NERC: COVID-19 is Chance to Test GridEx Lessons

By Holden Mann

Last year’s GridEx V security exercise provided the electricity industry with a number of lessons about crisis management that are proving timely in the current COVID-19 pandemic, according to NERC officials.

“One of the reasons we do exercises like this is so we are prepared to deal with significant challenges, and we are certainly in one now,” said NERC Senior Vice President and CEO of the E-ISAC Manny Cancel at a media briefing on NERC’s after-ac t ion report on the exercise. “And certainly, some of the lessons we learned from GridEx and the procedures that we practiced [have] prepared us for dealing with COVID-19, specifically the business continuity procedures that we and our entities have in place.”

NERC conducted GridEx V, the fifth of its biennial exercises, on Nov. 13-14, 2020, drawing more than 7,000 participants from more than 526 organizations across the industry and government — up from 6,000 participants and 450 organizations for GridEx IV. Organizations were asked to respond to a wide array of threat vectors representing what one PJM official called a “true doomsday scenario.” (See GridEx V Throws Ne w Tech Curveball.)

Distributed Play Borrows from Life

The exercise had two major components. First was a distributed play model involving players from across the electricity industry, as well as government officials and representatives from interdependent industries such as natural gas, water, finance and telecommunications. The two-day exercise presented participants with a range of simulated challenges including social media hacks, vehicle fires at regional facilities, intruders in headquarter buildings and infections by malware.

NERC COVID GridEx — An unnamed staffer at NERC’s Electricity Information Sharing and Analysis Center (E-ISAC) participates in day one of GridEx V. | *NERC*

In creating the distributed play scenario, planners drew heavily on lessons learned in previous exercises as well as from real-world crises. For example, the malware that attacked participants was patterned after the 2016 CrashOverride cyber-attack against Ukrainian utilities, a choice inspired by the malware’s targeting of industrial control systems (ICS) intended to cause chaos in the electric grid.

“When the exercise planners … were putting this together, the ICS component of CrashOverride in 2016 provided a lot of great training value to the industry,” said Matthew Duncan, senior manager of resilience and policy coordination for E-ISAC. “We had very good feedback from the utilities, seeing this malware that they could [respond to] in an exercise environment and really test their defense capabilities against it.”

Executive Tabletop Brings Needed Focus

The distributed play model was accompanied by an executive tabletop session with participation by leaders of electric, natural gas and telecommunications industries, along with senior government officials. While this has been a feature of previous exercises, this year the executive tabletop featured, for the first time, a separate scenario from the distributed play. In addition, unlike in previous events, the scenario was focused on a regional rather than a national threat, which organizers hoped would create more useful response data.

“In previous GridExes having the entire nation and continent under attack made it difficult to get down to the technical detail necessary [to model an effective response],” Duncan said. “By picking the Northeast, New York State and Southern Ontario, we were able to get sufficient detail to play this out, and it was very helpful.”

Recommendations from the executive tabletop included the following:

Ensure grid emergency response and restoration plans describe coordination with federal and state or provincial authorities in the event of a national security emergency;
Incorporate natural gas providers and pipeline operators into restoration planning and drills;
Enhance coordination with communications providers to support restoration and recovery and work to ensure the 6-GHz spectrum communications band remains open to utilities in emergencies;
Build consensus with the Department of Energy on procedures and requirements for issuing grid security emergency orders;
Identify key supply chain elements and ensure inventory can be shared in a crisis;
Expand participation in the Electricity Subsector Coordinating Council (ESCC) cyber mutual assistance (CMA) program; and
Strengthen industry and government coordination between the United States and Canada.

Supply Chain Participation Falls Short

NERC set seven objectives for GridEx. The organization reported that six of these were fully achieved: practice incident response plans, expand local and regional response, engage interdependent industries, improve communication, engage senior leadership and gather lessons learned.

The seventh objective, increase supply chain participation, was only partially achieved. NERC had hoped to expand engagement with the vendor supply chain in GridEx V after calling out utility operators in GridEx IV for failing to recognize the importance of maintaining vendor support. (See Ukraine Attacks, ‘Fake News’ Color NERC Grid E x IV Drill.) However, only three major electric industry supply chain vendors officially registered for the most recent exercise. While more vendors may have participated unofficially, NERC said that organizations must work harder to include these critical industry players in their response plans.

Organizations are already planning for GridEx VI, scheduled for Nov. 16-17, 2021. MISO has begun selecting internal committees to design scenarios and lead simulations for the next exercise. (See MISO Preps for G r idEx VI.) Duncan said future GridEx planning will continue to draw from current events such as the COVID-19 pandemic to ensure that the industry is as ready as possible.

