Page 1043 – RTO Insider

September 25, 2020

MISO Moves to Constrain Mid-queue Fuel Changes

MISO is considering how to restrict generation developers’ ability to change the fuel type of proposed projects in the interconnection queue.

The move comes after a recent FERC order exposed the RTO’s lack of protection against switching fuel sources for projects in the queue’s definitive planning phase (DPP).

Ryan Westphal, manager of probabilistic resource studies, said MISO has concerns that allowing DPP fuel-type changes could delay studies and “create gaming opportunities.”

“It just essentially encourages the submission of premature and speculative projects,” he told stakeholders during a Interconnection Process Working Group teleconference Tuesday.

The issue stems from a Leeward Renewable Energy Development wind project currently in the DPP. The developer wants to convert the project to solar energy while also retaining its position in the queue.

FERC last week said that MISO’s Tariff was silent on whether a generation project can switch from wind to solar while in the interconnection queue. The commission also said that there was no requirement in Order 845 that requires grid operators to study projects that opt to switch fuel types. (See FERC: No MISO Rules on Mid-queue Fuel Change Studies.)

MISO Mid-queue Fuel Changes — Rooftop solar in Indianapolis | © *RTO Insider*

Westphal said MISO is evaluating how fuel changes fit into the Tariff’s permissible technological advancements.

“Unstructured submission of multiple fuel-change requests during a single queue cycle creates cost and timing risks that may not be obvious from evaluating individual requests in the abstract,” he said, adding that the accumulation of several fuel-type requests could seriously alter a queue cycle.

A fuel-type change can also alter dispatch assumptions, throw off site control requirements and affect system studies coordination with other RTOs, Westphal continued. Staff are seeking a standardized method to handle fuel-type changes that keeps the queue on time, he said. MISO is already contending with a record queue of 719 projects, totaling 108 GW of capacity.

“If we have to evaluate these on an ad hoc basis, then it’s kind of a queue-within-a-queue,” Westphal said. Instead, the grid operator is considering making a new filing with FERC to explicitly disallow fuel-type changes, among other options.

Otherwise, Westphal said MISO could introduce a “check box” on interconnection requests where a customer could preserve its option to switch fuel types. The uncertainty would have staff studying the interconnection request at 100% dispatch of the most conservative fuel type until the customer can confirm its fuel type, probably at the queue’s first decision point.

“If we’re going to do this — allow this — then the decision point seems like a good place to start,” Westphal said. MISO could go a step further and study all interconnection requests at a 100% output, but he said that could result in unnecessary network upgrades.

Multiple stakeholders said studying all queue customers’ projects at full output would be too detrimental to project costs and would be a nonstarter.

Westphal said MISO could simply require customers to nominate fuel type at a fixed point, “before we get too far in the process.”

“The question was, ‘Could we allow a fuel-type change before a kickoff meeting?’ And the answer was ‘yes,’” Westphal said. “We’re asking about other points too. When can we allow a fuel-type change and disrupt the process as little as possible?”

EDF Renewables’ Arash Ghodsian said a deadline prior to DPP kickoff made the most sense.

“I think that a fuel-type change is tremendously disruptive to the DPP process and it affects other interconnection customers,” WEC Energy Group’s Chris Plante said. “Maybe it shouldn’t be allowed.” He asked whether there are other customers like Leeward seeking to change fuel sources on existing project proposals.

“We’ve gotten several customers asking how to do this,” Westphal confirmed.

He asked that stakeholders submit more written opinions on fuel-type changes by Oct. 2. He expects MISO and stakeholders to work on a solution through early 2021.

September 25, 2020January 15, 2025

SPP Board of Directors/MC Briefs: Sept. 22, 2020

SPP’s Board of Directors and Members Committee met virtually Tuesday outside of their normal quarterly schedule to consider a number of pressing issues and learn more about the planned joint transmission study with MISO.

Unfortunately, as happens during the new normal, technology got in the way.

MISO CEO John Bear was among those calling in to the meeting, returning the favor after his SPP counterpart, Barbara Sugg, attended his Board of Directors’ webinar on Sept. 17. (See “Teamwork with SPP,” MISO Readying Intensive Transmission Planning.)

“Happy to be here,” Bear said after Chair Larry Altenbaumer, waiting on a quorum, noted his presence.

Altenbaumer and Sugg both praised Bear in introducing him when it came time to discuss the RTOs’ study. The grid operators said earlier this month they will collaborate on a yearlong transmission study designed to identify projects with comprehensive, cost-effective and efficient upgrades as they look for solutions to “historical challenges” facing their generator interconnection customers along their seams. (See MISO, SPP to Conduct Targeted Transmission Study.)

SPP’s board last year set an objective to improve the relationship with MISO, Altenbaumer said. The appointments in January of Sugg as CEO and Lanny Nickell as COO have given SPP a “fresh start” with its neighbor, he said. The détente with MISO comes after a merger attempt in the early 2000s ended in acrimony.

“John’s leadership has been front and center on this collaborative approach we’ve seen over the last few months” between SPP and MISO, Altenbaumer said. “We have far more success where we share common interests and challenges. Hopefully, the joint study will be an example of that.”

“He’s never hesitated to take a call from me, and he’s been very, very open with sharing information,” Sugg said. “He’s been very responsive to my inquisition of things and how to improve operations and coordination between the two organizations.”

But when it came time for Bear to speak, his words went unheard. After an uncomfortable silence, Sugg spoke for him.

“I know John is excited, and I know John would say the same things I’ve said,” she said. Spying Bear on one of the webinar’s video windows, Sugg said, “He’s giving a thumbs-up.”

