Page 1221 – RTO Insider

July 21, 2019

MISO Mulling Next Steps on Cost Allocation Overhaul

By Amanda Durish Cook

MISO last week said it will still pursue major aspects of a cost allocation proposal that FERC rejected last month after it found that the RTO’s treatment of a new category of local economic transmission projects would have violated the principle of cost causation.

The extensive cost allocation plan would have lowered the voltage threshold for market efficiency projects (MEPs) from 345 kV to 230 kV, created two new project benefit metrics and eliminated a 20% footprint-wide postage-stamp cost allocation method for projects. It would have also provided limited exceptions to the competitive bidding process if a transmission project were needed immediately for the sake of reliability. (See MISO Allocation Plan Fails on Local Project Treatment.)

MISO says it will still seek most of those changes, staff revealed during a Wednesday conference call of the Regional Expansion Criteria and Benefits Working Group. Director of Economic and Policy Planning Jesse Moser said the RTO is still hopeful it can apply the cost allocation changes before the 2019 Transmission Expansion Plan is approved in late December.

Keep Local Economic Project?

But MISO’s proposal also sought to create a new project type — the local economic project — meant for smaller, economically driven transmission projects between 100 and 230 kV, where 100% of costs would be allocated to the local transmission pricing zone containing the line. The projects would not only have to meet a local benefit-to-cost ratio of 1.25 to 1 or greater within their pricing zones, they would also be required to show the same minimum regional 1.25-to-1 ratio required of MEPs.

FERC ultimately rejected MISO’s entire cost allocation proposal on the basis of the local economic project design. The commission said the requirement to show regional benefits only to charge project costs to local pricing zones would have violated its cost-causation principle.

MISO is currently undecided on whether to alter the local economic project criteria or abandon the proposal altogether.

The revised plan could include a “Local Economic Project 2.0,” Moser said, adding that MISO could remove the 1.25-to-1 regional benefit-to-cost ratio requirement and preserve the proposed project criteria.

“I have some reservations on even using the [local economic project] terminology because it was rejected,” Moser said.

But Clean Grid Alliance’s Natalie McIntire argued that MISO should commit to assigning costs commensurate with any regional beneficiaries, even for small transmission projects.

“We’re trying to get some direction. I don’t think we even have enough detail to call them options just yet,” Moser said. “We’re not proposing anything today.”

However, MISO is clear that it will not lower its proposed regional MEP voltage threshold from 230 kV to 100 kV, although some stakeholders on the call said the RTO should consider lowering the threshold across the board.

At any rate, staff said, FERC will address the 100-kV issue shortly in response to LS Power’s June complaint seeking to compel MISO to lower the threshold for competitively bid transmission projects to 100 kV. (See Complaint Seeks Bigger Role for Smaller MISO Projects.)

Interregional Aspect

While MISO will still seek to lower its internal MEP voltage threshold to 230 kV, it still must address a six-year-old FERC compliance directive to lower its interregional MEP voltage threshold to 100 kV.

FERC in 2013 ordered MISO and PJM to lower interregional project thresholds after Northern Indiana Public Service Co. complained about shortfalls in the RTOs’ interregional planning process.

Like the local economic project proposal, MISO had proposed that its share of interregional economic projects with voltages below 230 kV but 100 kV and above be fully allocated to the transmission pricing zones where the project is located. FERC similarly ruled out the proposal based on deviation from the cost-causation principle.

“MISO is not at a place where we have a preferred option or solution to address the interregional. We’re at the place where we have to do something for PJM lower-voltage projects, but maybe we leave SPP alone?” Moser said.

Moser said MISO could either file to lower the interregional project threshold to 100 kV on both seams or make a standalone filing to extend MEP cost allocation to lower-voltage interregional projects with PJM. He added those were merely options at this point. MISO is on a 90-day timeline to address the NIPSCO complaint order.

MISO asked stakeholders to weigh in over the next three weeks on which interregional filing path it should take.

July 21, 2019

SPP Ends 8 Days of Conservative Operations

By Tom Kleckner

DES MOINES, Iowa — SPP ended eight days of conservative operations last week, just in time to meet near-record demand in its 14-state footprint.

The RTO declared the alert, a level down from an energy emergency, on July 10, when it projected an above-normal number of primarily forced outages and a drop in wind production. Normal operations resumed on Wednesday.

SPP was already without 13 GW of non-variable resources when it declared the alert. Those outages peaked at slightly more than 14 GW on July 13, before finally falling to less than 10 GW on Thursday.

“At one point, 45% of our generation was unavailable to us through outages or derates,” Operations Vice President Bruce Rew told the Markets and Operations Policy Committee on July 16. He said outages were slightly less than 8 GW a year ago on July 13.

Rew said SPP was predicting a more normal wind production of 12 to 13 GW through the end of last week. Forecasters pretty much nailed their prediction.

“Less than 5 GW is a low wind day for us anymore,” he said.

Fortunately, the alert ended just as SPP was expecting to set new records for peak demand. Demand fell short Wednesday to Friday, though on Friday it came within 30 MW of the all-time mark of 50.6 GW, set in July 2016.

