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June 21, 2020

More Work Needed on MISO Order 845 Compliance

MISO has four months to make two more filings to comply with Order 845, FERC ruled last week.

The commission’s order Thursday marks the second time MISO has been directed to refine its proposed compliance with Order 845, meant to increase the transparency and speed of generator interconnection processes. (See MISO Almost There on Order 845.)

This time, MISO must clear up language relating to surplus interconnection service and studies of projects’ technological advancements (ER19-1823-002, et al.).

FERC said MISO still hasn’t properly explained why it gave itself 60 days to decide whether to conduct additional studies when an interconnection customer seeks to include technological advancements in its project prior to an interconnection facilities study agreement. The commission prescribed 30 days to decide on new studies and told MISO in December to either justify the 60-day timeline or halve it.

In response, the RTO had proposed to “perform the required studies and communicate the results to the customer” within 30 days “after receipt of any additional data that MISO requires the interconnection customer to submit.” FERC’s latest ruling said that language could still allow MISO more than 30 days to decide whether a technological advancement to a project would constitute a material modification and warrant further study.

MISO Order 845 — | *National Renewable Energy Laboratory*

FERC also said MISO interchangeably used the titles “Surplus Interconnection Service Agreement” and “Surplus Interconnection Service Interconnection Agreement” in monitoring and consent agreements, which the RTO drafts to list the roles and responsibilities of a transmission owner and an interconnection customer seeking to interconnect through surplus interconnection service.

“We find that the proposed revisions create a lack of clarity that may cause confusion to interconnection customers,” the commission said, suggesting that MISO might avoid confusion by swapping the two terms with “Surplus Interconnection Facility’s Generator Interconnection Agreement.”

But FERC did accept MISO’s fuller description of how it determines which projects in its annual Transmission Expansion Plan are “contingent facilities.” Order 845 defines those facilities as a generation project’s unbuilt interconnection facilities and network upgrades that, if delayed or canceled, “could cause a need for restudies of the interconnection request or a reassessment of the interconnection facilities and/or network upgrades and/or costs and timing.”

FERC said MISO’s description of the impact criteria it uses in its distribution factor analysis fit the bill.

No Rehearing

The commission also denied the American Wind Energy Association’s rehearing request that it direct MISO to remove “barriers” preventing interconnection customers from exercising the option to build network upgrades.

AWEA contested the compliance filing’s inclusion of Tariff language describing a TO’s right to self-fund network upgrades for interconnection customers. FERC last year ordered MISO to reinstate TOs’ rights to self-fund the network upgrades, and the RTO requested an independent entity variation in its compliance filing to note the change, which the commission accepted. (See MISO Gauging Aftershocks of TO Self-fund Order.)

AWEA argued that “interconnection customers have had very little success exercising the option to build since the commission issued Order No. 2003 and that the commission, in Order No. 845, intended to restore that right.”

But FERC agreed with MISO that “not harmonizing a transmission owner’s right to self-fund with the expanded option to build could impermissibly undermine a transmission owner’s right to self-fund.” It said the RTO had no choice but to reconcile Order 845’s expanded option to build for interconnection customers with the TOs’ right to elect to provide initial funding for standalone network upgrades.

June 21, 2020

ERCOT Briefs: Week of June 15, 2020

ERCOT last week approved two suspension-of-operations requests from Austin Energy, saying both generating units are not required to support the system after it conducted a reliability analysis.

On June 16, the Texas grid operator gave the go-ahead to retire Decker Lake 1, a 49-year-old gas-fired steam unit with a capacity of 315 MW. The unit will be decommissioned and retired permanently as of Oct. 31.

The next day, ERCOT signed off on Austin Energy’s request to place the Nacogdoches Generating Facility into seasonal mothballs, with an operating period of May 15 to Oct. 15. The wood-fired East Texas plant is the country’s largest biomass plant at 105 MW.

Austin Energy has told ERCOT it intends to retire both steam turbines at its Decker Lake facility. Decker 2 will be retired following the 2021 summer peak. Both units are nearing the end of their normal life expectancies. (See “Austin Energy to Retire 735 MW of Gas Units,” ERCOT Briefs: Week of June 1, 2020.)

The municipal utility acquired Nacogdoches from Southern Power last year. It has a 20-year power purchase agreement for the plant’s energy that expires in 2032.

System Demand Nears Pre-COVID Levels

Staff said “it appears” the pandemic had less effect across all hours for the week beginning June 7. Weekly energy use is down by about 1%, and there have been no impacts on daily peak demand.

ERCOT came close to a monthly record on June 8-9 when demand approached 69.1 GW. The grid operator did set a monthly record in April with a peak demand of 55.2 GW.

The backcast analysis compares model results using actual weather versus actual hourly load. The model was last updated in January and does not reflect the pandemic’s effects.

June 21, 2020

NARUC, NASEO Launch Solar Cybersecurity Resource

The National Association of Regulatory Utility Commissioners and National Association of State Energy Officials have launched an initiative aimed at improving cybersecurity defenses in solar energy facilities.

The Cybersecurity Advisory Team for State Solar, which is also backed by the Department of Energy’s Solar Energy Technologies Office, will include experts on digital security, the electric grid and photovoltaic technologies. Leadership will be drawn from state-level policymakers and regulators — with additional expertise from the federal government and private sector — in order to create “model cybersecurity programs and actions for states to take in partnership with utilities and the solar industry.”