Bear later sent an email to Sugg, who shared it with those still involved in the meeting. Bear, she said, thanked SPP and its members for their help as MISO “navigated” two hurricanes and a tropical storm this year.

“He’s looking forward to working with you on seams projects that bring value to all of our members,” Sugg said.

Technology was otherwise effective during the meeting. SPP changed its meeting registration practices to reduce the number of “nefarious” callers who have been bedeviling the RTO’s meetings in recent weeks. IT Vice President Sam Ellis said “anywhere from a few dozen to a few 100 people have been infiltrating the [webinars] and flooding the channels with weird audio.

“We’re not sure if they’re trying to be disruptive, but we’re hopeful this meeting goes smoothly because of the changes we made,” Ellis said.

ERCOT encountered similar disruptions in late August and early September but has since resolved the problem.

SCRIPT to Address Transmission Planning

The board formally approved the Strategic & Creative Re-Engineering of Integrated Planning Team (SCRIPT), a 15-person group comprising directors, members and state regulators tasked by the Strategic Planning Committee to evaluate SPP’s transmission planning and applicable cost-allocation processes. (See “SPC Takes Look at Tx Planning,” SPP Briefs: Week of Aug. 31, 2020.)

The RTO has seven different transmission planning processes that use various cost-allocation structures for transmission upgrades. The SCRIPT will evaluate options to strategically re-engineer those processes and write a final report with high-level recommendations for the board and Members Committee. The report will be conducted separately from the joint study with MISO.

“This will help us strategically address the growing number of transmission requests we are facing and have been dealing with for a number of years,” Nickell said. “I don’t want to say the planning process is broken or staff isn’t doing a good job. They’re doing a tremendous job performing the processes that are required of us in our Tariff, but the challenges facing us are ripe for a tremendous opportunity to re-engineer them going forward.”

SPP’s generator interconnection queue currently contains more than 75 GW of wind, nearly 38 GW of solar and almost 9 GW of battery storage, all under some form of study. The grid operator says expected generation growth will likely create financial pressures on older conventional generation, leading to increased future retirements.

The “unprecedented” amount of generation and SPP’s “very iterative” interconnection process has “significantly” delayed processing the queue, Nickell said.

“The outrageously high volumes of [generator interconnection] requests has created stress on our staff and customers, given it takes four to five years [to process studies] and the uncertainty over costs,” he said. “As customers drop out, we have to restudy, and as they drop out, the cost allocation changes. We have a tremendous opportunity to export energy, but without enough transmission capacity and the incentive to do so, we haven’t been capitalizing on this as well as we could.”

John Stephens, with the city of Springfield, Mo., pointed out that the Holistic Integrated Tariff Team’s (HITT) recommendations haven’t yet been acted upon and said he was concerned about overlap. Five of the HITT’s recommendations were related to planning processes.

“There’s been discussion in the membership that instead of doing everything at the same time, let’s wait and see the effect of those [recommendations] on these processes,” Stephens said.

“There is some of this effort that we will need to consider and be aware of as [the HITT recommendations] move forward,” Nickell said. “I do believe those won’t have any impact on this bigger, more holistic, strategic effort. We need to develop policies and propose policies that result in the consolidation of the [planning] process.”

Board Lifts Suspension on Competitive Upgrade

SPP’s second competitive project took another step toward reality when the board approved staff’s recommendation to lift the suspension of the 345-kV Wolf Creek-Blackberry project and authorized the Oversight Committee to create an industry expert panel (IEP) to evaluate responses to a request for proposals.

The competitive upgrade, SPP’s first with a nonmember, Associated Electric Cooperative Inc. (AECI), was approved last year. The board in April suspended the project while staff worked with AECI to complete a cost-and-use agreement. That agreement has since been filed with FERC, where it received no protests during the required 20-day period. (See “Directors Suspend Competitive Upgrade,” SPP Board/Members Committee Briefs: A p ril 28, 2020.)

Lifting the suspension means the project is once again considered approved for construction. Staff have seven days following the board’s approval to issue an RFP.

The project involves a 105-mile transmission line from Kansas into Missouri and is estimated to cost $152 million. Part of the project is on the AECI system and will be constructed by the cooperative. SPP needs FERC approval to allocate funds to AECI.

Oklahoma Gas & Electric’s Greg McAuley abstained from the Members Committee vote. He noted the utility is protesting several generator interconnection agreements at FERC related to a separate Wolf Creek project that has been canceled.

“We have a fundamental disagreement with staff over how that occurred. We think it was done contrary to the Tariff,” McAuley said. “We’ve elected not to protest [Wolf Creek-Blackberry] at FERC because we recognize there are reliability issues that need to be resolved that way, even though we think there are better and more economical options than this.”

SPP’s first competitive project under FERC Order 1000, awarded to Mid-Kansas Electric in 2016, was subsequently canceled because load projections dropped over time. (See SPP Cancels First Competitive Tx Project, Citing Falling Demand Projections.)

A third competitive project has already been evaluated by an IEP and will be brought before the board for its consideration in October.

WEIS Tariff to be Refiled with FERC

Bruce Rew, SPP’s vice president of operations, said the RTO plans to refile with FERC its Western Energy Imbalance Service (WEIS) tariff and other related documents by the end of the month. The WEIS remains on track to go live on Feb. 1, he said.

The commission rejected SPP’s first attempt to secure approval for the WEIS in July. FERC said the RTO failed to respect nonparticipants’ transmission rights and could improperly burden reliability coordinators. It also cited shortcomings on supply adequacy, market power protections and line-loss calculations (ER20-1059 , ER20-1060). (See FERC Rejects SPP’s WEIS Tariff.)

“FERC did recognize the benefits of the WEIS market and what it could bring to the region,” Rew said.