It was the sixth time the RTO has called for conservative operations this year, more than it did all last year. The first two alerts were called in February and March as a result of normal cold weather events. SPP has since issued alerts on May 29, June 4 and July 1 over what staff called “uncertainty factors.”

“What’s the weather forecast? Potential generation? Certainty of load?” Rew said. “We’re seeing outages extending a little longer than normal.”

A comparison of SPP’s July outages | *SPP*

Asked if SPP’s criteria for declaring conservative operations have changed, C.J. Brown, director of system operations, said no.

“We have gotten better at what we’re looking at from a certainty perspective,” he said.

Given the number of conservation alerts called this year, which have totaled 25 days, the MOPC asked SPP to further evaluate this year’s events and bring back a recommended policy and/or process improvement to October’s regular meeting. Members asked for more detailed information on the outages and the discrepancies between real-time operating capacity and assumed planned capacity, and to clarify the RTO’s current must-offer requirements.

July 21, 2019

MISO: Grid Can be Stable at 40% Renewables

By Amanda Durish Cook

CARMEL, Ind. — MISO’s grid can withstand major reliability risks even when renewables reach 40% of the generation mix, RTO staff said last week.

That finding represents a turnabout from a study last year that found the RTO would need to take significant steps to reinforce its grid to handle a jump from 30% to 40% renewable penetration. (See Study: MISO Grid Needs Work at 40% Renewables.) But it is now more confident about its ability to maintain reliability as renewable development intensifies.

“The challenge is a non-linear thing. There are certain points where it becomes more complex as you eat up some of the flexibility and capacity on the system. … There’s more megawatts of capacity needed on the system over time,” MISO Manager of Policy Studies Jordan Bakke said during a special workshop on the topic Wednesday.

MISO foresees continued wind growth in the northern part of its footprint, with most renewable generation in the South coming from solar. As more solar comes online, the daily peak risk hour shifts to later in the day as the sun sets, Bakke said.

“The characterization of renewable generation deployment is wind in the north and solar basically everywhere,” he said.

In a scenario in which renewables account for 40% the resource mix, MISO found they could serve 42% of peak load, 67% of shoulder or light load, and up to 81% of load when weather conditions for renewables are optimal. When renewable conditions are ideal, wind and solar generation drastically cut into the share of load served by natural gas and coal generation.

“Renewables try to replace other generation because of the economics,” MISO Senior Transmission Expansion Planning Engineer Nihal Mohan said.

Although MISO found frequency response degrades as more renewables are added, the system would remain stable at 40%, even when a hypothetical large generator of about 4,500 MW trips offline. When that happens, the system stays above the 59.5-Hz underfrequency load shedding threshold.

Bakke said MISO staff now think declining frequency response is not as serious as first suspected.

While frequency response seems to remain acceptable up to 40% renewables, staff say they’re still concerned about scenarios with combinations of high renewable output, low load and large generator disturbances.

And MISO is still concerned that reliability will suffer in other ways.

Under a 40% renewables scenario, the RTO may need to remedy low short-circuit issues with transmission lines equipped with dynamic support capabilities. It said members may be better off building HVDC lines rather than installing several synchronous condensers, then mitigating the small signal stability issues that such equipment produces.

“You can add small lines, you can add condensers, but they would probably add more stability issues,” Mohan said. “It’s probably better to think about this in advance and come up with an [all-encompassing] solution.”

“We’re able to get to a renewable energy penetration and deliver energy in a stable way” if MISO members are willing to move to new technologies, Bakke said.

MISO also found that at a higher penetration of renewables, the system would in most cases have more time to clear line faults.

Keeping with previous discussions on the renewable integration assessment, stakeholders asked how MISO envisions that electric storage resources will mitigate reliability issues.

“At this phase of study, we’re not considering storage,” Mohan said. Storage devices will make an appearance in the third phase of the ongoing study, he said.

MISO will host another workshop Sept. 13 to discuss its study results on a 50% renewable future. The final phase of the study will examine how the grid operates when locally sited renewables serve load.

July 21, 2019

NYISO Business Issues Committee Briefs: July 17, 2019

NYISO’s Business Issues Committee on Wednesday voted to approve updates that align the Transmission Expansion & Interconnection (TE&I) manual with Tariff changes made since the last comprehensive manual update, provide additional detail regarding interconnection study methodology, and clarify existing practices and procedures.

The Operations Committee reviewed and approved the revisions on Thursday.

The ISO’s senior manager for interconnection projects, Thinh Nguyen, detailed the TE&I Manual revisions and the Tariff revisions accepted by FERC over the past two years to alter the transmission expansion and interconnection procedures. Updates include:

Revisions made as part of the 2017 comprehensive queue revision, such as reducing the number of study agreements.
Creating deadlines for study reports.
Clarifying roles and responsibilities of parties in the interconnection process.
Making feasibility studies under Attachments X and Z options at the developer’s election, with two alternative levels of analyses.
Revising interconnection request data forms and requirements.
Providing parties the option to narrow the scope of studies required or uprate projects.
Allowing certain projects with multiple voltage levels to submit a single interconnection request.