“We say that GridEx is designed to overwhelm even the most prepared utilities, and we use realistic scenarios to keep making the industry better,” Duncan said. “There’s no shortage of threats out there, but the only way we’re going to get better at mitigating and defending against those threats is [by] practicing against those threats, and that’s what GridEx is all about.”

March 31, 2020

FERC Conditionally OKs Purchase of EPE

By Tom Kleckner

FERC on Monday conditionally approved an investment fund’s $4.3 billion purchase of El Paso Electric, directing the companies to file a mitigation plan addressing market power screen failures (EC19-120).

The Infrastructure Investments Fund (IIF), Sun Jupiter Holdings and EPE announced the transaction last June. FERC is the final regulatory body to sign off on the deal, which was approved by the Texas and New Mexico utility commissions earlier this year. (See Texas PUC Approves EPE’s $4.3B Sale.)

At issue before FERC was IIF US Holding’s ownership of the 595-MW Mesquite natural gas plant in Arizona. All the plant’s capacity is committed to third parties.

Mesquite currently sells 271 MW to 20 parties under a power purchase agreement, with the balance of the plant’s capacity sold to other parties not affiliated with IIF or Sun Jupiter. The PPA’s term is set to terminate at the end of April 2021, when it will be replaced by a PPA that increases the volume of capacity committed under the contract to 483 MW. (IIF US Holding is one of three master partnerships that hold all investments for IIF, an open-ended infrastructure fund.)

JP Morgan EPE — EPE’s Rio Grande Plant in Sunland Park, N.M. | *El Paso Electric*

The applicants submitted an “alternative analysis” of the Mesquite plant that assumed early termination of the PPA, which would result in more generation capacity from Mesquite becoming available for sale in the EPE balancing authority area under IIF’s control, resulting in market screen failures for the region. FERC said the screen failures are “significant and occur in moderately to highly concentrated markets,” indicating reduced competition. It directed the applicants to file a mitigation plan within 45 days that addresses the potential adverse effects on competition.

The commission found the transaction would not have an adverse effect on rates, noting it will retain its authority to approve EPE’s rates for jurisdictional services and the state commissions will regulate its retail rates.

The commission rejected calls by Public Citizen for an evidentiary hearing over the transaction’s complexity and the web of financial affiliates involved. Sun Jupiter is the sole shareholder of Merger Sub, a corporation formed for the purpose of merging with and into EPE, with EPE as the surviving entity. Sun Jupiter is an indirect, wholly owned subsidiary of IIF Sun Jupiter Ultimate Holdings.

J.P. Morgan Investment Management officials advise and help manage IIF’s portfolio of 19 companies. EPE would become part of that portfolio. IIF and EPE officials have argued that does not mean J.P. Morgan is a legal affiliate of IIF or any IIF entities. The commission agreed with the applicants’ assertion that any affiliation between the IIF companies with J.P. Morgan would not change its analysis under the Federal Power Act.

“Even if there are disputed issues of material fact in a proceeding, the commission is not obligated to establish an evidentiary hearing if [it] can determine whether the proposed transaction is consistent with the public interest based on the written record,” FERC said. “[The applicants] have demonstrated that even if Sun Jupiter were affiliated with J.P. Morgan or any of its affiliates, such affiliation would not change the outcome of the commission’s analysis.”

March 31, 2020

PJM MRC Moves Forward on Storage, Hybrids

By Michael Yoder

PJM members last week advanced efforts to integrate the growing volume of energy storage and hybrid resources in the RTO, endorsing one issue charge and hearing a first reading of another at Thursday’s Markets and Reliability Committee meeting.

The MRC approved an issue charge to consider using effective load-carrying capability (ELCC) to set the capacity value of limited-duration resources such as battery storage. The initiative, which will be run by a new Capacity Capability Senior Task Force (CCSTF) reporting to the MRC, was approved by acclamation with one objection.

Alternative to 10-hour Minimum Run Time

PJM’s Andrew Levitt said ELCC, which was already under consideration for solar and wind resources, could be an alternative to the 10-hour minimum run time requirement for storage that was rejected by FERC in October.

FERC partially approved PJM’s Order 841 compliance filing but set a paper hearing to determine whether its 10-hour minimum for storage seeking capacity obligations was unjust and unreasonable. (See FERC Partially OKs PJM, SPP Order 841 Filings.)

