in the Eastern Interconnection would be better off functioning as one large, consistent RTO with aligned markets.

“I’m a mathematician, so I often think of big networks as a way to optimize things,” she said.

But Cleco’s Elliott said there’s conflict even within MISO’s 10 stakeholder sectors on how to handle seams relationships. “If we can’t come to an agreement on how to handle this internally, how are we going to do this with external parties?”

Several stakeholders said they didn’t think MISO requires the same seams policies with SPP as it does with PJM.

“A lot of the sectors said consistency wasn’t important across seams — that it was actually an impediment,” moderator Gunn observed. “This was one of the most fascinating things to see: advocating for inconsistency or even saying consistency wasn’t important.”

Director Thomas Rainwater said there’s a difference between advocating for absolute seams policy consistency and adjusting policies to produce similar outcomes. He said he preferred the latter approach.

March 25, 2019February 12, 2025

Overheard at the 161st New England Electricity Restructuring Roundtable

BOSTON — FERC Commissioner Cheryl LaFleur kicked off her farewell tour with reflections on electricity markets in New England and around the country, NERC CEO Jim Robb shared concerns about fuel security, and a panel of experts discussed the challenges confronting the industry.

Attendees heard that and more at the 161st New England Electricity Restructuring Roundtable hosted by Raab Associates on Friday. Following is some of what we learned during the event.

Attributes over Volume

LaFleur, who announced in January that she will leave the commission between the end of her term June 30 and the end of the year, offered her insights into the changes on the horizon. (See LaFleur Announces Departure from FERC.)

“I am seeing lots of evidence from all over the country, in organized markets and outside organized markets, that a fundamental shift is underway in how we procure and pay for electricity,” she said.

“Back in the vertically integrated days … we took it for granted, and many times we still do, that energy is priced on volume,” LaFleur said. “Aside from a few ancillary services that were co-optimized at a lower price, everything was volumetric, and it worked as long as the cost curves were that way. Well, there’s a lot of evidence that the cost curves are not going to look that way in the future.”

With persistently low gas prices, even in New England, zero-marginal-cost renewables coming online, and distributed energy and demand-side resources changing the load curves, the industry can’t assume that resources are going to make money on volume, and that peaks are going to set the prices at which resources make money, she said.

“Across all the markets and regions, what we’re seeing is people … paying for attributes rather than volume in the energy markets, in the capacity markets and in the ancillary services markets,” LaFleur said.

“The trouble is, an attribute is a slippery thing” and can encompass anything from stockpiling coal to pricing carbon; from flexible ramping to scarcity pricing, storage or fuel security, she said.

“And it’s in the capacity markets too, where we have Pay-for-Performance; Capacity Performance; seasonal capacity,” LaFleur said. “I’m starting to think if we’re not going to pay on volume, how are we going to pay? And this is fundamental. … Most of the money is in the energy market. How we pay for energy is going to determine what we get and how we pay to keep the lights on.”

The “cut-across issue” for LaFleur is jurisdictional, where the federal government does some things and the states do others.

“We understand what’s interstate, and we have jurisdiction over the ISO rates, and then the states have their jurisdiction, but then here are resources connecting behind the meter at the distribution level that operate like wholesale resources,” she said in response to a question about DERs.

“It’s really easy to say, ‘Oh, we should have more cooperation with the states,’ but it’s really hard to figure out how to do that in this space because our system was set up as if we knew the difference between central station wholesale and distributed [resources],” LaFleur said. “So, [there is] a lot to work through, but … I think it’s way more an opportunity than a challenge. It could be, to use an overused word, transformative.”

‘A Lot to Celebrate,’ but…

New England has benefited from ISO-NE’s creativity in dealing with fuel security, said Robb, who has been at the helm of NERC for nearly a year after leaving the chief role at the Western Electricity Coordinating Council.

“There are really three hotbeds of issues in reliability around the country,” Robb said. “The first one is California … the epicenter of the issues around an integration of large-scale solar into the system. … Whoever thought we’d have too much generation on peak?”

Until the Aliso Canyon gas storage facility came in service, it was not clear what a growing balancing role the natural gas system was playing in response to the surge in solar capacity, and how that system was being stressed by fast-ramping gas-fired plants pulling gas off the network faster than it could be replaced, Robb said.

“The other area is Texas, which is really testing all of our patience on the question of capacity adequacy and reserve margin,” Robb said. “They’re operating at about a 7 to 8% reserve margin going into the summer. They put great faith in the market signals that they’re sending to the operators and to the plants online. They made it through a very hot summer last year, so there’s something in the soup that we’re starting to understand about what kind of reserve margins are really necessary.”

The third area is New England, and “from an environmental perspective there’s a lot to celebrate,” Robb said. “You have substantially repositioned your fleet to a much lower carbon footprint than it was 20 or 30 years ago to meet environmental objectives and have managed to keep the lights on.

“The shift away from on-site fuel — large coal, nuclear and petroleum — to resources that are dependent on weather and just-in-time delivery of fuel really changes the risk profile,” he said. “The issue up here is not one of capacity adequacy; it’s one of energy adequacy and, importantly, fuel adequacy to serve load.”