The manual changes also reflect queue reforms aimed at improving the class year study process by revising start dates; creating the “bifurcated class year” process; affording additional opportunities for projects to withdraw from the class year study; and specifying how a project can finalize an interconnection agreement prior to completion of a class year study and/or request limited operations prior to execution of an interconnection agreement.

NYISO — New York Power Authority transmission lines near the Adirondack Mountains | *NYPA*

Other changes to the interconnection process reflected in the manual updates include clarification of interconnection study base case inclusion rules; updated small generating facility deposits and application fee requirements; clarification of the clustering process for small generating facilities; clarification of the process for evaluating alternative points of interconnection for small generators; and the requirement that certain large generating facilities install phasor measurement units.

The manual changes, consistent with the 2017 revision, also explain the process for calculating capacity resource interconnection service values applicable to the winter capability period and require stakeholder review of changes in transmission owner planning criteria, while also increasing the frequency of required updates to proposed in-service, initial synchronization and commercial operation dates.

External Capacity Resource Eligibility

Director of Market Design and Product Management Robert Pike presented the monthly Broader Regional Markets report and highlighted item 26, regarding an effort to clarify the minimum deliverability requirements for external capacity into the NYISO Installed Capacity (ICAP) market.

The ISO reviewed eligibility and deliverability requirements for external capacity from ISO-NE with stakeholders at the June 27 ICAP/Market Issues Working Group meeting and will return to future working group meetings to continue the discussions, he said.

NYISO will continue to evaluate what, if any, additional performance requirements and obligations are needed for deliverability to the New York Control Area border for purposes of external resource eligibility to sell capacity into New York.

LBMPs down 25% YoY in June

NYISO locational-based marginal prices averaged $24.43/MWh in June, up slightly from $23.10/MWh in May, but down about 25% from the same month a year ago, Pike said in delivering the monthly operations repo r t. Year-to-date monthly energy prices averaged $35.76/MWh, a 25% decrease from a year ago.

Day-ahead and real-time load-weighted LBMPs came in higher compared to May. Average daily sendout was 429 GWh/day in June, compared with 373 GWh/day in May and 445 GWh/day in the same month a year ago.

Transco Z6 hub natural gas prices averaged $2.10/MMBtu for the month, off slightly from May and down 14.1% from a year ago.

Distillate prices were down 13.2% year over year and lower from the previous month, with Jet Kerosene Gulf Coast averaging $13.50/MMBtu, down from $14.64/MMBtu in May, while Ultra-low Sulfur No. 2 Diesel NY Harbor dropped to $13.23/MMBtu from $14.54/MMBtu in May.

June uplift dropped to 7 cents/MWh from 13 cents/MWh in May, while total uplift costs, including the ISO’s cost of operations, came in higher than the previous month.

The ISO’s 19 cents/MWh local reliability share in June was down from 23 cents the previous month, while the statewide share dropped a penny from the previous month to -12 cents/MWh.

The Thunderstorm Alert cost for New York City was 77 cents/MWh, up from 19 cents in May.

— Michael Kuser

July 21, 2019

US House Takes on Grid Security

By Rich Heidorn Jr.

Grid modernization and security were the focus of two U.S. House of Representatives committees last week as four bipartisan bills cleared the Energy and Commerce Committee and a second panel held hearings on two other legislative proposals.

Grid Security — The House SST Committee’s Energy Subcommittee held hearings on grid modernization and cybersecurity last week.

On Wednesday, the Energy and Commerce Committee passed the following bills by voice votes, moving them to consideration by the full House:

The Enhancing Grid Security through Public-Private Partnerships Act (H.R. 359), introduced by Reps. Jerry McNerney (D-Calif.) and Bob Latta (R-Ohio), would direct the Department of Energy to encourage public-private partnerships to mitigate electric utilities’ physical and cybersecurity risks. The effort, in consultation with state regulators, industry and the Electric Reliability Organization, would promote the use of maturity models, self-assessments and auditing methods for measuring security, provide training to address supply chain risks, and encourage sharing of best practices and data collection.
The Cyber Sense Act of 2019 (H.R. 360), also introduced by Latta and McNerney, would require the secretary of energy to establish a program to identify cybersecure products for use in the bulk power system.
The Pipeline and LNG Facility Cybersecurity Preparedness Act (H.R. 370), introduced by Rep. Fred Upton (R-Mich.) — ranking member of the E&C Committee’s Energy Subcommittee — and Rep. David Loebsack (D-Iowa), would establish a program at DOE to improve the physical security, cybersecurity and resilience of natural gas transmission and distribution pipelines and LNG facilities.

The panel also approved a bill (H.R. 362) that would codify the role of Karen S. Evans, who was appointed in September as assistant secretary for DOE’s Office of Cybersecurity, Energy Security and Emergency Response.

Science, Space and Technology Committee

Evans was among the witnesses who testified Wednesday before the House Science, Space and Technology Committee’s Energy Subcommittee.