In a press release, NARUC and NASEO said “the rapid growth and importance of solar energy” to the bulk power system in recent years has introduced new weaknesses into the grid that must be addressed. New communication technologies have provided grid operators with considerable flexibility but also created more points of entry for malicious actors hoping to gain access to critical infrastructure.

“As energy systems become more integrated and cyber-connected, their vulnerability to malicious actions grows,” said Andrew McAllister, a member of the California Energy Commission and chairman of NASEO’s board of directors. “Solar technologies are no exception. New tools and a dedicated, multi-stakeholder approach should strengthen solar cybersecurity and, by doing so, enable states to make meaningful progress on climate and resilience goals.”

NARUC has a history of pushing state utility regulators to take seriously the cybersecurity implications of new grid technologies. The topic was a major theme of the organization’s 2019 Summer Policy Summit, where experts warned that the growth of distributed energy resources means utilities must protect many more generation facilities than they are used to. (See Experts Urge State DER Cybersecurity Standards.)

Such systems can be highly vulnerable to attack: One analyst described accessing a solar array and its microinverters through a webpage without having to enter any login credentials. Security factors are often overlooked because a lack of regulatory urgency on cybersecurity leaves it a low priority for utilities and equipment vendors.

NERC has also become increasingly concerned about the cybersecurity implications for rooftop solar panels and other DERs in recent years. At a meeting earlier this year of the System Planning Impacts from Distributed Energy Resources Working Group, Thomas Bialek, chief engineer for San Diego Gas & Electric, warned that not only does such equipment often contain security flaws overlooked by the vendors, but exploiting such openings may be easier for malicious actors because the systems are not protected by utilities’ existing cybersecurity measures. (See Rooftop PV’s ‘Hidden Loads’ Challenge Grid Planners.)

“We have our cybersecurity and our firewalls over our interfaces … but we don’t do that for any of the rooftop PV installations that are now using home Wi-Fi,’” Bialek said. He observed that more than 58% of rooftop solar installations in his utility’s territory are provided by just two vendors, which poses a significant risk because hackers can often use the same attack vector against multiple types of systems from a single manufacturer.

June 19, 2020

NERC Standards Committee Briefs: June 17, 2020

NERC’s Standards Committee approved a proposal to solicit one or two additional nominees for the Standard Authorization Request (SAR) drafting team responsible for cold weather standards (Project 20 1 9-06), over the objection of Sean Bodkin, NERC compliance policy manager for Dominion Energy.

The solicitation is intended to add representation for small entities. Howard Gugel, NERC’s vice president of engineering and standards, said he had received emails from industry stakeholders expressing concern that this sector was underrepresented on the team. However, Bodkin pointed out that the drafting team already has a member from Ingleside Cogeneration in Texas, which he felt should satisfy the stakeholders.

“I guess I’m a little concerned about the disconnect. We already have a small entity on there, [do] we need more small entities, different small entities?” Bodkin asked during the committee’s conference call Wednesday, which replaced its scheduled in-person meeting.

In response, Gugel observed that NERC believes that a cogeneration facility like Ingleside will not bring the same perspective as a municipal or cooperative utility. But Bodkin continued to press the matter, reminding committee members that the SAR drafting team itself has raised no objections to its current membership through several rounds of revisions. (See Col d Weather Team Seeks More Time to Process Response.)

“It’s already got 10 members [and] there’s already a small entity on there,” Bodkin said. “[The] standard drafting team didn’t see a need to add that extra diversity or expertise. I’m not sure I can support going out and adding an eleventh member to a 10-member team that’s going out for a fourth try on a SAR.”

Despite the debate, the proposal passed with Bodkin and Linn Oelker, market compliance manager for Louisville Gas and Electric and Kentucky Utilities, casting the only “no” votes. Neil Shockey, principal manager for Southern California Edison, and Venona Greaff, senior energy analyst for Occidental Chemical Corporation, abstained. Nominations for the small entity representatives are open through July 2. The Standards Committee will appoint the new members at its next meeting on July 22.

Blohm Touts Experience in SAR Candidate

A request to appoint members to the SAR drafting team for Project 2020-01 — modifications to MOD-0 32-1, governing data for power system modeling and analysis — prompted discussion as well. The proposed team would consist of 12 members, including the chair and vice chair.

NERC Standards Committee — Soo Jin Kim, NERC | © *ERO Insider*

Asked by Bodkin why the planned roster was larger than the normal team size of 10 members, NERC’s Manager of Standards Development Soo Jin Kim explained that in the last few months several standard drafting teams have reported scheduling issues related to the COVID-19 pandemic, as members have been pulled by their utilities into business continuity efforts. Adopting a larger team size is one way to reduce these impacts.

Robert Blohm, managing director of Keen Resources, also raised the possibility of replacing one nominee, who like the others was not identified by name during the proceedings, with another from the same company who was considered by NERC for nomination but not included in the final slate. Blohm acknowledged that both candidates were well-qualified but observed that the unselected candidate had both longer industry experience and previous experience serving on standard drafting teams, a quality that he worried was being overlooked by the committee.