Robb looked at the dramatic oil consumption during last winter’s sever cold snap — when generators burned as much oil in two weeks as they normally do in a year — and asked what would have happened if the cold snap had lasted another day.

Oil supplies at plants around New England declined rapidly over the two-week cold spell as gas prices spiked and dual-fuel plants switched to oil, but the RTO avoided serious reliability issues thanks to LNG shipments. (See FERC, RTOs: Grid Performed Better in Jan. Cold Snap vs. 2014.)

“You guys are a day away from a load-shedding event,” Robb said.

Getting Late

Where the NERC CEO sees the region’s glass as being half-empty, Dan Dolan, president of the New England Power Generators Association, said he “would argue that we passed the stress test [and] came through the most severe cold snap in 100 years with gas in the system at the end.”

“The open market has been extraordinarily successful at dispatch of least-cost resources,” Dolan said.

However, he pointed to the increasing trend of states procuring energy contracts and estimated that state-sponsored resources will comprise more than half of the region’s energy production by 2027.

Dolan cited research by Joe Cavicchi of Compass Lexecon, commissioned by NEPGA, that says New England’s much-needed fast-ramping resources require capital investment — and that generators believe the market signals get mixed in a half free, half state-controlled market.

Jonathan Raab of Raab Associates, who conducted the roundtable, asked if the wholesale markets are at a tipping point, and if so, how New England can prepare for the world 10 years from now.

“It’s later than you think,” said Katie Dykes, commissioner of the Connecticut Department of Energy and Environmental Protection.

“We hear from those who have been in this market for quite some time that there’s a lot of volatility, uncertainty, marginal earnings and even from the [perspective of the] status quo, it’s not a market that a lot of people are feeling comfortable continuing to invest in,” Dykes said.

“Our failure to plan proactively [for natural gas supply constraints] … has exposed our ratepayers to the exercise of market power by those generators who do have the ability to provide fuel-secure resources,” she said. (See Exelon to Push for Laws, Rules to Boost Profitability.)

The retreat at the federal level on the need to address climate change has injected further uncertainty for those who would like to move forward with market-based approaches to valuing carbon reduction, she said.

Connecticut has long-term contracts approved or pending for 52% of the state’s energy demand, including 13% for non-nuclear resources needed to meet its renewable portfolio standard, Dykes said.

“If we’re paying a capacity payment to resources for availability for an entire year, for resources that we know don’t have access to pipeline gas to be able to run year-round, I think some further refinement on what that market is designed to procure is important,” Dykes said.

To the extent that states are seeking to meet their planning objectives for environmental policy around carbon, the more that those products can have resource adequacy and fuel security benefits will also be helpful, she said.

Inflection Point

“We are with our capacity markets nearing an inflection point where we need to figure out exactly what our resource adequacy construct needs to be going forward,” said Mark Karl, ISO-NE vice president for market development.

As he did in December, Karl said the RTO’s long-term solution for energy security has three components: multiday-ahead markets, a new ancillary service integrated into that market and a new, voluntary forward seasonal auction. (See Fuel Security the Focus at ISO-NE Consumer Liaison Meeting.)

“I should be clear it’s not just about fuel; it is about energy security,” Karl said.

The RTO’s enhanced storage participation rules go into effect April 1, with a second phase coming in the second half of this year, and staff are working on a third phase, he said. (See FERC Accepts ISO-NE Storage Tariff Revisions.)

In addition, the RTO prepared an interim proposal for compensating generators for fuel security, which it plans to file this month with FERC, with or without stakeholder endorsement. (See ISO-NE Steady on Fuel Plan Despite NEPOOL Rebuff.)

The Analysis Group’s Paul Hibbard, former chairman of the Massachusetts Department of Public Utilities, said the desire to reduce energy sector carbon emissions is the biggest market factor of all.

With various state policies being enacted, “how do the markets provide the resources needed to maintain reliability, particularly during winter months?” Hibbard asked. “That’s what makes this so incredibly difficult.

“There’s really very little opportunity for resources to earn sufficient revenues through energy markets when you look five or 10 years out, but we still have to maintain reliability during those winter months,” he said.

When the Pilgrim nuclear plant and the remaining oil and coal units retire, the system will become “a lot more peaky” from a gas supply perspective, he said. “What really changes here is that the consumption of natural gas power plants for electricity spikes in the winter … so it really increases our reliance, particularly for power sector reliability, on LNG over the course of the 25 or 50 coldest days of the year.”

Add electrification and “things get really scary, because now pipelines can’t even meet total demand for gas for over 100 days in the year,” Hibbard said. “It’s this combination of what the states are trying to do to meet carbon-reduction goals, and the feedback that has on the electric system, that makes the challenges so incredibly important when thinking about this transition over the next 10 years.”

March 24, 2019

NERC Standards Committee Briefs: March 20, 2019

NERC Standards Committee Chair Andrew Gallo urged committee members Wednesday to file comments on Phase 2 of NERC’s Standards Efficiency Review before Friday’s deadline.

Gallo made his comments after Howard Gugel, NERC senior director of engineering and standards, presented an update on the review, which is considering retiring or consolidating administrative or duplicative standards.