Subcommittee Chair Conor Lamb (D-Pa.) opened the hearing by touting two other pieces of legislation, the Grid Modernization Research and Development Act of 2019 — which calls for research on grid resilience, emergency response, modeling and visualization — and the Grid Cybersecurity Research and Development Act of 2019 (H.R. 4120), which would authorize a research and development program by the Department of Homeland Security, the National Institute for Standards and Technology (NIST), and the National Science Foundation to harden the grid from cyberattacks. The R&D program would include technical assistance, education and workforce programs. The bills will be introduced after the August recess.

Artificial Intelligence’s Role

Evans told the committee that DOE is seeking to spur innovation in big data and artificial intelligence, saying AI has a “critical role” in improving grid resilience. “We’re talking about … software-defined networks, autonomous solutions, really analyzing the data … to remove some of what is happening at a human level now that could be done by AI, by machine learning. That is the area that we are really exploring so that we can look at higher analysis of security, and also being able to model the resilience in real time.”

McNerney asked whether adversaries could use AI to attack the grid.

“For every great new innovation that we do … we also have to evaluate what are the potential risks associated with that and then engineer preventative solutions,” she responded. “We don’t want to stifle innovation. We want to take advantage of those things.”

Juan Torres, associate laboratory director for energy systems integration at the National Renewable Energy Laboratory, agreed.

“Just about any tool … can be used for good or for bad. That’s why it’s imperative for us to maintain that leadership in the advancements of these technologies so we are the ones using these for the right purpose and can actually deter any negative use or any attacks on these systems,” said Torres, who is also co-chair of DOE’s Grid Modernization Lab Consortium.

Torres said DOE is applying AI to four “foundational areas”: understanding complex systems theory; big data analytics; optimization to ensure distributed systems work together; and non-linear controls.

“What we’re seeing is with highly distributed systems, some of the linear control concepts that are used now on the grid may not apply in a highly decentralized type of system,” he said.

Wind, Solar Cybersecurity

Torres said DOE’s solar and wind technology offices are working with industry officials to identify the industry’s cybersecurity needs and those of distributed energy systems. DOE and the International Electrotechnical Commission on Wednesday hosted a cybersecurity workshop at the National Wind Technology Center at NREL’s Flatirons Campus in Boulder, Colo. “This event is bringing key government and industry players together for the first time to add the cybersecurity needs of the growing wind power industry,” he said.

AI would build on smart grid technologies that witness Katherine Hamilton, executive director of the Advanced Energy Management Alliance, said “have allowed the grid to operate more efficiently and with greater visibility.”

“The year of detective work necessary to determine that the Northeast blackout of 2003 was caused by a branch in Cleveland would no longer be the case thanks to these technologies,” she said.

Workforce Needs

The hearing also discussed the industry’s workforce needs. According to research funded by NIST, the U.S. has almost 716,000 people in the cybersecurity workforce and almost 314,000 job openings.

Hamilton said the workforce challenges extend beyond cybersecurity, noting that about 30% of utility employees and 40% of the industry’s engineers are millennials. “Millennials tend to change jobs faster than we’re used to in the utility workforce. You would start in the utility and retire in the utility. But people change jobs a lot faster and there are more types of jobs, so we need to find out what [kinds of] training are needed. … What are some of the skills that transfer really easily?

“In California right now, there are wildfires that are potentially going to cause public safety outages of 30 days or more … and there are not enough trained tree trimmers to do the work needed on vegetation management. You can’t send a kid out with a bushwhacker. These are really trained labor. So, there are a lot of job needs and opportunities, and there are people who don’t have jobs, and we need to somehow match those. So, bringing the public sector and the private sector together on that seems to me to be a good way to think about that.”

Hamilton said encouraging interest in STEM education and cybersecurity needs to begin in elementary school.

Kelly Speakes-Backman, Energy Storage Association

Witness Kelly Speakes-Backman, CEO of the Energy Storage Association, said she was glad her twin 15-year-old daughters were in the audience hearing the discussion. “Their high school has a program that is partnered with the U.S. Naval Academy specifically on cybersecurity, and I really want them to take it,” she said.

Torres said that in addition to sparking early interest in the STEM fields, industry and government should encourage mentoring to ensure a pipeline of future teachers and professors.

Hamilton said DOE and its National Labs also should be involved in encouraging what she called the “democratization” of innovation.

“Innovations are not limited to our labs, our universities or our utilities. They are everywhere. They are kids in basements playing with their apps,” she said. “So, trying to make sure that our research programs are able to connect the dots so that we can bring entrepreneurs to test and make sure that we have proof of concept [is important]. Because no utility is going to purchase a piece of equipment that was designed in somebody’s basement. They need to know that the Department of Energy and the National Labs have given it the seal of approval … by testing it and making sure that this all works.

“While part of that is about bringing new people into the industry — because there are so many new excited young people coming in — we also need to make sure that we then connect them to the programs that are existing to enrich the programs too,” she said.

A House subcommittee meeting last week heard testimony from (from left) Karen S. Evans, DOE; Juan Torres, National Renewable Energy Laboratory; Kelly Speakes-Backman, Energy Storage Association; and Katherine Hamilton, Advanced Energy Management Alliance.