“We want to encourage younger membership; you don’t want to institutionalize the past too much. But, on the other hand, you don’t want to de-emphasize it either,” Blohm said. “And in this case it’s not like there’s an excess or surplus of drafting team experience … In fact, [only] one-sixth of the selected [nominees] have had that experience.”

Blohm moved to switch the two nominees, though he admitted that the motion was unlikely to receive a second — which turned out to be the case. The original slate was approved unanimously with no changes.

SOL, Training Proposals Accepted

The committee approved the following items during the conference call:

Project 201 5 –09, establish and communicate system operating limits: Authorize initial posting of proposed reliability standards IRO-008-3 and TOP-001-6 for a 45-day formal comment period, with a ballot pool formed in the first 30 days. In addition, conduct parallel initial ballots and non-binding pools on violation risk factors and violation severity levels during the last 10 days of the comment period.
Endorse the Process Subcommittee’s proposal to identify and document relevant materials for orientation and/or training of Standards Committee members and recommend improvements where necessary.

The second measure was passed in modified form after Bodkin suggested that training processes be included, in addition to materials, to ensure that orientation can be done in a more consistent manner.

June 19, 2020

Monitor Breaks with MISO over RA Concerns

MISO and its Independent Market Monitor are at odds over how — and exactly how quickly — the RTO should address its resource adequacy, board members heard Tuesday.

Both sides presented their opinions during a June 16 virtual meeting of the Markets Committee of the MISO Board of Directors.

MISO RA Concerns — MISO IMM David Patton | © *RTO Insider*

Monitor David Patton said MISO’s worsening resource adequacy situation is a top concern for his staff, noting that RA solutions will be a centerpiece of his annual State of the Market report due out next week.

Patton said he continues to have “diplomatic disagreements” with MISO over how to handle RA, calling attention to low capacity prices in the April Planning Resource Auction, despite a historically high cost of new entry price for Lower Michigan’s Zone 7. (See MISO: New Outage Rules Boosted Mich. Capacity Prices.)

Outside of Zone 7, MISO zones cleared at $5 to $7 per MW-day, “inefficiently low at less than 3% of the cost of building a new peaking resource,” he s a id. Capacity should be priced at or above $200/MW-day in those zones, or about 80% of the cost of building a new resource.

Reliability is “almost free” in MISO based on capacity prices, Patton argued. He also said current prices nudge coal generators to retirement and prompt other capacity resources to sell outside the footprint.

“As MISO’s capacity margin continues to fall and renewables enter, it will be increasingly important to send efficient long-term price signals,” Patton warned.

The subregional transmission limit from MISO South to MISO Midwest often binds on the 2,500 MW limit, restricting supply that can be sent from South, whose zones are often in a better capacity position than zones to the north.

“Replacing a megawatt of coal in the North with a megawatt of gas in the South is not contributing effectively to the planning reserve margin,” Patton said.

The Monitor presented its viewpoint after a review of results from the Organization of MISO States-MISO survey, released last week.

The five-year RA survey forecasts MISO will have 0.8 GW of excess firm capacity beyond the planning reserve margin for 2021, although the surplus could reach as high as 7.2 GW. But MISO may confront a 0.4 GW shortfall as early as 2022, with 2023 to 2025 seeing anything from a 6.8-GW deficit to a 12.5-GW surplus, depending on the volume of new resources that come online. It also said some of that surplus in local resource zones could probably cover potential scarcities in other zones. (See OMS-MISO Survey Sees Uncertain Supply Fut u re.)

More Coming than Going

MISO’s generator interconnection queue currently contains 417 projects, totaling about 64 GW, with solar generation accounting for nearly 60% of proposed megawatts. Last year, the queue hit a peak of about 100 GW.

MISO is anticipating a little more than 9 GW to interconnect by year’s end and expects from 8 GW to 39 GW of new resources to join the queue in 2020. And while MISO has executed about 36 GW in generation interconnection agreements from 2015 to 2019, only 18 GW of generation retired over the same time period.

“More has come on than has actually retired on an installed capacity basis,” MISO Executive Director of Systems Planning and Competitive Transmission Aubrey Johnson told board members.

Director Barbara Krumsiek said she was not particularly concerned about a near-term shortfall, although “the press picked up on it.” However, she asked if the possibility of a capacity shortage in a few years might prod MISO and OMS to conduct the survey more frequently than on an annual basis.

“That would be more important if we saw more red [deficits] in 2021 or some more potential shortfall in 2022 … I think right now we’re not contemplating a more frequent survey,” Executive Director of Market Operations Shawn McFarlane said.

Director Theresa Wise suggested that stakeholders would be more reassured if MISO also provided details about how closely past surveys matched eventual supply.

“Would it help this message if we saw what was predicted for 2021 or 2022 four years ago?” she asked.

McFarlane said he was “almost positive that six years ago, 2021 would have showed red.” He said the survey’s indications of retirements and increasing planning reserve margins likely prompt some resource owners to make their generation more available, helping to avoid capacity shortages.

“I think that’s a constant iteration of this process, these actions and reactions based on data,” McFarlane said.

But he added that capacity additions in the interconnection queue are overwhelmingly renewables and intermittent in nature, making efforts to ensure future reliability imperative.

“The resource shift shows no signs of waning,” McFarlane said.