WEIS stakeholder groups met several times before approving in early September the last of four revision requests addressing FERC’s concerns. (See SPP Expands its Western RC Footprint.) The board approved those changes Tuesday, allowing SPP to refile the Tariff.

Rew said a couple concerns outside the Tariff’s scope remain to be resolved — congestion management in the WECC region and the Northwest Power Pool’s reserve-sharing program — but that SPP is committed to working with those entities.

Of more concern to SPP is its Market Monitoring Unit’s recent determination of “significant structural market power concerns” for WEIS energy and imbalance energy that should be addressed before the market’s implementation. The MMU recommended SPP and market participants consider developing a systemwide mitigation measure and using cost-based offers if the mitigation measures cannot be implemented before the market goes live.

Rew said SPP is developing language to address those concerns and ensure pivotal suppliers don’t have excess market power.

“The ISO-NE market had a similar issue,” he said. “We’re modeling our approach to market power mitigation after theirs.”

Revisions to Rate Schedules

The board approved revisions to the cost-recovery mechanism from market participants who use and benefit from SPP’s services as the RTO prepares to move to an unbundled rate schedule in 2021.

The revision request (RR413) clarifies the formula rate template to include the net financial impact of contracts in its overhead calculation and to include a prior period’s over- or under-recovery in the rates’ calculation for rate-cap purposes.

The board last year approved subdividing SPP’s Schedule 1-A into four rate schedules, including a mix of demand and energy charges. Current 1-A charges for transmission service will become Schedule 1-A1 charges, and three market-related charges would be recovered through three energy charges. (See “Board Approves Modernized Cost-recovery Structure,” SPP Board of Directors/Members Committee Briefs: Jan. 29, 2019.)

September 25, 2020

MISO Planning Advisory Comm. Briefs: Sept. 23, 2020

MISO members have recommended that the RTO’s 2020 Transmission Expansion Plan (MTEP 20) proceed to final approval in December.

Without discussion, eight of MISO’s 10 sectors with voting rights approved MTEP 20, comprising 514 new projects costing $4.06 billion, during the Planning Advisory Committee teleconference Wednesday. The portfolio investment level is similar to MTEP 19’s.

The State Regulatory Authorities and Eligible End-User Customers sectors both abstained from voting.

MTEP 20 is now before the Board of Directors’ System Planning Committee for consideration and an October vote. The PAC’s recommendation vote came about a month early this year, as MISO wanted to give the board more time to review the plan. The board has approved about $36 billion in annual transmission buildout since 2003.

The RTO’s executive director of system planning, Aubrey Johnson, said earlier this year that “a preponderance” of projects is in the Central planning region. Most of those are baseline reliability projects: transmission upgrades necessary to meet NERC standards.

Coordinated Planning Effort Continues

Some stakeholders continue to be dissatisfied with MISO’s first suggestion to coordinate its interconnection upgrade studies and planning studies under MTEP.

The RTO and stakeholders have been working on coordination in the hopes of approving more multifunctional transmission projects. (See MISO Processing Heftiest Interconnection Queue Ever.)

Staff have offered to perform an economic evaluation of certain generator interconnection upgrades that show promise. That offer is only open to the network upgrades of generation projects that already have a signed generator interconnection agreement in place. (See MISO Unveils 1st Proposal to Consolidate Tx Planning.)

The grid operator this week also suggested that interconnection upgrades pass screening criteria before they can be evaluated as possible market efficiency projects. The criteria include a $50,000 to $100,000/MW cost minimum on network upgrades and exclude line rebuilds and interconnection substation work.

Some stakeholders say the proposal is not enough to prevent generation projects from dropping out of the interconnection queue when they balk at high upgrade costs. Many stakeholders said waiting for an economic evaluation after a GIA is signed wastes time.

“It’s challenging from a commitment timeline to wait until that moment,” EDF Renewables’ Arash Ghodsian said.

The Sustainable FERC Project’s Lauren Azar asked that MISO keep a reasonable per-megawatt cost threshold so that generation developers aren’t dissuaded from GIAs by high costs. She also reminded stakeholders that an interconnection upgrade being cleared for MISO economic analysis isn’t a guarantee that it will proceed to regional cost sharing.

Other stakeholders said MISO shouldn’t be so quick to exclude line rebuilds, because a project could only slightly overload the original line. That would leave a lot of headroom for other flows on rebuilt lines.

Clean Grid Alliance’s Natalie McIntire also urged the grid operator to think about network upgrades that may negate the need for future reliability projects.

MISO has framed its proposal as a first step in better linking transmission upgrades unearthed in the interconnection queue with annual transmission planning.

“The fact of the matter is that these processes have been in place for a number of years. We can’t change them overnight; there are too many moving parts and complications,” MISO’s Neil Shah said.

“I agree that these processes were designed when there were 5 to 6 GW in the queue. Now there is more than 100 GW,” Ghodsian said.

Shah also said MISO has to work out the board approval process of interconnection upgrades-turned-economic projects.

The Coalition of MISO Transmission Customers attorney Kevin Murray has said a consolidated transmission approach’s incorrect assumptions could lead to needless transmission.

“We have concerns about building transmission paths to nowhere,” Murray said during an Aug. 19 Advisory Committee meeting.

But the Union of Concerned Scientists’ Sam Gomberg said planning models have gotten better, continue to evolve and can usually pinpoint the most useful projects.

Several stakeholders have said that cost allocation under coordinated planning must be handled to appropriately charge cost-causers and beneficiaries.

Board OKs 1st Major Interregional Project

Directors last week approved MISO’s and PJM’s first major interregional transmission project, a year after it was first recommended by the RTOs.