The inquiry is considering changes in six areas of NERC’s Operations & Planning and Critical Infrastructure Protection standards, including evidence retention time frames, moving requirements to guidance, simplifying training requirements and consolidating data exchange requirements.

NERC held a webinar on the initiative Feb. 22 and accepted additional comments until Friday.

“I would really encourage all of the members of the Standards Committee … to please engage your folks in the process,” said Gallo, director of corporate compliance for Austin Energy. “It’s very rare that we [have] had opportunities to do a hard look at the standards.

“Everybody is so quick to [complain] about the standards … ‘[It’s] administrative. It’s burdensome. It doesn’t really help reliability,’” he added. “Those kinds of things you hear … all the time. Here’s our chance — let’s use it. This is a real good opportunity for us to try and do away with some of the things that are more administrative.”

Standards Grading Process on ‘Pause’

In a related matter, the committee agreed to “pause” work on the Standards Grading Process until May 2020 to avoid conflicts with other current initiatives with overlapping resources and scope.

In 2016 the SC created the Periodic Review Standing Review Team, composed of the chairs of the SC, Operating Committee, Planning Committee, a regional representative and NERC staff, to annually grade a selected set of standards.

Gugel said the initiative resulted from a charge by the Board of Trustees to develop metrics to signal whether revised standards have resulted in improvements. The 2017 review graded 47 requirements of eight standards.

“Given all the changes that we’ll be making with the Standards Efficiency Review, and potentially changes that would [be made] in Phase 2, we thought it would be a good idea this year to put a pause on that so we can concentrate our efforts, our focus, on the efficiency review,” Gugel said.

Cyber System SAR Approved for Posting

The committee accepted a Standards Authorization Request (SAR) and authorized a 30-day comment period and 30-day drafting team nomination period to consider standard changes to accommodate use of third-party “cloud” data storage providers.

The SAR was proposed March 1 by Tri-State Generation and Transmission Association on behalf of a sub-group of the Critical Infrastructure Protection Committee (CIPC) to consider use of encryption as a security measure under NERC BES Cyber System Information (BCSI) access management rules.

The project, which was endorsed by the CIPC on March 5, would consider changes to CIP-004-6 and CIP-011-2.

“The standard should allow multiple methods for controlling access to BES Cyber System Information, rather than just electronic and physical access to the [BCSI] storage location,” the SAR says. “As currently drafted, the requirement is focused on access to the ‘storage location,’ and therefore does not permit methods such as encryption and key management to be utilized in lieu of physical/electronic access controls.”

Functional Model Advisory Group Work Frozen

The committee agreed to direct the Functional Model Advisory Group (FMAG) to cease work pending deliberations on whether the group should continue or be eliminated to avoid confusion over registration requirements and related standards.

Created in 2014, the FMAG was tasked last year with aligning the terms and definitions in the Functional Model guideline with those used in NERC’s Rules of Procedure. It also was asked to solicit industry input on whether it should continue its work and make “more substantive” revisions to the FM to align with industry practices, NERC said.

At its December 2018 meeting, the SC endorsed the FMAG’s work on the first task but delayed publication of its report. At the same time, several SC members called for creating a small group of members from the NERC standing committees to consider next steps.

In February, the Standing Committee Coordinating Group (SCCG) agreed to form an ad hoc group of NERC staff, Compliance and Certification Committee leadership and SC leadership to map out plans for the FM. SC Chair Gallo instructed the FMAG to refrain from additional work until the ad hoc group makes its recommendations.

“What’s happened historically is, any time a change is made to the Functional Model, there are those who think it automatically changes registration, how standards are written. So, it’s caused a lot of angst,” explained Charles Yeung, SPP’s executive director for interregional policy. “It makes it much clearer to say, ‘If it’s in the registration criteria, it’s black and white.’”

Gallo, a member of the ad hoc group, said he’d like the issue resolved quickly. “We don’t want this to languish very long. The Functional Model work has been going on now for a couple of years. It’s been stopping and starting and [moving in] fits and starts,” he said. “That’s not good for anybody.”

Revised Charter OK’d

Members approved a new committee charter, replacing the version last amended in December 2014 and reviewed and reaffirmed in December 2016. The revisions, which are mostly cosmetic or updates, were drafted by the SC Executive Committee and will be submitted to the board at its next meeting.

“I thought there were a lot of changes in here that didn’t really change anything,” commented Barry Lawson, associate director of power delivery and reliability for National Rural Electric Cooperative Association. “A few of the changes are substantive.”

Section 5.1 amends the timing for selecting the committee chair and vice chair, requiring nominations about 150 calendar days before the end of the expiring terms.

Another member expressed concern about the elimination of a section mandating at least two Canadian representatives. But NERC’s Gugel said the section was removed as duplicative because Canadian representation is protected in Rules of Procedure Appendix 3B.

Modifications Within SAR Scope

The committee agreed that making modifications to IRO-008-2 and TOP-001-4 are within the scope of the Project 2015-09 system operating limits SAR.

The Standards Drafting Team (SDT) requested the committee’s approval to make clarifying modifications to the two standards to ensure their consistency with proposed FAC-011-4 Requirement R6 regarding logging and reporting of system operating limits (SOL) exceedances.