Patton also pointed out that wind resources represent virtually all recent generation additions in Midwest.

“It’s important to keep an eye on that trend; it might cause a capacity problem in the North,” he said.

Spring Easily Managed

The auction played out against a spring backdrop where real-time average energy prices fell to $18/MWh compared to an average $24/MWh in 2019 and about $30/MWh in 2018 and 2017.

“Prices remain low across the MISO footprint, and when you compare to last year, it’s a 25% decrease,” Executive Director of System Operations Renuka Chatterjee said, adding that the low prices were a product of falling natural gas prices and stay-at-home orders in response to COVID-19.

Patton said the spring price drop was the largest he’s ever seen in MISO.

Overall, spring temperatures were about 2 to 3 degrees above the 30-year average in Midwest and about 1 to 2 degrees below normal in South.

Prior to the pandemic, MISO predicted spring energy usage would peak at 100 GW in May — which peaked at just 80 GW. (See MISO Forese e s ‘Typical’ Spring.)

“The load was lower, so we didn’t have any significant reliability issues,” Chatterjee said.

Patton said his monitoring team observed a 35% drop in day-ahead revenue sufficiency guarantee (RSG) payments and a 57% decrease in real-time RSG payments compared to last spring. He said the dip was expected and a good sign.

“It signifies that the markets do a really good job of responding to supply,” he said.

Chatterjee said MISO is seeing a return to more normal load levels as states allow a staggered reopening of businesses. MISO continues to forecast day-ahead demand using a “COVID and non-COVID model” to more seamlessly return to predicting normal loads.

“In the early days [of the pandemic], we struggled to get our model to learn the impacts,” he said.

MISO said a forecast for a warmer-than-normal summer with higher air conditioning demand might counter the load-reducing impact of the pandemic. However, it warned that the return of full-force closures could again constrict demand. The RTO projects a 125-GW summer peak. (See MISO Preps for Balmy Summer with Pandemic Effects.)

“There’s still a degree of uncertainty as we head into summer,” Chatterjee said.

“The reality of COVID isn’t a complete crash in demand,” MISO President Clair Moeller told board members.

June 19, 2020

Regulators Not Sold on MISO Tx Planning Sync

Some state regulators aren’t convinced about the wisdom of merging MISO’s transmission expansion planning with generator interconnection studies, a move supporters say could improve cost effectiveness.

MISO is conducting an in-depth review of its planning processes in response to a proposal to synchronize its annual Transmission Expansion Plan with network upgrades needed to accommodate generator interconnections. Proponents say a coordinated planning process could identify projects that satisfy multiple needs. Renewable developers have complained that MISO is relying on network upgrades — paid by generators seeking interconnection — to plan the system. (See MISO Floats Ideas on MTEP, Interconnection Coupling.)

Speaking during a June 17 Advisory Committee teleconference, North Dakota Commissioner Julie Fedorchak said members of the Organization of MISO States (OMS) are split on the idea. She said some state regulators view the push for synchronization as an attempt by renewable developers to shift the cost of network upgrades to others that does not merit a change in planning processes.

Clean Grid Alliance’s Natalie McIntire, speaking on behalf of MISO’s Environmental Sector, said she understands new transmission “fatigue.”

“I don’t think anyone loves to see new transmission lines. It’s a tough process to get them through state approvals,” McIntire said. But she added that one larger, well-planned project can meet the needs of many small transmission projects.

MISO transmission planning — | *Midwest Reliability Organization*

DTE Energy’s Nick Griffin said a more consolidated transmission plan could be more cost-effective for customers and lead to a more robust capacity supply. He said his utility has encountered delays in the interconnection queue while trying to bring more capacity online.

“While the queue advertises a 500-day process, there are sometimes when it’s a 1,000-day process,” Griffin said.

He stressed that the benefits of any multipurpose transmission projects need to be traced to ensure beneficiaries pay their fair share.

The Union of Concerned Scientists’ Sam Gomberg said MISO should also investigate “bridge solutions” like dynamic line ratings, which could allow more power on the system.

OMS recently partnered with the MISO Independent Market Monitor to gather more information on the use of dynamic and temperature-adjusted transmission line ratings in MISO. Once OMS has exhaustively researched dynamic line ratings, it will announce a position on the topic. OMS President and Minnesota Commissioner Matt Schuerger said OMS believes there’s a “lack of transparency and consistency” among MISO TOs’ existing line ratings.

Fedorchak also said OMS regulators are in general agreement that another long-term transmission package like 2011’s Multi-Value Project portfolio may address some of the transmission needs resulting from an increase in renewable generation.

MISO’s generator interconnection queue currently contains 417 projects, totaling about 64 GW, with solar generation accounting for nearly 60% of proposed megawatts. MISO expects to interconnect about 9 GW of resources in 2020 and add 25 GWs in new projects to the queue for the year.

June 19, 2020

PJM Stakeholders Endorse End-of-Life Proposal

PJM members endorsed a proposal to open end-of-life (EOL) projects to competition Thursday, setting up a showdown with Transmission Owners at FERC.