The $22 million reconstruction of the 138-kV Michigan City-Trail Creek-Bosserman line in the northwestern corner of Indiana was identified last fall in the 2018/19 MISO-PJM coordinated system plan. (See MISO, PJM Poised for 1st Major Interregional Project.) The project is a tie line between Northern Indiana Public Service Co.’s service area in the MISO footprint and American Electric Power’s territory on PJM’s side. The project boasts a 3.12:1 benefit-to-cost ratio. MISO stands to pay just under 11% of project costs at $2.35 million.

MISO’s board approved the project during its Sept. 17 meeting.

Director Nancy Lange asked whether future interregional projects with PJM will be approved more quickly now that a cost allocation method is in place.

“These reforms certainly make it easier for projects. It should be a more expeditious process in the future,” said Jesse Moser, director of economic and policy planning.

PJM’s Board of Managers approved the project during its December 2019 meeting. MISO’s nine-month lag came because the grid operator does not have a cost-sharing plan in place for its interregional market efficiency projects. (See Another Rejection for MISO Cost Allocation Plan.)

September 25, 2020

CAISO Retiring, Incoming CEOs Field Questions

CAISO CEO Steve Berberich will retire Sept. 29 after nine years as head of California’s grid operator. His replacement, Elliot Mainzer, who served for the past seven years as head of the Bonneville Power Administration, will take over the next day.

At a time of great change for CAISO, the two CEOs answered stakeholder questions in a roundtable discussion Tuesday hosted by the Western Energy Imbalance Market’s Regional Issues Forum. John Prescott, chair of the EIM’s Governing Body, moderated the discussion.

Many of the questions dealt with the challenges CAISO faces as it struggles with capacity shortfalls, the switch to carbon-free energy and its expanding role in Western energy markets.

The most candid answer of the hourlong meeting came from Berberich, when Prescott asked him about the rolling blackouts of Aug. 14-15 and the energy emergencies CAISO declared over Labor Day weekend.

Massive heat waves across the West and a scarcity of resources during evening peak demand times pushed CAISO too close to the edge, Berberich said. ISO staff had warned that capacity shortfalls could occur under just such circumstances, and now the state must move quickly to head off similar shortfalls next summer, he said.

“In a nutshell, resource adequacy needs to be redesigned, and I don’t mean in a two-year regulatory, litigated process,” Berberich said. “It better happen pretty damn fast, or we’re going to have these same issues next summer, and I don’t want Elliot to have to deal with the same crap I’ve had to deal with over the last 30 days. So, if there’s any legacy I could [leave], it’s that this has to happen, and it has to happen soon.”

Berberich previously faulted the California Public Utilities Commission, which oversees procurement, for failing to heed CAISO’s warnings. (See CAISO Blames Blackouts on Inadequate Resources, CPUC.)

CAISO, the CPUC and state Energy Commission are compiling a report on the causes of the August blackouts, which will probably be released after he retires, Berberich said. Some, including the California Community Choice Association, have called for an independent audit of that report. (See CalCCA Seeks ‘Objective’ Review of Blackout Report.)

It appears, Berberich said, that California generators were exporting energy in the day-ahead market even as the state struggled to meet demand in the real-time market, but the exact nature of the exports and their effects must still be determined, he said. Another problem may have been that some load-serving entities weren’t scheduling all their demand in the day-ahead market, he said.

“There are a lot of moving parts on this thing,” Berberich said.

The biggest problem, however, was clear, he said. It was the “head of the duck” in California’s distinctive “duck curve” demand trend. The duck’s head is also called the net peak: the hours after sun goes down and solar power rolls off the system but demand remains high.

“From a resource adequacy perspective, you have to cover all of the hours, and the way renewables work, you have to rethink these old ways of doing things,” Berberich said.

“It’s clear to everyone the sun doesn’t work in the evening and the wind doesn’t always blow, particularly when it’s hot with high-pressure systems sitting over California and the West,” he said. “So now you’re left with what? Right now, you have to use the gas fleet and imported power. And the gas fleet has been retiring here in California. And I’ve known this for some time, and I’ve told people … for some time, [that] there are going to be limits on imports when you have these heavy load periods throughout the region.

“And that’s exactly what transpired,” Berberich said. “The net peak or the head of the duck has to be provided for just like the 4 and 4:30 peak has to be provided for, and this is not news. We’ve been talking about this for a long time. We’ve said this publicly. We’ve had these filings. The resource adequacy program in California is not now matched up with the realities of working through a renewables-based system.”

The approximately 1,500 MW of battery storage that’s scheduled to come online by next summer will help but may not be the panacea some imagine, he said.

“Storage is going to play an important role, but you also have to think through how that storage is going to be charged, how it’s going to be discharged and how the economics will work,” Berberich said.

CAISO is seeking to deal with import shortfalls through its Resource Adequacy Enhancements Initiative by requiring commitments from out-of-state generators and lining up dedicated transmission heading into the summer of 2021. (See CAISO Seeks ‘Firm’ Tx for Resource Adequacy.)

Mainzer’s First Conversation

“I unequivocally agree that we really need a candid and clear-eyed assessment of what happened in August so that we can identify the causal factors … [and] can craft solutions that affect the underlying issues,” Mainzer said during what he described as his “first conversation” as incoming head of CAISO. (See CAISO Names Bonneville Power Administrator as New CEO.)

Markets need to be based on firm resource adequacy frameworks, he said.

“This is clearly going to be topic No. 1 for the state … and others across the West,” said Mainzer, a California native. At the same time, “it’s absolutely axiomatic that we must meet California’s clean energy goals.”

State law (SB 100) requires LSEs to supply customers with only carbon-free energy by 2045.