The SDT is modifying FAC standards that address SOLs and interconnection reliability operating limits (IROLs).

SDT member Stephen Solis, of ERCOT, said several entities have market mechanisms for addressing projected post-contingency exceedances identified in real-time assessments and generally can mitigate them within minutes.

Solis said the revised rules would give entities up to 30 minutes to address the issue before having to report an exceedance to its reliability coordinator or transmission operator (TOP).

Under proposed FAC-011-4 R6, if a TOP’s real-time assessment indicates that a contingency would cause a facility to exceed its emergency rating, it would constitute an SOL exceedance, triggering logging and other documentation requirements.

Several entities have complained that the requirement creates an undue burden for logging, communicating with the RC and creating audit-ready compliance documentation, Solis said. They said the unnecessary logging and communications would divert system operators’ attention from operating the system, creating an increased reliability risk.

“We can’t lower what the requirements are, but we can clarify what the requirements are,” Solis said. “Solidify for everybody what is and is not an SOL exceedance.

“If you’re a TOP and you see a voltage limit exceedance, you can [perform switching] in 30 seconds to a minute,” Solis said. “Why [should] you then [have] to call your RC right after these normal-type operating actions that happen throughout every day?”

Participant Conduct Policy

NERC Senior Counsel Lauren Perotti briefed the committee on NERC’s new Participant Conduct Policy, which spells out acceptable (e.g., discussing issues) and unacceptable (e.g., engaging in price fixing, using NERC for commercial purposes) conduct at stakeholder meetings.

The policy will replace individual policies previously adopted by the SC and Operating Committee. It applies to all NERC standing committees.

“The whole point of us putting this together was to promote an efficient and effective use of our participants’ time. NERC relies on its stakeholders to achieve its mission,” Perotti said.

The rules bar members from expressing personal views unless they are directly related to the scope of work. “‘I really hate XYZ politician’ is not appropriate,” Perotti said.

Perotti said that when stakeholders speak to news reporters, they should specify that they are speaking for themselves or their company and not for NERC.

– Rich Heidorn Jr.

March 24, 2019

Silicon Valley Tackles Wildfire Prevention

By Hudson Sangree

SACRAMENTO — The SLAC National Accelerator Laboratory occupies a sprawling site in the hills above Stanford University’s main campus and uses so much electricity to run its laser and particle physics experiments that it has its own high-voltage transmission line.

Stanford’s Linear Accelerator Center is using the latest in 3D imaging and artificial intelligence to prevent its transmission line from sparking wildfires. | *SLAC*

The overhead line runs through one of the wealthiest and most important parts of Silicon Valley. It’s also in a high-risk fire zone of hillsides covered in tall grass, chaparral and dense tree cover. A wildfire there could be a major disaster.

To tackle that threat, SLAC has employed the latest in geospatial 3D imaging, artificial intelligence and big data to assess risks and manage vegetation around the 5-mile 230-kV line. The technology’s developers say it could be applied broadly across California.

Enview, based in San Francisco, uses the latest in geospatial 3D imaging to identify potentially hazardous vegetation near power lines. | *Enview*

Catastrophic wildfires have been called the state’s new normal, but “they don’t have to be,” said San Gunawardana, CEO and co-founder of Enview, a company that uses 3D analytics to protect utility infrastructure. “We need a new generation of tools to prevent and predict these events. Big data and AI are one of those tools, and they’re available to us today.”

Gunawardana made his remarks at the inaugural Wildfir e Technology Innovation Summit that took place Wednesday and Thursday at California State University, Sacramento, with roughly 700 attendees. It was hosted by the California Public Utilities Commission, IBM and the University of California, San Diego, among others. Sponsors included Enview, Google and Microsoft.

The two-day summit featured presentations from firefighting organizations such as the California Department of Forestry and Fire Protection (Cal Fire); utilities, including San Diego Gas & Electric, which has installed hundreds of cameras and weather stations across its service territory; and tech firms that make safety sensors, fault interrupters and monitoring software.

An estimated 700 stakeholders attended the inaugural Wildfire Technology Innovation Summit, convened by the California Public Utilities Commission, at California State University, Sacramento. | © *RTO Insider*

The summit was intended to “dramatically shift how we address the expanding climate-change challenges of drought, dry winds and vegetation,” organizers wrote. “California has long been a global leader in technology innovation, and we must work together to devise the tools we need to get ahead of this issue.”

Steve Liebelt (left), a SLAC engineer, and San Gunawardana, CEO of Enview, demonstrate the high-tech methods SLAC uses to keep its transmission line from sparking fires. | © *RTO Insider*

Gunawardana presented the SLAC case scenario with Steve Liebelt, an engineer at the linear accelerator and part of its vegetation management team. The Enview CEO then moderated a panel discussion titled “Big Data, Advanced Analytics and Machine Learning” that included Sumeet Singh, a Pacific Gas and Electric vice president and head of its Wildfire Community Safety Program. (See PG&E Lays out Billion-dollar Wildfire Plan.)