The joint stakeholder pro p osal, which was sponsored by American Municipal Power (AMP), Old Dominion Electric Cooperative (ODEC) and others, cleared the two-thirds threshold with a sector-weighted vote of 3.45 (69%) to win the Members Committee’s endorsement. The measure had fallen short with a 3.23 (65%) vote at the May 28 Markets and Reliability Committee meeting. (See PJM End-of-life Propo s als Fail at MRC.)

In the interim, the Transmission Owners Agreement-Administrative Committee (TOA-AC) on June 12 filed Attachment M-3 amendm e nts with FERC, laying out their own EOL proposal, which aligned with the position of PJM staff (ER20-2 046). (See TOs Vote to File End-o f -life Rules with FERC.) [Late Thursday, ODEC and AMP Transmission filed a motion seeking to have the TOs’ filing dismissed on procedural grounds. The companies said the TOs issued the 30-day notice of their filing without a formal vote of the TOA-AC, violating the Consolidated Transmission Owner Agreement and AMPT and ODEC’s rights as PJM Transmission Owners.]

PJM General Counsel Chris O’Hara said after Thursday’s vote that the RTO will file the stakeholders’ proposal with FERC within two weeks, even though it believes it violates its governing documents.

“This is obviously a difficult spot for PJM,” he said, citing the “tension between PJM’s obligation to … comply with all of its governing documents [and its] obligation to accomplish the will of the members.

“We understand there’s a pending TO [Section] 205 proposal at FERC, so we will act with reasonable diligence to accomplish this filing,” O’Hara added.

On Thursday, the joint stakeholders’ proposal won s u pport from 100% of End-Use Customers, 97% of the Electric Distributors, 83% of Generation Owners and 51% of Other Suppliers. It was opposed by all but two of the 14 Transmission Owners. The difference maker was a shift by Other Suppliers, who only gave the proposal 41% support at the May 28 MRC meeting, and Generation owners, whose support increased by 12 percentage points.

Under the stakeholders’ proposal, TOs would be required to notify PJM and stakeholders of any facility nearing the end of its life at least six years before its retirement date so that the project could be included in five-year planning models and potentially opened to competitive bidding. It would also modify the supplemental project definition to exclude EOL projects, which would become a new category of regionally planned projects.

The MC vote was one of two victories for advocates of transmission competition in PJM Thursday as FERC ruled that the RTO has failed to comply with its conditions for the “immediate need” exemption under Order 1000. The commission said PJM must increase the transparency of its practices. (See related story, More Transparency Ordered on PJ M `Immediate Need’ Tx.)

The Proposal

Mark Ringhausen of ODEC gave a presenta t ion on the joint stakeholder proposal, saying the goal is to improve transparency and incorporate the EOL determination process into the Regional Transmission Expansion Process (RTEP).

Ringhausen said he wanted to clarify some misconceptions about the proposal, explaining that the language allows TOs that don’t want to utilize the EOL process to continue to use maintenance activities for their transmission facilities. The new rules would only impact TOs declaring an entire line or facility as having reached its EOL, he said.

“It’s very clear in the CTOA that maintenance activities are 100% under the purview of the transmission owners,” Ringhausen said.

The stakeholder proposal should also lead to fewer supplemental projects from the TOs, he said. PJM has reported that TOs’ supplemental projects totaled almost $3.4 billion in 2019, more than double the less than $1.5 billion in regionally planned baseline projects. It was the fifth year out of the last six in which supplemental projects exceeded baseline projects. (See Stakeholders Urge PJM: Plan ‘Grid of the Fut u re’.)

“It just gives PJM the ability to plan a better transmission system to allow market participants to use going forward,” Ringhausen said.

Sharon Segner of LS Power offered a series of friendly amend m ents to the OA changes. Segner said the amendments were a result of conversations with PJM staff and other stakeholders to clarify definitions and other language in the proposal.

Segner said PJM staff made it clear they were not endorsing the changes when discussions took place but simply wanted to provide legal comments on what was being proposed and help edit draft language.

Some of the changes included making sure the TOs, not PJM, are responsible for the EOL look ahead program, Segner said.

“I think it’s fair to say there continues to be policy differences with PJM, but it’s certainly been a good faith effort on everyone’s part,” she said.

Dave Souder, PJM senior director of system planning, presented the RTO’s respo n se, including a May 27 let t er from the Board of Directors, detailing PJM’s concerns with the stakeholder package.

Souder said the stakeholder proposal introduces a “dichotomy” by requiring a final EOL determination six years in advance when final EOL determinations typically occur at the one- to three-year time frame. Forcing a final binding six-year EOL determination may result in premature retirement of transmission facilities, he said.

Supporters

Cynthia Holland, director of federal and regional policy for the New Jersey Board of Public Utilities (NJBPU), said the joint stakeholder proposal provides a path to transparency in the planning process.

“We appreciate the efforts of the stakeholders who have put forward this proposal,” she said. “We do think it has merit.”

Susan Bruce of the PJM Industrial Customer Coalition (ICC), which co-sponsored the joint proposal, said that consumers have been living with “unprecedented transmission costs” for years and that her members experience difficulties budgeting for the rising costs of transmission each year.

She said many ICC members are pursuing clean energy, and generation interconnection is a key issue for them.

“It’s important for this issue to be before [FERC] for us to make progress,” Bruce said.

Disagreements

Robert Taylor of Exelon said the stakeholder proposal is “substantively and legally flawed.”