In February, PJM requested the hearing be held in abeyance until Jan. 29, 2021, when it hopes to file Tariff changes applying ELCC to capacity storage resources. FERC responded March 2 by extend ing the deadline for initial briefs to April 27 and reply briefs to May 27. It said it could extend them further depending on its ruling on PJM’s request (EL19-100). “We’re optimistic” FERC will approve the request, Levitt said.

ELCC, which is already used by MISO, NYISO and CAISO, evaluates reliability in each hour of a simulated year and compares a resource mix with limited resources against one with unlimited resources. A resource that contributes a significant level of capacity during high-risk hours will have a higher capacity value than a resource that delivers the same capacity only during low-risk hours.

Levitt said the new senior task force will build on previous Planning Committee discussions on using ELCC for intermittent resources.

“We thought there was enough similarity there that it made sense to put them all under the same effort,” Levitt said. “The new senior task force we’re considering here to start with is essentially a blank slate, although one that is informed by prior efforts.”

Phase I of the effort will focus on solar, wind and energy storage, including batteries and pumped hydro. Phase II, expected to begin in 2021, will cover all other intermittent and limited-duration resources, including hybrids and resources for which part of the capacity is limited-duration and part is unlimited.

Brian Kauffman of Enel N.A. praised PJM’s strategy for resolving the storage issue. “I think it will save a lot of money and resources to have this discussion at PJM rather than in front of FERC,” he said.

Jim Davis of Dominion Energy said he appreciated PJM splitting the process into two phases, especially when looking at hydro resources. “We view run-of-river … as different than pumped storage and other types of storage,” he said.

Hybrid Resources Issue Charge

PJM’s Scott Baker presented a first read of an issue charge that would create a new senior task force to clarify how existing rules for intermittent and energy storage resources would apply to inverter-based solar-battery hybrids. The task force would also consider new requirements needed to incorporate hybrids into PJM markets. The committee will be asked to endorse the issue charge at its next meeting on April 30.

There are more than 10,000 MW of co-located generation and energy storage hybrid resources in the PJM interconnection queue, Baker said, and more than 95% of those megawatts are solar-battery hybrids.

“Given the amount of solar-battery hybrid resources in the interconnection queue and the existing rules clarification and gaps needed to be addressed for this resource type prior to operation in the PJM market, it is recommended that this work begin immediately and that the senior task force target completion of its work by the end of 2020,” the issue charge says.

Some areas are being considered out of scope of the issue charge, Baker said, including PJM’s implementation of compliance with FERC Order 845, stakeholder engagement related to the FERC directive regarding capability of energy storage resources in the capacity market and providing new capabilities to “toggle” the accounting for solar output between sales to PJM and the self-supply to the battery component.

Pete Fuller of Autumn Lane Energy Consulting asked why some of the items are being considered out of scope and when they may be addressed going forward.

Baker said other PJM committees are working on Order 845 compliance and that issues surrounding battery technology would make the initiative too complex to be resolved on an expedited timeline.

“It’s our preference to keep it out of scope just because we think that they are complicated enough that it may slow down the effort,” Baker said.

Ken Foladare of Tangibl thanked the PJM staff for bringing forward the issue charge. “With the entrance of hybrid resources recently into the PJM queue, we think it’s very important to clearly define the market rules for these resources and also to educate PJM stakeholders on the different configurations and how they affect the PJM grid,” Foladare said.

March 31, 2020

PJM MRC/MC Briefs: March 26, 2020

Markets and Reliability Committee

Compliance Hotline Announced

PJM Board of Managers Chair Ake Almgren opened the Markets and Reliability Committee meeting Thursday by introducing a redesigned compliance hotline for RTO personnel and stakeholders to anonymously report violations of laws, regulations or RTO rules.

Almgren said the RTO broadened the existing PJM employee hotline as part of its commitment to a “ethical conduct and the culture of compliance.” Anonymous callers can send tips on violations of the PJM Employee Code of Conduct, RTO governing documents, FERC orders and NERC reliability standards.

The hotline (1-866-776-6942), which will be operated by an independent third-party organization (Navex Global), can also be used to report issues with PJM’s financial reporting.

“In addition, credit risks to the organization that are not being addressed by PJM may also be reported to the hotline,” Almgren said. An independent investigation of the 2018 GreenHat Energy default concluded PJM staff ignored red flags about the company’s assets and exhortations from other members.

Posters highlighting the hotline will be hung around the PJM campus beginning next month.

“I believe the compliance line provides another way for PJM to achieve transparency and continue communications with members and stakeholders,” Almgren said.