State fire investigators blamed PG&E’s equipment for starting 17 of the 21 Northern California wildfires of 2017, which raged through the famed wine country of Napa and Sonoma counties. The company’s equipment is also suspected of starting massive fires in the Sierra Nevada foothills, including November’s Camp Fire, the deadliest in state history.

PG&E and its parent company PG&E Corp. filed for Chapter 11 bankruptcy reorganization this year as they faced billions of dollars in fire liability. (See Bankruptcy Only ‘Viable’ Option for PG&E, Lawyer says.)

Sumeet Singh (right), PG&E’s vice president for wildfire community safety, called for utilities to share more safety data. | © *RTO Insider*

Singh said PG&E has 129 million trees that could potentially contact power lines in its 72,000-square-mile service territory. That territory is larger than 33 states, including Florida, and about half of it is in areas of elevated or extreme fire risk, he said.

With such vast numbers, machine learning and big data are “must have,” Singh said. He called for utilities to share more safety information among themselves, as he said the nuclear power industry had done to improve its safeguards.

Elizaveta Malashenko, the CPUC’s deputy executive director for safety and enforcement policy, sat on the panel with Singh. She said the last two years of increasingly large and deadly wildfires have shown that the efforts of state agencies is insufficient and that AI is needed to bolster traditional fire prevention methods.

San Gunawardana (left), CEO of 3D analytics firm Enview, moderated a panel on big data and machine learning that included Elizaveta Malashenko, the CPUC’s deputy executive director of safety and enforcement policy. | © *RTO Insider*

The industry is at a crossroads, when human intelligence “cannot process the amount of information necessary to get us to the next stage of knowing what to do” to prevent wildfires, she said.

March 24, 2019

PJM MRC/MC Briefs: March 21, 2019

Wilmington to be Retired as Meeting Site

WILMINGTON, Del. — The city will be retired as the meeting site for the Markets and Reliability and the Members committees, PJM stakeholders agreed Thursday with a sector-weighted vote of 3.74 to 1.26.

Katie Guerry of Enel X first proposed relocating future meetings to PJM’s Conference and Training Center in Valley Forge, Pa., at the Feb. 21 Members Committee meeting, noting the center provides stakeholders cost efficiencies, as they have access to PJM staff and resources while there. (See “Stakeholders to Consider Retiring Wilmington as Meeting Site,” PJM MRC/MC Briefs: Feb. 21, 2019.)

PJM’s Markets and Reliability Committee meets at the Chase Center in Wilmington, Del., on March 21. | © *RTO Insider*

MC Chair Chuck Dugan, of East Kentucky Power Cooperative, said notice of when the location change will take effect will be given to members in the coming weeks. “We have some contracts to cancel,” he explained, referring to the Chase Center on the Riverfront, the current venue for meetings in the city.

Emotional Farewell for CFO Suzanne Daugherty

Members presented PJM CFO Suzanne Daugherty with a signed plaque of recognition and gratitude for her two decades of service at the RTO just days before her anticipated retirement.

PJM CFO Suzanne Daugherty listens as colleagues praise her 20 years of service. | © *RTO Insider*

During her last time serving as chair of the MRC, Daugherty tearfully bid farewell to members, saying she’s “enjoyed working with every single one of you.”

PJM staff and members alike commended Daugherty for her commitment to the RTO over the years and said they were sorry to see her leave.

“They say where you stand on a particular issue depends on where you sit,” said Stu Bresler, senior vice president of operations and markets. “With respect to where Suzanne stood, it was equally consistent. The direction was always ‘Do the right thing,’ and the remainder of the conversation was ‘How do we get there?’

“If you are looking for a role model … it’d be challenge to find anyone better than Suzanne Daugherty,” he added.

Daugherty announced in February she would retire on April 1 after 20 years with PJM. The decision follows months of recriminations by stakeholders over credit policies that allowed a small trading shop to default on more than $100 million in financial transmission rights losses. (See PJM CFO Retiring in Wake of GreenHat Default.) She never connected her announcement to the GreenHat Energy fallout, rather saying she timed it to coincide with her husband’s retirement.

Members Committee Chair Steve Lieberman presents Daugherty with a retirement gift on behalf of PJM members. | © *RTO Insider*

The Board of Managers’ report on PJM’s handling of the GreenHat incident is expected to be released this week.

Fix for Deficiency Cure Periods OK’d

Stakeholders unanimously approved a quick fix to prevent transmission customers from falling out of the interconnection queue because of minor errors.

They endorsed revisions to Manual 14A: New Services Request Process and the Open Access Transmission Tariff that would give customers 10 days to fix minor errors in their requests, no matter whether they submit their application on the first or last day of the new services request window. (See “Quick Fix for Queue Filing Errors Endorsed,” PJM PC/TEAC Briefs: Feb. 7, 2019.)

The change will be effective with queue AF1, which opens April 1.

Manuals Endorsed

The MRC endorsed the following manual changes:

B. Manual 13: Emergency Operations: Updates language to align with both NERC EOP-004-4 and OE-417 reporting requirements in Attachment J, relating to disturbance reporting.

C. Manual 20: Resource Adequacy Analysis: Cover-to-cover periodic review includes minor grammatical corrections and updated language to reflect implementation of Capacity Performance. Removes references to demand resource factor and deletes sections 5 and 6, which relate to demand response reliability target analysis procedures and limited-availability resource constraint procedures, respectively.