Alex Stern, director of RTO strategy for PSEG Services Corp., went even further in his critique of the proposal, saying the result of Thursday’s vote calls into question the entire stakeholder process. He said the TOs spent six months trying to work with other stakeholders only to find “divide and a disconnect” in the stakeholder process.

He said the OA changes will hinder, not facilitate, “the grid of the future.”

The proposal would confront needed transmission projects with “unnecessary roadblocks while some gamblers in the crowd hope there’s uncertainty that brings competitive opportunities,” Stern said.

June 19, 2020March 11, 2025

More Transparency Ordered on PJM ‘Immediate Need’ Tx

PJM has failed to comply with FERC’s conditions for exempting “immediate need” transmission projects from competition under Order 1000 and must increase the transparency of its practices, the commission ruled Thursday (EL19-91).

Separately, the commission terminated Section 206 investigations into ISO-NE (EL19-90) and SPP (EL19-92), concluding they were in compliance with the exemption rules.

FERC opened investigations into the three RTOs’ practices in October 2018, questioning whether they were thwarting Order 1000’s competition mandate by abusing the immediate need exemption. (See FERC to Probe Order 1000 Competition Exemptions.)

Order 1000 required RTOs to eliminate any federal right of first refusal (ROFR) from commission-jurisdictional tariffs and agreements but allowed a ROFR for reliability projects whose needs are so urgent that there is insufficient time to hold a competitive proposal window.

Five Criteria

Saying the exemption should be used only in “certain limited circumstances,” the commission set five criteria to limit the RTOs’ discretion for applying it.

In Thursday’s order, FERC concluded PJM was complying with only two of the criteria, ordering it to make Operating Agreement changes regarding the other three within 60 days.

The commission said PJM complied with the first criterion that projects exempted from competition must be needed in three years or less to solve reliability criteria violations. PJM also complied with a requirement to post annually a list of immediate need reliability projects to be built by incumbent transmission owners.

But FERC said it agreed with stakeholders’ comments that PJM’s explanations “do not provide sufficient detail” of the reliability violations and system conditions for which there are time-sensitive needs. “Similarly, we find that PJM generally fails to include any discussion about system conditions related to the reliability violations in its TEAC [Transmission Expansion Advisory Committee] presentation materials. For example, we find one-line labels (e.g., ‘short circuit,’ ‘end-of-life,’ ‘overstressed’) identifying the reliability violation driving the immediate need reliability project insufficient to comply.”

FERC said it was not requiring “an exhaustive description” but said PJM “may provide details regarding the specifics of the violation; why the violation arose; when it first occurred; the implications of the violation in terms of generation, load, congestion, etc.; the severity of the problem; and expectations for the violation’s severity in the future (i.e., will the problem get worse or have a cascading effect at a later point in time).”

The commission also cited PJM for failing to post a “full and supported written description” on any decision to award a project to an incumbent transmission owner, including an explanation of other transmission or non-transmission options that the RTO considered and the cause of the need and why it was not identified earlier.

‘Little Insight’

“The TEAC presentation materials provide little insight as to PJM’s reasoning,” the commission said. ” … In addition, we find that PJM does not provide in its presentation materials an explanation for its determination that there was insufficient time to open a full or shortened proposal window.”

Going forward, FERC said, PJM must “expound on its description to support the designation of its immediate need reliability projects, specifically addressing the time-sensitive nature of the need, why the incumbent transmission owner was selected, alternatives considered and why the need was not identified earlier. … PJM could also explain the urgency of the violation and compare it to the typical timeline of a standard or shortened competitive proposal window, explaining how the proposal window would delay the solution further.”

Although its prior order did not specify how much time PJM should allow stakeholders to comment on project descriptions, FERC said the RTO’s practice of posting materials three days before meetings at which the projects are to be discussed “is not sufficient.” It noted that the RTO gives stakeholders 10 days to review materials for supplemental transmission projects under its Attachment M-3 process.

“As a result, we direct PJM to submit a compliance filing to designate a specific time period greater than three days for stakeholders to provide comments in response to the project description,” it said.

PJM also failed to provide transparency in addressing stakeholder questions about immediate need projects, FERC said, ordering the RTO to post on its website all stakeholder comments and PJM answers, “whether provided in writing or submitted verbally at TEAC meetings.”

The commission also said PJM must make it easier for stakeholders to locate information on immediate need projects, noting that the RTO has put such information in more than 60 locations on its website. “While we do not find that PJM must post all immediate need reliability project information to a single webpage to meet the transparency requirements … we direct PJM to post all information regarding immediate need reliability projects in a manner that is more easily accessible to stakeholders than the current approach.”

‘Reasonable Balance’

The commission rejected other requested relief, including LS Power’s request to eliminate the immediate need exemption and the New Jersey Board of Public Utilities’ request that the commission hold a technical conference to determine whether it should continue to allow other exemptions from competition such as those for lower voltage projects and substation equipment.

The commission noted PJM’s statement that it is working to reduce the use of immediate need designations by improving the efficacy of its five-year model. PJM said improved modeling and testing has already begun to reduce the use of immediate need designations. In 2019, PJM said that it reported only eight immediate need reliability projects — totaling 11 baseline upgrades.