Both Mainzer and Berberich stressed the need to continue reaching out to stakeholders across the West, especially as the EIM seeks to add a day-ahead market to its current interstate real-time operation. The governance of the EIM is especially important to those outside the state, who worry about CAISO exerting too much control, he said.

“We need to be humble and listening,” Berberich said. “That’s probably the most important learning we have from [the EIM],” which has achieved more than $1 billion of benefits for its members across the West, according to CAISO.

Berberich said Mainzer is a good listener and will continue the dialogue.

Mainzer said he had to work with multiple, diverse constituencies to incorporate wind into BPA, a hydroelectric powerhouse, and to allow the federal power marketing administration to join the EIM, which it’s scheduled to do in 2022. (See Customers Probe BPA on EIM Impact.)

“A guiding pillar of my philosophy will be a lot of outreach, a lot of listening and … just trying to harness the incredible intellectual capital of folks in our industry and trying to get those best solutions identified and right into the heart of operations,” Mainzer said.

He said his knowledge of the Northwest and California will serve him well.

It’s vital to “just really sit down and take the time to listen to folks [and] have that open, honest and rigorous dialogue,” he said. “People need to feel as though their perspectives are heard and understood. You’re not going to agree with everything everybody says, but at the end of the day, people need to feel that sense of participation and stakeholder engagement.”

Mainzer said he hoped to get back to face-to-face meetings if the threat of COVID-19 passes. Online meetings are a poor substitute, he said.

“Let’s go get that vaccine and get back to some three-dimensional relationships,” he said.

Chairman Prescott called Berberich and Mainzer pre-eminent energy leaders and said he expects Mainzer to do great things at CAISO. As for Berberich, he said he doesn’t think retirement will stick. “I just have a feeling we’re going to see your smiling face somewhere in the industry.”

September 25, 2020

NEPOOL Reliability Committee Briefs: Sept. 23, 2020

The cost of the Greater Boston Project is expected to increase by $191 million (33%) primarily because of the underground Wakefield-Woburn, Mystic-Woburn and Sudbury-Hudson lines, Eversource Energy told the New England Power Pool Reliability Committee on Wednesday.

The cost of the three components is increasing by $147 million, to $352 million (72%).

The remaining 30 components’ cost is rising from $367 million to $411 million, a 12% increase over the transmission cost allocations supported previously by the RC and approved by ISO-NE.

Eversource said 25% of the increase is resulting from the need to underground the 115-kV Sudbury-Hudson line. It was initially proposed as an overhead line, but Eversource was unable to secure property leasing rights from the Massachusetts Bay Transportation Authority (MBTA). The proposed underground line is estimated at $91 million, more than double the original cost of $45.3 million, and has an in-service date of December 2023.

Eversource performed an updated alternative analysis and found that a new 9-mile, 115-kV underground transmission line within an MBTA right of way was the “most cost-effective and constructible alternative.” The two alternatives analyzed — a new 10.3-mile, 115-kV underground transmission line entirely in roadways ($110.4 million), or multiple upgrades to convert a 14.5-mile, 69-kV line to 115 kV, reconductor 11.6 miles of other 115-kV lines and upgrade seven substations ($116.1 million) — had higher costs.

The Wakefield-Woburn and Mystic-Woburn lines are increasing to a combined $260.6 million from $160.2 million, representing 50% of the total cost increase. Eversource said additional restrictions on the design and construction required a realignment of underground construction within roadways to avoid interference with existing utilities. Restrictions on work hours and the number of crews also increased the construction bids, the company said.

The matter is slated for a future committee vote.

ISO-NE, NYISO Propose Revision to Coordination Agreement

ISO-NE proposed revisions to its Coordination Agreement (CA) with NYISO to eliminate the need to make a FERC filing when the grid operators update their description of shared interconnection facilities.

The grid operators share three interconnections: the NY/NE Northern AC Interconnection (comprising the PV-20, K7, K6, E205W, 393, 690/FV and 398 interties); the Norwalk Harbor-Northport, NY, Cable (NNC Intertie) and the Cross-Sound Cable Interconnection (CSC Intertie).

Rather than maintaining the detailed list of interconnection facilities in Schedule A of the CA — which requires a FERC filing for any changes — the grid operators are proposing to update the list on their external websites. The addition or removal of an interconnection would still go through the grid operators’ stakeholder processes and filed with FERC.

ISO-NE said it and NYISO sought the change after the addition of a new transmission substation and common metering point modified one of the interties in the NY/NE Northern AC Interconnection. The change replaced the Pleasant Valley substation and common metering point in New York with the Cricket Valley substation and common metering point on the 398 Intertie.

Although the change did not alter the makeup of the NY/NE Northern AC Interconnection, current rules required that it be filed with FERC. “ISO-NE and the NYISO recognized that such ministerial revisions to the ISO-NE/NYISO CA place an unneeded burden on the respective ISOs, their stakeholders and the FERC,” ISO-NE told the committee.

The grid operators plan to file the revised CA with FERC at the end of 2020 and expect an effective date of early 2021. NYISO will go through a similar stakeholder process, which it expects to complete in November or December, according to ISO-NE.

The RTO requested that the RC vote in support of the proposed modifications at its Oct. 20 meeting.

Tie Benefits and ICR Recommended by Vote

The RC voted to recommend that the Participants Committee support ISO-NE’s tie benefits and installed capacity requirements (ICR) and related values for Forward Capacity Auction 15. (See ISO-NE Sees 722-MW ICR Jump for FCA 15.)

The Hydro-Québec Interconnection Capability Credit (HQICC) values for FCA 15, which is associated with the 2024/25 capacity commitment period, is 883 MW, and the ICR is 34,153 MW with a net ICR of 33,270 MW.