Measuring Cost-effectiveness

Speakes-Backman, a former member of the Maryland Public Service Commission, had a different ask of DOE, saying it should help states develop ways to measure the cost-effectiveness of resilience measures. “This is an issue that I personally had after the derecho in 2011. Utilities can invest in reliability and there are metrics for that, but they cannot invest in resilience because there aren’t metrics for that to prove cost-effectiveness.”

July 21, 2019

SPP Western Reliability Briefs: July 16-17, 2019

SPP’s Western Reliability Working Group last week approved several governing documents as it continues its preparation for its new reliability coordinator function in the Western Interconnection.

Approved during a two-day meeting July 16-17 were the:

Communication Protocol for the West, which governs emergency and nonemergency situations where operating instructions are issued or received by an SPP operator. SPP’s Margaret Quispe said it is “very similar to what we’ve used” in the Eastern Interconnection under reliability standard COM-002-4.
Modification Oversight Process for the Western Interconnection, which was recommended for approval by the Western Reliability Executive Committee (WREC). Senior Interregional Coordinator Clint Savoy said the document was changed somewhat since the group discussed it in May based on feedback from the Executive Committee. The WREC delayed action on the document on Wednesday, saying it supported the edits but wanted to see a clean version before approving.
RC Restoration Plan. Senior Operations Engineer Neil Robertson said the document included “minor modifications” made since the committee’s last meeting. “In the process of preparing for our certification visit [by the Western Electricity Coordinating Council], SPP’s compliance group suggested we explain … how this document is distributed to [comply] with the EOP-006 standard,” he explained.
Congestion Management Methodology, which will set the RC’s procedures for mitigating system operating limit and interconnection reliability operating limit exceedances in real-time operations for both pre- and post-contingency conditions. “[We are] of the opinion that a consistent … methodology that everybody agrees on would help us do our job as the RC in a much more streamlined way,” explained SPP’s Yasser Bahbaz, a senior engineer. “When we assign any relief allocation to any of you guys, you know what the expectations are. The approach and the methodology has been documented, and there’s hopefully not a lot of back and forth in real time on who should give what relief.” The methodology was recommended for approval by the Congestion Management and Seams Task Force last month, he added.
Data disturbance document, documenting the process by which SPP identifies bulk electric system elements for which dynamic disturbance reporting data is required under PRC-OO2-2.

Tennille Tims, an SPP project manager, provided an update on the RTO’s progress in onboarding its RC customers, saying Inter-Control Center Communications Protocol (ICCP) connectivity was complete for 12 of the 13 customers.

WECC Update

The working group also heard an update from Steve Ashbaker, WECC’s reliability initiatives director, who said the regional entity was continuing to prepare for Phase 2 of CAISO’s expanded RC West footprint.

CAISO completed Phase 1 on July 1, when it became RC for 16 balancing authorities and transmission operators in California and Mexico. Phase 2 will expand the ISO’s footprint to 23 other entities in the Western Interconnection.

WECC will be conducting site visits in CAISO’s Folsom and Lincoln, Calif., offices July 30 through Aug. 1.

“The RC West Phase 1 transition went very smooth. Things continue to seem to be working very well, at least what we’re hearing and what we’re seeing,” Ashbaker said. “They’ve been fortunate in their shadow operations and in their real-time operations. They’ve seen quite a bit go on with … the energy emergency alerts, some earthquake activity —fortunately that didn’t cause a whole lot of chaos on the power system.”

WECC has a site visit planned with SPP in August.

Ashbaker said the Western Area Power Administration has agreed to take possession of 18 months of historical synchrophasor data from Peak Reliability. Ashbaker said WECC had considered taking the data although it lacks the hardware or software to read them. “We just didn’t want that data to be lost. But WAPA has stepped up … and said they said they would be willing to take that on,” he said.

WREC Update

During a brief WREC meeting Wednesday, staff said SPP and CAISO have entered an RC-to-RC agreement, the first business arrangement between the two. SPP is still working with CAISO to gain necessary data for its Western operations.

“It’s taken longer than expected,” SPP Director of System Operations C.J. Brown said. The RTO has since decided its best approach is to go to Peak Reliability to secure the data, he said.

The RC-to-RC agreement was executed last week.

— Rich Heidorn Jr. and Tom Kleckner

July 19, 2019

FERC Heaps Praise on Departing LaFleur

By Michael Brooks

WASHINGTON — Current and former colleagues gathered at FERC headquarters Thursday to praise departing Commissioner Cheryl LaFleur.

As the commission does not hold open meetings in August, Thursday marked LaFleur’s last as a sitting commissioner before her term ends Aug. 31. When it does, she will have served 3,336 days, according to Chairman Neil Chatterjee, making her the second-longest serving commissioner in the agency’s history (519 days short of William L. Massey, who served from 1993 to 2003).

“Rare are those who … through grace, logic and verve make a genuine difference,” said former Commissioner Marc Spitzer, one of 12 she served with during her tenure. “That’s Cheryl LaFleur.”

She was also the longest serving chairman, with 704 days at the helm, Chatterjee said, including two stints as acting chair. During the meeting, LaFleur stacked her three nameplates — chairman, acting chairman and commissioner — in front of her.