FERC also declined a request to shorten the three-year time threshold for immediate need projects, saying it “continues to strike a reasonable balance” between reliability and competition.

In addition, it rejected LS Power’s request to exclude “end-of-life” projects from the immediate need category. LS Power said EOL projects represent a large portion of immediate need designations.

The commission also refused LS Power’s request to require transmission owners to provide PJM with information on EOL projects seven years in advance and American Municipal Power’s call for more frequent and timely submission of information by TOs on load changes to aid system modeling.

“We make this determination because such a requirement is outside the scope of the proceeding. We expect that, as PJM has committed to do, PJM will continue to improve its processes, to both timely receive the relevant system information from transmission owners and timely incorporate this information into its planning models, to potentially reduce reliance on the immediate need reliability project exemption,” FERC said. (See related story, PJM Stakeholders Pass End-of-Life Proposal.)

SPP, ISO-NE Cleared

FERC terminated the Section 206 investigations into SPP and ISO-NE, saying they had not produced evidence that the RTOs were implementing the exemption “in a manner that is inconsistent with or more expansive than the commission directed.” It noted that no stakeholders had accused either RTO of violating their tariffs.

SPP said that it had designated only five transmission projects as “short-term reliability projects” out of 144 projects identified in its Integrated Transmission Planning studies since study year 2016.

The Public Utilities Regulatory Authority had argued that ISO-NE’s need-by dates are artificially early because the RTO performs its needs assessments under assumptions more conservative than those used by day-to-day operations. But FERC said ISO-NE had “sufficiently justified” its approach. The RTO explained that its operators do not have to respect certain contingencies if they don’t have impacts outside of the local area where they occur. It also said the operators have access to a wider range of equipment ratings and system operating conditions than are allowed in transmission planning.

Several New England state agencies, including the attorneys general for Massachusetts and Connecticut and the Maine Public Advocate, said FERC should find ISO-NE’s exemption unjust and unreasonable because the region was the only RTO that had not completed a competitive transmission procurement. “Although ISO-NE’s lack of a competitive solicitation was one reason the commission instituted this proceeding, this outcome is not a sufficient reason to find the relevant Tariff provisions unjust and unreasonable,” FERC said. (On June 8, the RTO announced that it would recommend a project by incumbent utilities National Grid and Eversource Energy as the lone finalist in its first competitive solicitation.)

The commission also rejected arguments regarding the efficiency of New England’s transmission spending, its accommodation of non-transmission solutions and its “reactive” planning process as beyond the scope of the proceeding.

June 19, 2020

Pandemic Operations Steady, MISO Members Report

MISO members say that work-from-home measures and social distancing mandates in workplaces aren’t generally impeding their pace of work, but they do miss the personal collaboration afforded by in-person meetings.

The RTO asked Advisory Committee members to discuss how the novel coronavirus has impacted their company operations during a June 17 teleconference.

“COVID has impacted every industry, every business around the world,” MISO Vice President of Strategy and Business Development Wayne Schug said in opening the discussion.

He asked stakeholders “what a path to normality” looks like for their companies, or if they could even return to complete normalcy.

“Once the stay-at-home orders were in effect, many of us found ourselves at home, probably taking way too many virtual meetings,” Schug said.

According to a MISO surv e y, only about 14% of member companies had had more than 25% of their workforce working remotely before the pandemic hit. Now, most MISO member companies have more than a quarter of their employees reporting from home.

“In large part, our projects are on schedule. There have been some delays to accommodate this new work environment,” Otter Tail Power’s Stacie Hebert said, referring to rescheduled public meetings and temporarily closed courthouses.

DTE Energy is returning employees to the field to resume maintenance work, the company’s Manager of Wholesale Power Markets Nick Griffin reported.

MISO pandemic — DTE Energy’s Nick Griffin | © *RTO Insider*

North Dakota Commissioner Julie Fedorchak said it was at first difficult to maintain the pace of the commission’s work remotely while still honoring open meeting requirements. However, state commissions now largely have the remote format down pat.

“I think commissions got to the point where they could do just about anything,” Fedorchak said, adding that her commission had already been laying the groundwork for more virtual meetings prior to the pandemic.

She said the commission was able to honor all biweekly regular meetings, as well as permitting and routing meetings, while many employees worked from home. She also said about 75% of commission staff have returned on-site.

When MISO Director Todd Raba asked what member companies do when employees come down with a COVID-19 infection, multiple members said their companies have yet to confront that situation. Griffin noted that cases among DTE Energy’s 11,000 employees jumped from about 50 to about 200 “after an isolated incident at one of our power plants.”

Audrey Penner said her fellow Manitoba Hydro employees would return to offices “not earlier than the end of the summer.”

Director Barbara Krumsiek asked how member companies are preparing for a possible second wave of infections in the fall.

Many companies are targeting a return to work at year’s end or spring of 2021, Griffin responded.

“I would expect more telecommuting practices even after the pandemic,” he said.

Missing Meetings

Schug asked how MISO members are faring under an entirely virtual stakeholder process.

LS Power’s Pat Hayes said an online stakeholder process has been working “rather well,” though connectivity during meetings sometimes lags. “Of course, you’re hearing some dogs bark and some family conversations in the background.”

Hayes also lamented an inability to directly interact with people at meetings and make personal connections. He wasn’t alone.