The following megawatt values were also recommended for support: Southeast New England Local Sourcing Requirement (10,305), Maine maximum capacity limit (4,145) and Northern New England maximum capacity limit (8,680).

The PC will vote on the ICR and related values on Oct. 1, with a FERC filing expected by Nov. 10.

Winter Readiness, Gas Infrastructure Surveys Added to OP-21

The RC voted to recommend that the PC approve changes to Operating Procedure 21 to add the generator winter readiness survey and natural gas critical infrastructure survey.

OP-21 is being renamed “Operational Surveys, Energy Forecasting & Reporting and Actions During an Energy Emergency” to reflect the additions.

The annual generator survey process enhances situational awareness of pre-winter generator preparations, while the natural gas survey ensures critical infrastructure of the interstate natural gas system is not on electrical circuits subject to automatic or manual load-shedding schemes.

ISO-NE distributes the generator survey before Nov. 1 each year, and it is due back no later than Dec. 1 unless specified otherwise.

The RTO distributes the natural gas survey to representatives of each interstate natural gas pipeline company operating in New England, as well as the Canaport and Everett LNG facilities. It is typically completed in June.

September 25, 2020

NERC Standards Committee Briefs: Sept. 24, 2020

NERC’s Standards Committee voted Thursday to accept the standard authorization request (SAR) presented by the drafting team for Project 2019-06 (Cold weather). It also appointed the team as the standards drafting team (SDT) for the project.

Much of the discussion of the measure at the meeting reflected the responses that it received from industry stakeholders in previous comment periods. (See Cold Weather Team Seeks More Time to Process Response.) Some committee members questioned the wisdom of moving forward with a project that has proven so controversial.

“The industry has rejected this SAR numerous times, and now it’s come to the Standards Committee, and industry has not approved it yet,” said Marty Hostler, reliability compliance manager for the Northern California Power Agency. He added that “numerous issues” remain with the SAR, including unaddressed compliance burdens and the potential impact of adding more detail to existing NERC standards that were intentionally written vaguely to give more flexibility to registered entities.

Sean Bodkin, NERC compliance policy manager for Dominion Energy, agreed that while “almost all of industry supports” some kind of cold weather preparedness requirement, several rounds of stakeholder feedback made clear that the committee shouldn’t support moving forward with the SAR in its current form.

SPP’s Matthew Harward, the chair of the drafting team, pushed back on this interpretation of the stakeholder comments. While he acknowledged that “multiple comments did not agree that a new standard was needed,” he said the team had taken this into consideration and planned to work within existing standards as much as possible. The only new standard that is likely to be needed is “a requirement for [generator owners and operators] to prepare [for] cold weather.”

The measure passed with no negative votes, though Bodkin abstained, along with Venona Greaff of Occidental Chemical, Linn Oelker of LG&E and KU, and John Babik of JEA.

IRPTF SARs Accepted

The committee voted to accept two SARs requested by the Inverter-based Resource Performance Task Force (IRPTF) and approved by the Reliability and Security Technical Committee in June. They will be posted for a 30-day informal comment period as members are solicited for a SAR drafting team. (See “IRPTF SARs Pass After Debate,” NERC RSTC Briefs: June 10, 2020.)

IRPTF’s SARs would apply to the following standards:

FAC-001-3 (Facility interconnection requirements) and FAC-002-2 (Facility interconnection studies) — Clarify which entity is responsible for determining which facility changes count as material modifications; clarify that generator owners should notify affected entities before making a material modification; revise the term “materially modifying” to avoid confusion between Facilities Design, Connections and Maintenance (FAC) standards and FERC’s interconnection process.
MOD-026-1 (Verification of models and data for generator excitation control system or plant volt/VAR control functions) and MOD-027-1 (Verification of models and data for turbine/governor and load control or active power/frequency control functions) — Revise or replace with a new model verification standard that accounts for inverter-based resources.

Two other SARs suggested by the IRPTF — to modify PRC-002-2 (Disturbance monitoring and reporting requirements) and VAR-002-4.1 (Generator operation for maintaining network voltage schedules) — were also approved by the RSTC but were not submitted to the Standards Committee. NERC’s Manager of Standards Development Soo Jin Kim said that the two that the committee approved were considered “higher priorities based on some issues that are occurring today with regard to compliance.”

Questions About Consistency in Nominations

The committee also approved the appointment of the chair and vice chair, along with nine members, to the SAR drafting team for Project 2020-04 (Modifications to CIP-012) and endorsed NERC’s 2021 Reliability Standards Development Plan. (See NERC Opens Comments on Standards Plan.)

None of the prospective team members for Project 2020-04 — who were not identified by name during the meeting — met with serious opposition, but some committee members did raise questions about the nominating process.

Bodkin said one candidate did not seem to have relevant expertise and lacked an endorsement from a generator or transmission owner/operator. However, he dropped the question after Kim and Howard Gugel, NERC’s vice president of engineering and standards, reminded him that ERO staff have the authority to certify a candidate as a subject matter expert — and had done so in this case.

Robert Blohm, managing director of Keen Resources, noted that none of the candidates nominated by stakeholders but not recommended for inclusion by NERC had references on file. He asked whether they had been rejected for failing to submit references — a policy that the committee has objected to before. (See “SDT Candidate Restored After Application Oversight,” NERC Standards Committee Briefs: July 22, 2020.)

In response, Kim explained that the candidates did submit references, but the template used by her team in preparing the report did not have a space for the information. Blohm suggested that the form be updated to ensure those candidates not recommended by NERC were represented with the same level of detail as those who were endorsed.