D. Manual 37: Reliability Coordination: Periodic cover-to-cover review that includes minor grammatical updates and annual changes to transmission owner designations. Adds PJM’s Reliability Plan to attachment A and updates appendix D to include AMP Transmission as a TO.

March 24, 2019

PJM Members Welcome Carbon Pricing Talks

By Christen Smith and Rich Heidorn Jr.

WILMINGTON, Del. — PJM stakeholders appear ready and willing to explore carbon pricing in the RTO — a prospect that concerns utilities in coal-heavy states.

pjm carbon price — Michael Borgatti | © *RTO Insider*

Michael Borgatti of Gabel Associates presented a first read of a problem statement and issue charge at the Markets and Reliability Committee meeting Thursday that would task stakeholders with creating rules to address carbon leakage and help states meet greenhouse gas reduction policies. Borgatti made the presentation on behalf of the Independent Energy Producers of New Jersey, which includes NextEra Energy and PSEG Power.

“Acknowledging the reality that some folks are pursuing these policies and others aren’t is not an indictment or an endorsement of either of those positions,” he said. “The conversation is being had whether we want to or not. We are not policymakers here. What we should do is consider options to make sure pricing reflects the difference between [those] pursuing these policies and those that are not.”

Many stakeholders expressed support for the initiative and said they looked forward to engaging in the process. Borgatti said he expected the initiative would take one to two years to consider policy changes.

“It’s one of those discussions that are in the hallways and the back of the room,” said Greg Poulos, executive director of the Consumer Advocates of PJM States. He said he supported the initiative, “so we can have a discussion in the front of the room.”

Gary Greiner of Public Service Electric and Gas also expressed support. “We agree it’s the right time to be in this, with [the Regional Greenhouse Gas Initiative] showing its head in New Jersey and Virginia.

In December, New Jersey Gov. Phil Murphy’s administration proposed rules to rejoin RGGI, which the state left in 2012 under Gov. Chris Christie. One proposal would set the state’s initial carbon dioxide cap for electric generation at 18 million tons in 2020 — when the return would be effective — declining by 3% annually through 2030. A second proposed rule concerns how the state would spend proceeds from the CO₂ allowance auctions. The comment period on the proposals closed Feb. 15.

Earlier this month, Virginia Gov. Ralph Northam vetoed legislation that would have prevented his state from joining RGGI. Northam is pushing for the state to join the pact next year.

Only two PJM states, Delaware and Maryland, are currently RGGI members.

The problem statement refers to leakage concerns — changes to generator dispatch decisions that occur when energy offers from some resources reflect the cost of carbon while others do not. In addition to RGGI, it noted that New York and Canada are implementing carbon pricing.

Load interests expressed concern over the complexity and impact of carbon pricing given the diversity of climate policies in the 13-state RTO’s footprint.

“This is such a tricky issue because I think there are chicken-and-egg-type problems associated with it,” said Susan Bruce, representing the PJM Industrial Customer Coalition. “One concern right now … with the amount of change that’s occurring, we don’t know what we don’t know at this point in time, and that’s layering on an additional level of uncertainty.”

Carl Johnson of the PJM Public Power Coalition said the language in the problem statement suggests there’s already a solution for the issue.

“If the carbon price is zero and you don’t have leakage, then you don’t have to do anything,” he said. “If we are talking about just leakage, then I think we are fine. But if we start considering other issues, like resource adequacy, I can understand the hesitancy from nonparticipating states.”

American Electric Power’s Dana Horton noted that his company has many coal-fired generators and serves states that have not adopted aggressive climate policies. “We’re … concerned about what this might do to our customer base and their costs,” he said. “We have lots of reservations.”

Borgatti responded that the initiative is intended to ensure appropriate pricing in states with and without climate policies. “We’re talking about creating an option that the states don’t have today,” he said.

PJM’s Stu Bresler called the problem statement and issue charge “fortuitous.” The RTO issued a white paper in 2017 that explored ways to implement carbon pricing on a regional or subregional basis.

“I feel like the problem statement and issue charge is an ideal forum for feedback for what we can work into our process,” he said. “We support engaging stakeholders in this discussion because we were going to do this anyway.”

March 24, 2019

MISO: Winter Emergency Another Signal for Grid Ops Change

By Amanda Durish Cook

NEW ORLEANS — MISO’s most recent maximum generation emergency is yet another portent of its increasing need to rethink grid operations, executives told the Board of Directors last week.

Although it was better managed than the January 2018 MISO South emergency, the event demonstrates how the RTO has come to rely on intermittent resources subject to weather conditions and demand-based resources, which require a maximum generation event to access.

MISO Executive Director of Market Operations Shawn McFarlane said the Jan. 30 event in the Midwest seemed like a repeat of the extreme cold conditions a year ago.

Independent Market Monitor David Patton called the “highly regionalized” event an almost a mirror image of last year’s cold.

miso winter grid operations renewables — David Patton (left) and Richard Doying | © *RTO Insider*

This time, however, McFarlane said MISO avoided the need for emergency purchases and was able to stay within the contractual limits of its transmission contract path while still accessing Southern capacity. The RTO estimated that both scheduled and voluntary load modifications, paired with school and business closings, reduced demand by 3 GW or more during the event.