“It’s about getting to know people in the process. But it’s also about when you have a differing opinion, maybe meeting in the hallway to have a follow-up, asking clarifying questions, having a meeting of the minds,” Beth Soholt of Clean Grid Alliance added.

“It’s impossible to read body language,” said CMTC’s Kevin Murray about virtual meetings.

“A lot of the work that we do is based on in-person interaction,” noted Travis Stewart of Gabel Associates, who requested that MISO find a way to facilitate more spontaneous conversations.

“I dearly miss sitting around a table and the congeniality,” Penner said of quarterly MISO Board Weeks. “I’m looking forward to getting back into a room together.”

MISO has halted all in-person stakeholder meetings at its offices through the end of the year. Offsite meetings — such as Board Week — have also largely been converted to a virtual format, though RTO executives hold out hope that the December Board Week in Orlando may yet be spared. MISO has also begun allowing employees back on-site on a voluntary basis at its three office locations.

MISO also plans to hold virtual Nominating Committee meetings through November, where new MISO board candidates are vetted and selected for member voting.

Directors Theresa Wise and Baljit Dail will reach their term limits at the end of the year. Wise is eligible to serve another three-year term, while Dail has already exceeded his total three-term limit through a special waiver in 2017, which was granted to retain his IT expertise. (See “Committee Permits Consideration of Extra Term for Dail,” MISO Bo D Briefs: June 22, 2017.)

“We miss seeing you in the auditorium. We’re doing this virtually, but we’d much rather do it in person. As soon as it’s safe to do so, we’re going to resume these,” Board Chair Phyllis Currie said during the June 18 board meeting.

Difficult Times

Schug asked how companies are considering stressed-out ratepayers under the pressure-cooker combination of the pandemic’s economic fallout and social and racial justice protests in every state.

“There’s a lot of pressure on customers right now … manifesting in a lot of ways,” Public Consumer Advocates Sector Representative Christina Baker said. “… The economic effect is going to be around for years to come.”

She said “all customers — not 1% of customers” are experiencing stressors related to the pandemic and the push for societal change.

“For the customers it’s a much broader, longer, multilayered time for them,” Baker said.

Krumsiek agreed: “For the end-use customer, there’s no return to normal. Our vulnerable populations for COVID run along the same lines as those affected by racial injustice.”

Schug asked if MISO members anticipate a slowdown in the political push for renewables and carbon reductions given the political and social turmoil.

“I don’t anticipate a reduction in demand for renewable energy because of the pandemic. I really don’t,” Fedorchak said.

Soholt also expects carbon reduction goals to continue as planned.

“I think our sector expects to see some of these issues percolate up in integrated resource plans,” she said, adding that a renewable buildout could put some people back to work.

In the MISO footprint, load dipped by about 11% during the country’s strongest lockdown measures. Now, Schug said load is currently trending about 5% below weather-adjusted norms.

Murray said his clients are experiencing different load recoveries. For instance, he said steel companies, automobile manufacturing and oil and gas production have been significantly dragged down. Other manufacturers are less affected.

Further waivers of MISO Tariff requirements might still be necessary, Griffin said. MISO has so far put together a waiver of load modifying resource registration deadlines for the capacity auction and a 60-day grace period on the June 25 deadline to demonstrate exclusive land use for some generation projects in the interconnection queue. (See MISO Dr a fts COVID-19 Waiver for LMRs.)

“We’d like MISO to remain flexible,” he said.

June 19, 2020

MISO Board Addresses Racism, Social Unrest

MISO made a rare foray into addressing political and social events Thursday when its CEO and board members condemned systemic racism and vowed to listen to minority employees in order to effect organizational change.

Board Chair Phyllis Currie said directors and executives had engaged in “considerable discussion” in a closed session about the “long-term disparate treatment of African Americans by the police and in the workforce.”

“These issues impact our employees, so in turn, they impact MISO,” Currie said during the virtual board meeting.

“Obviously, racism and prejudice still exist, and we need to eradicate them in all their forms,” Director Baljit Dail said.

“Obviously, we’ve all been shocked into realizing there’s so much more to do,” added Director Barbara Krumsiek. She said the board will be more open to adopting actions to assist MISO employees and go further in promoting diversity.

The board’s comments come about three weeks after Minneapolis resident George Floyd was killed while in police custody, galvanizing racial justice protests that have reverberated around the world.

A boarded-up storefront in downtown Indianapolis following protests on May 31. MISO’s headquarters are located in nearby Carmel, Ind. | © *RTO Insider*

During the meeting, Director Mark Johnson reflected on a recent blog post his daughter wrote on experiencing racism.

“Being an African American parent, you try to insulate them from the racism. But it’s unavoidable that anything you try to do, they will experience it,” Johnson said.

“It’s a community in pain right now,” CEO John Bear said of African Americans. Bear said MISO has recently instituted all-hands meetings discussing systemic racism and historical inequalities. He also said the RTO’s leaders plan to embark on “listening tours” inside the company.

Bear also lauded the U.S. Supreme Court’s recent dec i sion granting protected class status to gay and transgender employees.

“I am proud of the diversity on our board and in our senior leadership. … But I think we can take that much further,” Bear said.

“This is not a flash; this is something we will press on,” he promised.