September 25, 2020

NERC Team Shows off ‘Nifty Tools’

NERC’s Bulk Power System Awareness Team on Thursday gave stakeholders a presentation on their role as the ERO’s “eyes and ears.”

“We collect data, analyze the data and report on the data,” Bill Graham, principal bulk system awareness coordinator, said during NERC’s eighth annual Monitoring and Situational Awareness Technical Conference, held via WebEx. “We’re continuously observing system conditions and using various tools that we have, as well as expertise, [to] try to identify any kind of threats.”

Graham gave his presentation after an update by Wei Qiu, senior engineer of event analysis, on trends in NERC’s energy management system outage data.

The seven-member Bulk Power System Awareness Team, part of NERC’s Reliability Risk Management department, has an average of 22 years of experience. It is headed by Director Darrell Moore, a former transmission operator for Georgia Power.

In addition to Graham, who received nuclear training in the U.S. Navy, it includes senior engineer Mani Mardhekar, a former power trader and analyst of bulk power system operations; senior analysts Ara Johns, a former generation dispatcher for Southern Co., and Brent Kane, a former reliability coordinator for PJM; Tony Burt, former supervisor of reliability coordination operations at Peak RC; and administrative assistant Stephanie Lawrence, who holds a degree in information technology.

In addition to issuing about a dozen special reports annually, the team provides a report each morning that is circulated to NERC CEO Jim Robb, FERC, the regional entities and some reliability coordinators. “It’s a description of what we’ve seen … threats that are potentially in place against the bulk power system, as well as any kind of weather events or anything of the like that needs to be at the forefront of everyone’s mind,” Graham said.

It also collects the EOP-004 disturbance reports filed daily by regulated entities.

“What my team does is the initial triage of these events to understand if there’s an immediate concern,” Graham said. It also files the information into databases used for event analysis and Lessons Learned reports.

But it is not involved with any compliance monitoring, Graham emphasized. “We do file the mandatory EOP-004 reports into the NERC database … but we don’t provide any kind of comment or input with regard to any compliance monitoring issues,” he said. “We steer clear of that 100%. If compliance ever does become an issue, we stop the conversation and get the correct parties involved. We just simply are not part of the compliance regulatory arm of NERC.”

The team has a variety of what Graham called “nifty tools,” including OSIsoft’s PI Vision, which tracks system frequency, and SAFNR v.3 (Situational Awareness for Situational Awareness Tool Nears Rollout.)

It also uses Genscape, which collects power prices and uses sensors to monitor transmission line loads.

Although it is largely used by power traders, “we use it to understand the health and wellbeing of the bulk power system,” said Graham, showing a screen shot from a day when he said there were “buying opportunities” in MISO.

“What my team does is we see this and try to understand why. Why is there a buying opportunity up in the Michigan area? Is there a plant that’s in a forced outage? Is there transmission congestion?”

The group also monitors “all the social media and news websites that you can imagine. So, for example we keep an eye on all the utility websites, all the reliability coordinator websites [and] all the balancing authority information that’s publicly available,” Graham said. “Likewise, we keep a close eye on social media. We do not participate, but we do watch what’s being talked about.”

And because NERC is a nonprofit organization, Graham said, “we make the best use of any single free Internet tool that’s available.”

“So, we’ve become experts at all the different weather websites,” he said. “Hurricanes are a huge deal for us.”

September 25, 2020

FERC, NERC to End CIP Violation Disclosures

FERC and NERC will no longer publicly post information about violations of the ERO’s Critical Infrastructure Protection (CIP) standards, according to a joint white paper published by the organizations on Wednesday (AD19-18).

Under the new rule, NERC will request that CIP noncompliance information filed to the commission be treated as critical energy/electric infrastructure information (CEII) in its entirety, and it will end its current practice of publicly posting redacted versions of the filings. It is unclear whether NERC will continue to provide public information about violations of CIP standards in any form.

NERC and FERC’s new direction is a sharp contrast to a proposal floated last year that would have seen the ERO file public cover letters with its CIP-related Notices of Penalty (NOP), including the name of the violator, the standards violated (but not the requirements) and the penalty amount. (See FERC, NERC Propose New CIP Disclosure Rules.) The remainder of the NOP, containing details on the violation, mitigation activity and potential vulnerabilities to cyber systems, would be submitted as a nonpublic attachment with CEII designation.

NERC has been redacting information claimed as CEII from public filings on a line-by-line basis since 2019; previously, the public version of NOPs involving CIP violations contained similar information as the confidential submissions to FERC, with CEII excluded entirely. The proposal for public cover sheets came about in response to “an unprecedented number of requests” under the Freedom of Information Act (FOIA), with the organizations saying the new approach would achieve “an appropriate balance of security and transparency.”

Dueling Concerns over Security, Transparency

Stakeholder responses to the last white paper, submitted in November 2019, revealed widespread opposition to the proposal, though the reasons for disapproval varied widely. (See FERC, NERC Reviewing Comments on CIP Disclosures.)

CIP violations — FERC headquarters in D.C. | © *ERO Insider*

Several consumer advocacy groups, such as the Foundation for Resilient Societies (FRS) and Public Citizen, criticized the plan for not providing enough transparency. FRS objected to the requirement that any CIP violations be fully mitigated before an NOP is submitted, and to allowing utilities to request indefinite delays in public disclosure. Public Citizen called for further reforms, including formal protection for whistleblowers.

At the other end of the spectrum was a number of industry representatives, such as the MISO Transmission Owner stakeholder sector, and a group of trade organizations, including the Edison Electric Institute, National Rural Electric Cooperative Association and WIRES. They argued that even the limited information that NERC and FERC proposed to release “could provide roadmaps to bad actors” targeting critical infrastructure assets by exposing vulnerabilities in the bulk power system.

