Page 1061 – RTO Insider

March 25, 2019

FERC OKs Trans Bay Cable Sale to NextEra

By Hudson Sangree

Despite protests from a number of cities, FERC last week approved the sale of the Trans Bay Cable, a 400-MW line that runs for 53 miles under San Francisco Bay, to NextEra Energy Transmission (EC19-36).

“Based on the record in this proceeding, we find that the proposed transaction will not have an adverse effect on rates,” FERC wrote.

The cable’s current owner is Trans Bay Cable LLC, a portfolio company of SteelRiver Infrastructure Partners of Sausalito, Calif. The Trans Bay Cable provides electric transmission between two substations owned by Pacific Gas and Electric and is under CAISO control.

The Trans Bay Cable runs for 53 miles under San Francisco Bay, providing transmission between two PG&E substations. | *SteelRiver Infrastructure Partners*

Trans Bay and NextEra asked FERC to approve the deal in December. The companies did not publicly disclose the purchase price, but news reports put it at $1 billion.

The line’s current rates are fixed under a settlement agreement that expires next year. In its comments to FERC, the Northern California Power Agency said NextEra should not be able to recover acquisition costs after that settlement rate expires.

Six cities in California — including Anaheim, Riverside and Pasadena — said NextEra’s application failed to state how the transaction could affect rates. The city of San Francisco requested FERC to require more information from the applicants regarding acquisition costs “in order to ensure that no unlawful acquisition premium will be included in rates.”

Another intervenor, the California Municipal Utilities Association, said “that applicants have chosen to withhold key financial data from parties in this proceeding and that, without that information, parties are forced to rely upon public news reporting regarding the terms of the proposed transaction,” FERC wrote. “California Municipal Utilities Association states that, given that the applicants have chosen to request confidential treatment of financial data, it is difficult to test their assertion that the proposed transaction will have no adverse effect on rates.”

The 400-MW high-voltage transmission line serves the San Francisco area. | *California State Coastal Conservancy*

NextEra said it has no intention of trying to recover acquisition costs from CAISO customers via rate increases, and FERC said that even if NextEra did so, it would face a difficult test under Section 205 of the Federal Power Act to show the “the acquisition provides specific, measurable and substantial benefits to ratepayers, consistent with commission precedent.”

With regard to the confidentiality concerns, FERC said intervenors can request copies of confidentially filed materials, but that so far, none has done so.

March 25, 2019

Glick Disputes FERC ‘Breakthrough’ on LNG Projects

By Rich Heidorn Jr. and Michael Brooks

WASHINGTON — FERC Commissioner Richard Glick on Thursday rejected Chairman Neil Chatterjee’s claim of a bipartisan “breakthrough” on the commission’s evaluation of LNG projects, joining with fellow Democrat Cheryl LaFleur to say the panel was still ignoring the projects’ impact on climate change.

On Feb. 21, a FERC news release celebrated the commission’s 3-1 approval of the Calcasieu Pass LNG export project in Louisiana, calling it a “breakthrough … agreement that may provide a path forward” for the commission’s review of 12 other proposed LNG facilities.

The release quoted Chatterjee thanking LaFleur and Republican Commissioner Bernard McNamee for joining the chairman in the majority. It made no mention of LaFleur’s six-page concurrence, in which she disagreed with Chatterjee and McNamee for failing to disclose the cumulative greenhouse gas emissions from the project (CP15-550). (See LaFleur Sides with Republicans on LNG Terminal as Glick Dissents.)

Glick, who had authored a seven-page dissent, said at Thursday’s monthly open commission meeting that the ruling was “anything but a breakthrough.”

Although the order did acknowledge the project could produce almost 4 million tons of direct GHG emissions annually, Glick said, it ignored the impact of them on climate change and “then found that the project’s environmental impacts will not be significant and that, as a result, the project is in the public’s interest.”

“I don’t want to hear that assessing significance is too hard. The commission is called upon to do it all the time in other contexts with far less information than we have in this proceeding.”

Site plan for the Calcasieu Pass LNG export project | *Venture Global LNG*

LaFleur’s Frustration

LaFleur, who has joined Glick in opposing some gas pipeline projects, wrote in her concurrence that she supported Calcasieu Pass as “not inconsistent with the public interest” based on the “governing law.”

In her comments at Thursday’s meeting, LaFleur repeated her frustration with the Republicans’ reluctance to address GHG emissions.

“We have been treating climate impacts differently than all the other environmental impacts that we look at,” she said. “We know how to quantify, mitigate [and] consider impacts to land, water and species. We make calls on whether impacts to wetlands or to a specific species of mussels are significant. But we don’t do that for climate change impacts. Instead we say we can’t figure out how to do it.”

She also complained about the split jurisdiction over LNG exports. While FERC permits the facilities and evaluates their direct environmental impacts, the Department of Energy decides whether the export of the fuel is in the public interest, including the consideration of upstream and downstream GHG emissions.