Patton said MISO was able to effectively manage congestion during the event because of improved management of its market-to-market constraints with SPP and PJM.

Wind Forecast Lapse

But executives admitted a blind spot when it came to the RTO’s wind generation forecasting that day.

Last month, MISO pledged more study into generation cutoffs in extreme temperatures and how to account for voluntary load curtailments in load forecasting. It has said that “an earlier-than-expected drop in wind output increased insufficiency risk” early Jan. 30. Wind output during the morning peak was about 4 GW below MISO’s forecast as the worst of the cold struck the Midwest. (See “MISO Researching Generation Cutoffs, Voluntary Load Curtailment,” MISO Reliability Subcommittee Briefs: Feb. 27, 2019.)

Additionally, MISO said failed starts from conventional generation, uncertainty around the load forecast and risk of more outages contributed to the decision to call up about 2.5 GW worth of load-modifying resources (LMRs). Unplanned outages reached 29 GW on Jan. 30.

Patton said MISO’s emergency offer pricing, which defaulted prices to above $600/MWh, was adequate to incent response. In fact, he said, it was even higher than needed because MISO’s extended locational marginal pricing couldn’t model accurately when to ramp up other online resources to displace emergency megawatts.

“Did you get that in the minutes?” MISO President Clair Moeller joked in response. Patton has long panned MISO’s emergency pricing as too low to properly rouse resources into action.

Director Barbara Krumsiek commended the RTO for keeping some less-than-economic units on to cover the failed starts of other generation. She said MISO’s commitment to public safety during the dangerous cold rightly eclipsed a focus on economics.

But she asked if the RTO’s lack of foresight on the cold weather wind cutoffs was a “new revelation” or simply an extreme temperature anomaly, unlikely to be repeated.

McFarlane said that while some turbines have cold weather packages, others must shut off to avoid blade damage, and MISO lacked insight on the specifics. Unfortunately, he said, wind generation in MISO North is clustered where the cold was the most extreme: Minnesota and western Iowa.

“We were relying on our [2014] polar vortex experience … and we expected 1 GW to drop off,” he said.

McFarlane said MISO has since instituted a general temperature cutoff assumption for wind generation. He said it will now hold conversations with wind operators to figure out more precise cutoff assumptions.

Director Baljit Dail asked if the emergency illustrates a need to rethink emergency preparedness altogether.

“Should we be thinking differently about the loss-of-load and reserve margin?” Dail asked.

Moeller said MISO’s ongoing research into resource availability and flexibility is just that — an investigation into loss-of-load risk in every hour of every day as opposed to an annual peak. None of MISO’s last three maximum generation events has occurred in the summer.

A bright spot, McFarlane said, is that half of MISO’s 12 GW in LMRs will be available in two hours or less in the upcoming planning year, thanks to FERC’s approval of rules requiring those resources to provide lead times they can consistently meet. Historically, only about 3 GW of LMRs were ready within two hours, McFarlane said. (See “LMR Registration Steady Despite New Requirements,” LSE Load Forecast Documents Incomplete, MISO says.)

“That will help significantly as we deal with tight conditions going forward,” he said.

Patton commended the better LMR response time. He said LMRs with up to eight-hour lead times are essentially “worthless” in an emergency.

“But in our LOLE [loss-of-load expectation] study, we model them as if they’re available,” he said.

MISO’s average winter load was 77.8 GW from December 2018 through February 2019, with a 101-GW peak occurring Jan. 30. The RTO said that except for extreme cold at the end of January, footprint temperatures were in line with historic norms over winter, which drove down load and congestion. As a result, prices averaged $28.41/MWh, a 6% decrease over the same time last year.

Evolving Resources, Evolving Operations

Richard Doying, executive vice president of market development strategy, said continued turnover in the resource stack and renewables growth will mandate operations changes in MISO.

“You’ve got a combination of factors that gives rise to changes in … grid operations,” Doying said, adding that “once upon a time,” it was much easier to dispatch the system.

“Some of these effects are already hitting us today,” Doying said in reference to MISO’s string of off-peak emergency events. “That flexibility is needed today … [and] we’re already seeing the consequences of these trends.”

To adapt, Doying said MISO has identified three areas of work: increasing the deliverability and availability of resources, bettering system flexibility, and improving its visibility of distributed energy resources.

“We know that there will have to be adjustments made to the market, but exactly what those are, we don’t yet know,” Doying said. He said the many possible solutions will be put to the stakeholder process. Fixes could include scarcity pricing, a 15-minute day-ahead market, more storage integration efforts, modeling smart inverters in planning, and collaboration with distribution operators so MISO can see DER contributions.

Dail asked if MISO was studying whether consumer costs could increase as it changes its market in response to trends.

“We’ve got [members] in economic distress,” he said.

Doying said MISO’s exploration of trends and grid response doesn’t include price effects but offered that market changes needed to maintain reliability would also maintain efficiency.