Report Sides with Industry Objections

In their final decision, FERC and NERC leaned decisively toward the second line of reasoning, agreeing that the previous proposal “is insufficient to protect the security of the bulk power system” and that disclosing the identity of CIP violators creates “substantial risks” from hackers and other malicious cyber actors.

“Since the public does not have a statutory role in the enforcement of reliability standards, public disclosure of CIP noncompliance information does not serve any statutory purpose,” the white paper said. “Although commission and NERC staffs recognize the potential deterrent effect of publicizing the identity of violators in general, the security concerns discussed here outweigh the potential benefit.”

In addition, the report cited a filing by the Department of Energy that argued the commission “did not fully avail itself” of the authority to protect CEII provided to it by the Fixing America’s Surface Transportation Act and the Federal Power Act. The department also noted that the FOIA contains exemptions for both CEII and confidential business information, and suggested that CIP violation information could fall under either category.

September 24, 2020

MISO Sets Candidate Slate for Board Elections

MISO’s Board of Directors has three seats up for grabs in December, though the new board is only guaranteed one new face.

The RTO’s Nominating Committee advanced current Directors Theresa Wise and Robert Lurie for member consideration, along with newcomer Jody Davids. Formerly chief information officer for PepsiCo, Davids has also served as CIO for Agrium, Best Buy and Cardinal Health. She currently sits on the board for Premier, a Charlotte, N.C.-based health care improvement company.

MISO board elections — Jody Davids | *Premier*

Wise and Lurie are both rounding out their first terms and applied for reappointment. Lurie served the one-year remainder of former Director Thomas Rainwater’s term, which expires at the end of December.

Longtime Director Baljit Dail will not make a reappearance at MISO’s U-shaped board table next year. Dail spent 12 years on the board — three more than technically allowed — through a special waiver that allowed him an extra term so the board could retain a person with technology expertise.

MISO’s 139 voting-eligible members can begin casting ballots for candidates beginning 8 a.m. Thursday. The electronic polls will close at 5 p.m. Oct. 30. Board elections require a minimum 25% participation rate to achieve quorum.

Members can vote for or against any of the candidates, or abstain. Candidates must earn a majority of votes cast to be installed. MISO will announce election results in mid-November.

The board voted unanimously during its Sept. 17 meeting to retain Phyllis Currie as its chairman in 2021.

September 24, 2020February 25, 2024

Indiana City Wins Ruling on Station Power

FERC ruled last week that generating facilities that are not online and producing energy must pay for their station power at retail rates subject to state jurisdiction and directed PJM to consider changing its Tariff accordingly (EL20-30).

The commission said an offline generator that requires power to operate its lighting, air conditioning and other facilities “is consuming electricity as an end user and thus, consistent with the boundaries of the commission’s jurisdiction under the [Federal Power Act], the provision of station power is a retail sale subject to state jurisdiction.”

The commission’s ruling came in response to a complaint filed by Lawrenceburg, Ind., and the Indiana Municipal Power Agency against the RTO, American Electric Power Service and Lawrenceburg Power seeking to void the power self-supply monthly netting provisions of the RTO’s Tariff.

The city’s Lawrenceburg Municipal Utilities has an exclusive franchise for supplying electricity within city limits and says Lawrenceburg Power’s 1,160-MW combined cycle plant in the city must take station power service from the city because Indiana law does not allow it a choice of retail supplier. The plant is interconnected with AEP transmission facilities under PJM’s operational control.

FERC approved the netting rules in 2001, saying station power can be supplied to a generating plant in three ways: on-site self-supply (from behind-the-meter generation); remote self-supply (from another generator owned by the same company); or third-party supply.

| Lawrenceburg Municipal Utilities

While the commission disclaimed jurisdiction over the supply of station power, it rejected the petitioners’ request for a declaratory order finding the station power monthly netting provision in section 1.7.10(d)(i ) of the PJM Tariff null and void.

Instead, FERC instituted a new proceeding, requiring PJM to propose changes to its Tariff consistent with the order or show cause why changes are not necessary (EL20-56). The RTO has 60 days to respond.

FERC said PJM’s proposed revisions should clarify that the monthly netting provision in section 1.7.10(d)(i) “does not determine whether a retail sale of station power has occurred in that month.” It also said Tariff provisions should clarify that PJM has no responsibility for the determination of any state-jurisdictional retail rates.

“Because the PJM Tariff’s self-supply monthly netting provision can be read to — and indeed has been relied on by certain PJM generators to assert the right to — determine whether a retail sale of station power has occurred and avoid the retail purchase of station power, which is inconsistent with the commission’s jurisdiction, we find that PJM’s Tariff may be unjust, unreasonable, unduly discriminatory or preferential,” FERC said.

Lawrenceburg Power told FERC that Lawrenceburg Municipal Utilities has attempted to charge the generator a minimum of $845,000 annually “even if Lawrenceburg Power does not consume any station power in the entire year” and that it prefers self-supplying its station power under the PJM Tariff.

“Arguments about the justness and reasonableness of the retail rates, and about what entity within the state of Indiana has authority to provide retail service, are more appropriately raised before the relevant state regulatory body,” FERC said. “The commission does not have the authority to determine when, and on what terms, a retail sale of station power is made.”

The ruling is likely to have impacts on other merchant generators.

Among the intervenors in the case were Buckeye Power, which said it and one of its member cooperatives, Washington Electric Cooperative (WEC), are involved in a dispute with Waterford Power, a merchant generator located within WEC’s service territory, regarding WEC’s right to supply Waterford’s station power.