Chatterjee presents LaFleur with a farewell gift. | *Federal Energy Regulatory Commission*

LaFleur arrived first among her colleagues to the hearing room, where a packed audience with few open seats awaited her. The meeting began slightly late; it was only until Chatterjee walked in with Commissioners Richard Glick and Bernard McNamee right behind him that it became apparent why. Each wore a Boston sports jersey in imitation of LaFleur’s tradition of supporting her teams during playoff runs: Patriots for Chatterjee, Red Sox for Glick and Celtics for McNamee.

After the meeting’s official proceedings, Chatterjee brought forward Spitzer; former Montana Public Service Commission Chairman Travis Kavulla; Jamie Simler, former director of the commission’s Office of Energy Market Regulation; and LaFleur legal adviser Steven Wellner. Along with her current colleagues, they all praised LaFleur as wise, gracious and having a good sense of humor.

“She’s one of the funniest people I’ve ever met and always has a story or analogy for pretty much any occasion,” Wellner said.

Simler choked up as she spoke about how supportive LaFleur is of her staff, especially during the quorum-less period in the early days of the Trump administration, in which she was eventually the only commissioner at the agency. (See LaFleur Recounts Turbulent Tenure at FERC.) “No matter what your title was, we had the security of knowing that you cared … about the agency, the staff, the decisions and getting things right, or as close to right as possible.”

Chatterjee also praised her for leadership during the period. After serving as chair, “I now have a greater appreciation for how difficult a period that must have been, not just because of the stress of the backlog that was accruing, but just maintaining morale among our wonderful staff,” he said.

“You’re the embodiment of what it means to be not only a good regulator, but a good person,” McNamee said. “Washington will be something less because you’re not a part of it.”

LaFleur thanked all her current and former staff members, many of whom were in the audience, and called her time at FERC “the most rewarding professional experience of my life.”

Chatterjee handed her the gavel to close out the meeting one last time.

July 19, 2019

MISO Looks to Prune Competitive Tx Process

By Amanda Durish Cook

MISO is wagering that proposed rule changes will cut down on the time and expenses spent evaluating transmission proposals and position it to assess multiple competitive projects in a single Transmission Expansion Plan (MTEP) cycle.

The RTO said Thursday that it will soon file with FERC to outline increased data requirements, page limits and tighter deadlines in its competitive developer selection process.

Stakeholders have repeatedly asked MISO to make the improvements.

MISO Senior Manager of Competitive Transmission Administration Brian Pedersen said the length of proposals grew sharply between the solicitation for the Duff-Coleman project — the RTO’s first competitive project — and the currently embattled Hartburg-Sabine project. (See Uncertainty Deepens for Hartburg -Sabine Project.) Developers vying for Duff-Coleman in 2016 on average attached about 85 files to their proposals, but the file attachments had grown to about 150 per proposal by the 2018 Hartburg-Sabine solicitation.

“We have good developers and they submit full proposals,” MISO design engineer Alex Monn said during a July 18 workshop on the competitive transmission process.

But the proposals might have been a bit too fleshed-out for planners, prompting MISO to propose setting a 125- to 300-page limit, depending on the size and complexity of the transmission project being bid on.

The RTO also wants to “right size” its evaluation time based on size and complexity and is proposing to spend no more than 240, 375 or 480 days on one developer selection. It said the three proposal windows will “match the right level of proposal preparation and evaluation resources to each project.” Pedersen said the idea is to trim timelines and evaluation efforts on smaller, more straightforward projects.

MISO’s Tariff currently allows a maximum 480 days to execute the developer selection process from MTEP approval to an executed selected developer agreement. The Duff-Coleman selection took nearly all that time, while Hartburg-Sabine took less than a year.

The RTO also said it will change rules so it can accept a smaller project evaluation deposit for simpler projects that won’t require as much review. The current deposit requirement is $100,000 per proposal. Accordingly, MISO is proposing to scale down its proposal submission windows to either 60, 120 or 165 days, also depending on project intricacy.

Multiple stakeholders said a 60-day window would not be enough time to put together project proposals.

“Sixty days is just not enough time. … I feel like 90 days would be the minimum,” Entergy’s Yarrow Etheredge said.

Pedersen said he would re-examine the smallest proposal window with his staff to make sure it’s a sufficient amount of time.

“Matching our level of effort with your level of effort is a good thing,” Pedersen said. “Just like you’re on the clock, we’re on the clock when the proposals come in.”

MISO is also adding requirements to ensure the information received from developers is more valuable in aiding selection. It would specifically ask for recent project success stories, more project cost breakdowns and calculations to support design decisions along with three years of financial data and company credit ratings.

Pedersen said MISO will still move ahead with improving the competitive bidding process despite FERC’s rejection of its proposed cost allocation for competitive projects last month. (See MISO Allocation Plan Fails on Local Project Treatment.)

“There is a future out there and we still need to plan. It’s better to be ready when it happens,” he said.

MISO plans to file the competitive process changes with FERC in mid-September, with a goal to enact the rules by December. The RTO will not have a competitive project process in 2019.