“It’s hard to do the [public interest] weighing if we’re only in charge of the impact but someone else is in charge of the benefits. I think we could be well served by looking at the lifecycle of [LNG] exports and what the aggregate climate impacts are,” she said.

“I don’t have the authority to make that happen,” she acknowledged. “In the meantime, I have to do my job, which is deal with the applications that are before us. I will continue to try to look at them case by case.”

McNamee, Chatterjee Respond

Chatterjee, who had made his opening remarks before his Democratic colleagues, did not address their comments in the open meeting.

McNamee, however, defended the commission’s order, insisting it “seriously addressed” the GHG emissions.

“I think it’s a disappointing thing that in this town, often if there’s a disagreement about how something should be done or what the conclusions are, that some will say that it wasn’t done, that they’re ignoring something,” he said.

“We have to look at each order separately. But we were able to show, at least here, that Washington can work,” he continued. “We compromised. We come together. We listen. We can get things done.”

Speaking to reporters after the meeting, Chatterjee said, “I actually thought that was a model for how constructive dialogue can take place in Washington, and I want to commend all three of my colleagues for their approach to this. I echo Commissioner McNamee’s sentiment: This is an example of how Washington can work.”

He said LaFleur was instrumental in brokering the compromise that led to the inclusion of the emissions figures and how they compare to total U.S. emissions.

“This was a big win for her,” he said. The language “was a change in a policy, a major change in policy. The commission had been approving projects in the past without the inclusion of this language. … Commissioner McNamee and myself had to get comfortable with what the legal implications of this change would be. …

“I was not completely comfortable with the change in our approach, and neither was Commissioner McNamee, but it was important that we negotiated in good faith with Commissioner LaFleur. And I for one view it as a significant accomplishment for her.”

Chatterjee also complimented Glick for his dissent.

“While he spoke very passionately, and we may disagree in our interpretation of what the Natural Gas Act allows, I commend him for his very strong and rigorous dissent because that’s the purpose of these multimember commissions. Strong dissents make the order stronger. In crafting the underlying order, we have to ensure we are dotting all our i’s and crossing all our t’s to account for all the arguments that he is making in his dissents.”

Litigation Risk?

LaFleur and Glick said the commission’s failure to consider GHG emissions creates a risk that its orders will be overturned on appeal. They cited the 2017 D.C. Circuit Court of Appeals order that remanded FERC’s approval of an environmental impact statement (EIS) for the Southeast Market Pipelines Project and a federal court ruling last week faulting the Bureau of Land Management’s EIS on oil and gas drilling in Wyoming.

Glick said LNG developers could take steps to mitigate their GHG emissions, citing the Freeport LNG terminal, which he said “substantially reduced their greenhouse gas emissions … by employing all-electric compression motor drives. A developer can also offset emissions with emissions-free power. This isn’t rocket science. So, before we pat ourselves on the back and give ourselves the good government award, we need first to do our job under the law, which in this case means not ignoring the impact a project will have on climate change.”

March 25, 2019

SPP on Track for WECC RC Certification

By Tom Kleckner

SPP Vice President of Operations Bruce Rew last week said that he “feels pretty confident” the RTO will meet its first major target in providing reliability coordination services to 12% of the Western Interconnection’s load.

During a Wednesday meeting of the Western Reliability Executive Committee (WREC) in Tucson, Ariz., Rew said SPP is “doing well” in preparing for the certification process, which begins with the Western Electricity Coordinating Council’s on-site certification visit Aug. 13.

Rew said staff are updating and creating new procedures to include the Western footprint. He told the WREC the procedures will not be shared with customers, but a summary of methodologies will be provided.

SPP is updating and validating its system model, using Peak Reliability’s as a benchmark. Peak has provided RC services in WECC since 2011 but it will wind down operations at the end of the year.

SPP and CAISO RC Wins Most of the West.)

SPP staff are also working with the RTO’s Congestion Management and Seams Task Force to identify a “consistent and agreed-upon” congestion management approach between SPP West transmission owners and balancing authorities. The approach includes a redispatch methodology for congestion within the SPP West RC.

SPP is scheduled to go live with its RC services Dec. 3. It announced in September it had signed RC contracts with more than a dozen Western entities.

SPP’s timeline for launching its RC services | *SPP*

The WREC met following a two-day meeting by the Western Reliability Working Group, which spent much of its time discussing SPP’s communications processes, coordination among reserve sharing groups and emergency operations preparedness.

SPP staff encouraged new members to sign up for NERC’s Grid Ex V on Nov. 13 and 14, in which the RTO will participate as a player. Staff said more than 200 employees, including senior officers, will participate in the biennial exercise, which tests response to and recovery from simulated cyber and physical attacks. GridEx IV, in 2017, had more than 6,500 participants from 450 organizations.

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, 2019

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

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.