March 24, 2019

NERC Standards Committee Briefs: March 20, 2019

NERC Standards Committee Chair Andrew Gallo urged committee members Wednesday to file comments on Phase 2 of NERC’s Standards Efficiency Review before Friday’s deadline.

NERC held a webinar on the initiative Feb. 22 and accepted additional comments until Friday.

Standards Grading Process on ‘Pause’

In a related matter, the committee agreed to “pause” work on the Standards Grading Process until May 2020 to avoid conflicts with other current initiatives with overlapping resources and scope.

Cyber System SAR Approved for Posting

The project, which was endorsed by the CIPC on March 5, would consider changes to CIP-004-6 and CIP-011-2.

Functional Model Advisory Group Work Frozen

“What’s happened historically is, any time a change is made to the Functional Model, there are those who think it automatically changes registration, how standards are written. So, it’s caused a lot of angst,” explained Charles Yeung, SPP’s executive director for interregional policy. “It’s only changes to the registration criteria that can change entity registration.”

Revised Charter OK’d

Section 5.1 amends the timing for selecting the committee chair and vice chair, requiring nominations about 150 calendar days before the end of the expiring terms.

Modifications Within SAR Scope

The committee agreed that making modifications to IRO-008-2 and TOP-001-4 are within the scope of the Project 2015-09 system operating limits SAR.

The SDT is modifying FAC standards that address SOLs and interconnection reliability operating limits (IROLs).

Solis said the revised rules would give entities up to 30 minutes to address the issue before having to report an exceedance to its reliability coordinator or transmission operator (TOP).

“We can’t lower what the requirements are, but we can clarify what the requirements are,” Solis said. “Solidify for everybody what is and is not an SOL exceedance.

Participant Conduct Policy

The policy will replace individual policies previously adopted by the SC and Operating Committee. It applies to all NERC standing committees.

“The whole point of us putting this together was to promote an efficient and effective use of our participants’ time. NERC relies on its stakeholders to achieve its mission,” Perotti said.

The rules bar members using NERC’s listserv to express personal views unless they are directly related to the scope of work. “‘I really hate XYZ politician’ is not appropriate,” Perotti said.

Perotti said that when stakeholders speak to news reporters, they should specify that they are speaking for themselves or their company and not for NERC.

— Rich Heidorn Jr.

March 24, 2019

FERC Backs Cleco on Tax Rate Calculations

By Amanda Durish Cook

FERC last week dismissed a Louisiana city’s complaint that Cleco Power collected $6.7 million in excess revenue last year because its rates did not immediately reflect the 2018 federal corporate income tax cut (EL19-6).

The city of Alexandria’s October complaint asked FERC to require Cleco to flow back to transmission customers excess accumulated deferred income tax (ADIT) collected from January to May 2018.

But FERC on Thursday said the city filed its complaint too late and in the wrong docket. But even without the procedural deficiencies, the commission said, it would not have granted Alexandria’s request because Cleco’s rates use historical test year costs as a “reasonable proxy” for rate collections and there is no true-up mechanism to ensure recovery of actual costs.

Cleco’s annual transmission revenue requirement (ATRR) is based on a rate year of June 1 through May 31. Cleco used the 35% federal income tax rate in its May 31, 2017, ATRR update for its 2017 rate year and replaced it with the 21% in its filing for the 2018 rate year.

Alexandria contended that because the lower tax rates took effect Jan. 1, 2018, Cleco over-collected its transmission rates by $6.7 million for the last five months of the 2017 rate year, with the city overpaying by $271,000. It called the amount “a permanent windfall” to Cleco.

Alexandria, La. | *Alexandria Office of the Mayor*

The company responded that it “would be a violation of the approved historical test year approach” if it included cost increases or decreases that occurred outside the test year.

Cleco also said Alexandria was seeking to “cherry-pick” a single declining cost in its transmission formula rate, while ignoring other costs that increased. For example, Cleco said its transmission wages increased by 13% in 2017 because of additional hires but that it did not attempt to recover the increased costs in the ATRR until the 2018 rate year.

FERC agreed: “Due to this nature of Cleco’s transmission formula rate, Cleco may under-collect or over-collect various costs during a given rate year.”

MISO requires all transmission owners’ rates return or recover excess or deficient ADIT from customers as a result of tax law changes. But FERC said that requirement doesn’t speak to the precise timing of when the new rates must take effect.

“Cleco’s template calculates a single ATRR for the entire rate year. There is no provision in Cleco’s template for a partial year ATRR calculation, nor is there a provision to calculate the ATRR for a given rate year using two different federal corporate income tax rates,” FERC said. “The change in the federal corporate income tax rate that took effect on Jan. 1, 2018, was unknown when Cleco prepared the annual update for the 2017 rate year.”

Additionally, FERC pointed out that there is no provision in Cleco’s rate rules that it must recalculate ATRR if a tax change takes place during a rate year.

The commission also said Alexandria failed to file its challenge in time under Cleco’s rate rules. Alexandria submitted its informal challenge with Cleco after the Jan. 31, 2018, deadline and its formal challenge with FERC after the April 15, 2018, deadline. “Further, Alexandria did not file the formal challenge in the same docket as Cleco’s informational filing of its 2017 annual update” (ER18-999), FERC said.