July 19, 2019

Ohio Senate Clears Nuke Subsidy Bill

By Christen Smith

The Ohio Senate on Wednesday cleared a controversial plan to curb state renewable energy mandates and create subsidies for nuclear and coal plants, but the House of Representatives’ stamp of approval is still likely two weeks away.

Nineteen senators — 17 Republicans and two Democrats — approved House Bill 6 after months of hearings that debated the merits of saving FirstEnergy Solutions’ nuclear reactors at the Davis-Besse and Perry facilities near Lake Erie. The bankrupt company said it will begin shutting down the plants over the next few years without ratepayer subsidies to offset the flood of cheap natural gas that makes it difficult to compete in the wholesale energy market. (See FirstEnergy Extends the Clock on Ohio Nuke Plan.)

Two Ohio Valley Electric Corp. coal plants would also receive funding, which some critics have described as a sweetener to attract support from the state’s other electric distribution utilities (EDUs). (See Ohio Nuke Bill: A Worthwhile Trade-off?)

The latest iteration that moved out of the Senate Energy and Public Utilities Committee earlier this week would collect $150 million for the plants starting in 2021 via ratepayer fees that range from 85 cents for residential customers up to $2,400 for large industrial plants. The charge would sunset in 2027 and the Public Utilities Commission would audit the nuclear facilities each year between 2022 and 2026 to determine if the subsidies are still needed — an attempt to placate critics who insist the plants aren’t losing money at all.

Another $20 million would support six solar power projects being built throughout the state. The OVEC fees would range from $1.50 for residential customers to $1,500 for commercial and industrial customers, and would be subject to OVEC revocation.

The bill also preserves a scaled-back renewable portfolio standard, dropping from 12.5% by 2027 to 8.5% until 2025, with no continuation of the mandate thereafter.

The House didn’t vote on the plan but returns to session Aug. 1. Speaker Larry Householder (R) has reportedly worked behind the scenes to secure bipartisan support in his chamber by pushing the fees for OVEC and slashing RPS mandates long unpopular among state Republicans.

“This will give Ohio an energy plan that puts Ohioans first,” he said when the plan cleared the House Energy and Natural Resources Committee in May. “We’re keeping good-paying jobs here in Ohio and maintaining a diverse energy portfolio.”

Although the current version of HB 6 — Ohio’s Clean Air Act — walks back some of the House-approved components, critics insist the bill remains deeply flawed and misguided. The Sierra Club said it would wreck the state’s potential to become a leader in wind and solar development all for the sake of a “regressive” and burdensome surcharge that would disproportionately hurt small businesses.

The Ohio Consumers Council and the Ohio Manufacturers’ Association sent a joint resolution to Gov. Mike DeWine on Wednesday urging him to veto the bill, saying it will thwart the benefits customers receive from competitive energy markets. A spokesperson for the governor did not return request for comment, but DeWine has signaled support for the bill in the past few months.

FirstEnergy did not respond to requests for comment from RTO Insider on Thursday. The company extended the June 30 deadline for legislative action, remaining “optimistic” that lawmakers would approve the bill in the coming weeks.

July 19, 2019

FERC Orders Cold Weather Reliability Standard

By Rich Heidorn Jr.

FERC on Thursday called for reliability rules requiring generator owners and operators to winterize their units and provide their reliability coordinators (RCs) and balancing authorities (BAs) with information about their preparations.

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

“Today’s report finds that, despite prior guidance from FERC and NERC, cold weather events continue to result in unplanned outages that imperil reliable system operations,” the regulators said in a press release. Although the system remained stable, “continued reliable operation would have required shedding firm load if MISO had experienced its largest single generation contingency in MISO South.”

They said the need for a new reliability standard to improve generator performance was demonstrated by the 2018 incident as well as the large-scale unplanned outages during the 2014 polar vortex and the 2011 Southwest cold weather event.

“Learning from near-miss events is extremely important,” Chairman Neil Chatterjee said in announcing the report at Thursday’s open meeting.

The report said the 2018 incident resulted from both gas supply shortages and a failure to properly winterize generation facilities. It made 13 recommendations, calling for improvements in generator performance, load forecasts, communication and planning.

9 States Affected

The event affected all or parts of nine states, including MISO South (Arkansas, eastern Texas, Louisiana and Mississippi); southeastern SPP (lower Kansas-Missouri border, the eastern half of Oklahoma, Arkansas, eastern Texas and Louisiana); the western portion of the Tennessee Valley Authority (western Tennessee, lower Missouri, northeastern Oklahoma, northern Mississippi and Alabama) and the western portion of the Southeastern Reliability Coordinator (SeRC)/Southern Co. footprint (southern Mississippi and Alabama).

MISO did not expect to have a problem meeting its South load on Jan. 17, based on anticipated generator availability and precautionary measures it took to increase projected reserves. But conditions worsened because of the “extraordinary” level of generation outages and derates.

The report found 183 generating units in the RC footprints of SPP, MISO, TVA and SeRC suffered an outage, derate or failure to start between Monday, Jan. 15, and Thursday, Jan. 19.

Reliability — Generation outages and derates by RC footprint beginning Jan. 17, 2018 | *FERC*

Including generation already derated or on planned or unplanned outages before Jan. 15, the four RCs had more than 30,000 MW of generation unavailable in the South-Central portions of their footprints by the Jan. 17 morning peak.

MISO South had as much as 17,000 MW of generation unavailable — all but 4,000 MW unplanned — including 57% of generation in Louisiana and 23.5% of that in Arkansas.

“Had MISO’s next single contingency generation outage in MISO South of 1,163 MW occurred, continued reliable [bulk electric system] operations would have depended on system operators shedding firm load promptly to prevent further degradation of BES conditions,” the report said.

Weather Impact

Generator owners and operators (GOs and GOPs) directly blamed 14% of the generator failures between Jan. 15 and 19 on the cold weather, citing frozen sensing lines, frozen equipment, frozen water lines, frozen valves, blade icing and low-temperature cutoff limits.

An additional 30% were indirectly linked to the weather, including fuel curtailments to gas-fired generators (16%) and mechanical causes related to cold weather (14%), such as freezing of gas purge valve and steam turbine intercept valves, drops in oil pressure, wet or frozen coal and the loss of feedwater.

The report recommended GOs and GOPs implement freeze protection measures, such as installing wind breaks on generating units and conducting regular maintenance, and inspection of other protections, such as heat tracing equipment and thermal insulation.

The investigators noted about 70% of the unplanned outages occurred in gas-fired units. They recommended requiring gas generators to inform their RCs and BAs whether they have firm gas supplies.

Ambient Temperature Ratings

The report also recommended better information sharing on the impact of ambient temperatures on generators and transmission lines.

It said GOs and GOPs should ensure the accuracy of generating units’ ambient temperature design specifications and share them with RCs and BAs.

All four of the RCs experienced transmission constraints, and MISO declared an energy emergency because it lacked enough reserves to balance generation and load in South. But the researchers said some system operating limits that became constraints were based on summer temperatures or static, year-round ratings, which understated the lines’ winter capabilities.

The report said SOLs and their associated equipment ratings should be based on “at a minimum, ambient temperature conditions that would be expected during high summer load and high winter load conditions, respectively.”

Power Transfers

The report also noted that increased electricity demand resulted in large power transfers, with MISO and SPP dispatching remote wind generation and SPP importing power over its HVDC ties with ERCOT. In addition, MISO’s regional directional transfer (RDT) from Midwest to South exceeded its contractual firm and non-firm limit of 3,000 MW, peaking at 4,331 MW about 6:30 a.m. CT.

“Although MISO exceeded the RDTL, and did not reduce the RDT below the 3,000-MW limit within 30 minutes as contemplated by the settlement agreement [with SPP and neighboring RCs], MISO operators communicated with adjacent RCs … that MISO would be exceeding the limit, and that if MISO’s RDT flows caused a system emergency for the adjacent RCs, MISO would take appropriate actions,” the report said.

The report also called for improvements to the joint Regional Transfer Operations Procedure that governs MISO’s use of the RDT. The recommendations included changes to clarify roles and timing and a requirement that affected entities declare an emergency before MISO sheds firm load to reduce the RDT.

The report also recommended that RCs consider the deliverability of reserves, noting that the constraints “caused reserves to be stranded from MISO South.”

It also said MISO should notify the other RCs when it is counting on the as-available, non-firm portion of the RDT to deliver reserves for MISO South.

Inaccurate Load Forecasts

The investigators gave good marks to the RCs’ system operators, saying their actions were “effective and timely.” But they said they were hampered by inaccurate load forecasts for MISO South. MISO’s five-day forecast for Jan. 17 underestimated load by about 6,000 MW (18.9%), and its three-day forecast was 1,900 MW low (6.1%). The report said MISO should work with its local BAs and adjacent RCs to improve its accuracy.

“While MISO and its neighbors worked together to maintain system reliability during the event, we recognize the opportunity to collaborate on changes that improve coordination during extreme events,” MISO spokeswoman Julie Munsell said Thursday. “We look forward to reviewing the findings and recommendations in the final report.”

Studies and Drills

Several of the recommendations concerned additional studies.

The report recommends studies that consider “stressed but realistic conditions,” noting that none of the RCs had anticipated the widespread transmission constraints on Jan. 17.

MISO and SPP should “jointly perform seasonal transfer studies and sensitivity analyses in which MISO and SPP model same-direction simultaneous transfers (e.g. north to south, south to north, west to east) to determine constrained facilities so that they can develop mitigation plans or other procedures for the operators,” it said.

It also said planning coordinators and transmission planners should jointly develop and study scenarios to prepare them for extreme weather. It said the studies should include removing generation units entirely to represent actual generation outages as opposed to scaling generating unit outputs.

The study team also recommended that MISO and other RCs perform:

Voltage stability analyses in future constrained conditions and benchmark planning and operations models against actual events that stressed the system;
Periodic impact studies to identify which elements in the adjacent RCs’ systems have the most impact on their own systems; and
Drills to “execute load-shedding for maintaining reserves while at the same time alleviating severe transmission conditions.”