Paul Sotkiewicz of E-Cubed Policy Associates called the hotline “an absolutely fabulous idea.”

“We should have had it much earlier in the game,” he said.

Sotkiewicz asked how much authority the third party has to serve as a “mediator” to resolve issues brought to its attention.

“I’ll have to come back to answer that more precisely,” Almgren responded. “The idea is to have an escalation.”

The question –and –answer document for the hotline states that the PJM board “has a formal escalation policy — like that of many of our member companies — that requires certain types of concerns to be escalated promptly to the board. Then the board has the ability to direct the next steps including engaging other independent outside expertise to investigate or otherwise assist with the resolution of the concern.”

The Code of Conduct outlines rules for PJM employees on subjects including conflicts of interest, receiving gifts and maintaining confidentiality. Employees are prohibited from accepting gifts worth more than $150 in any 12-month period and must report all gifts exceeding $50 to Ombudsman Jim Burlew.

The code says the third party will relay details of calls to the ombudsman with a copy to General Counsel Christopher O’Hara. Depending on the nature of the concern, the ombudsman may relay the information to the director of business operations, the director of internal audit, the director of human resources or the senior director of physical security and facilities, “who will conduct a prompt, impartial and thorough investigation.”

“If the violation involves a subject matter which may impact the ability of individuals who should otherwise receive a report to be impartial, the situation will be investigated accordingly,” it says.

PJM declined to say how many calls the existing hotline has received in the past year.

Shift to IMM Opportunity Cost Calculator

Stakeholders approved a compromise p r opos a l to eliminate use of the RTO’s opportunity cost calculator and make the Independent Market Monitor’s calculator the required tool for market sellers. The action will take effect beginning June 1.

The proposal was approved on an acclamation vote with one abstention.

The new policy required changes to Manual 15: Cost Development Guidelines to document the Monitor’s calculator and provides for an annual review of the calculator to ensure compliance with the manual and Operating Agreement. (See “PJM Seeks to Retire Opportunity Cost Calculator, Use IMM Tool,” PJM MRC/MC B r iefs: Feb. 20, 2020.)

The calculator is intended to ensure generators are made whole for being scheduled by PJM outside their most profitable time periods.

An opportunity cost adder can be included in a cost-based offer when a unit faces environmental restrictions on how much they can operate, an equipment manufacturer imposes an operational restriction because of equipment limitations, or the unit faces a fuel limitation resulting from a force majeure event. The value of the adder is based on historical LMPs and forecasted future fuel prices.

Jim Davis of Dominion Energy thanked PJM officials for the change.

“It seems like we’ve been talking about these things for not just months, but years,” Davis said. “We look forward to the continued discussion and documentation as changes are made to the calculator.”

Black Start Resources Initiative on Hold for 4-8 Months

PJM said it could take eight months or longer to complete additional analysis in the contentious initiative that could tighten fuel requirements for black start resources.

The RTO told stakeholders March 2 that the initiative would go on “hiatus” for up to six months to conduct the analyses, as requested by the Organization of PJM States Inc. (OPSI). (See PJM Backs off Black Start Fuel Rule.)

But PJM’s Janell Fabiano told the MRC that the analyses could take four to eight months, and possibly longer, because of the need to reconsider the prioritization of other pressing issues in light of the COVID-19 pandemic.

PJM plans to analyze restoration times, the impact of gas supplies costs and economic impact. It called for the initiative in 2018, noting that the only fuel assurance requirement for black start resources is that they maintain enough for 16 hours of run time.

The RTO has estimated that requiring 100% of black start units to have a secondary fuel source would require $513 million in capital spending, increasing annual revenue requirements by $67.2 million over the current $65 million. A proposal that would limit such fuel assurance requirements to one resource per transmission owner zone is estimated to cost $13 million, or $1.9 million per year.

Manual Changes OK’d

The MRC endorsed six manual changes, including updates from periodic cover-to-cover reviews and updated procedures:

Manual 12: Balancing Operations as part of a periodic review.
Manual 13: Emergency Operations as part of a periodic review.
Incorpo r ated changes to Manual 14A: New Services Request Process, Manual 14E: Upgrade and Transmission Interconnection Requests and Manual 14G: Generation Interconnection Requests, related to FERC Order 845 on generator interconnection procedures and agreements.
Manual 22: Generator Resource Pe r formance Indices as part of a periodic review.
New sections in Manual 33: Adm i nistrative Services for the PJM Interconnection Operatin g Agreement for member roles and responsibilities and contact management and company account manager roles and responsibilities. Some existing sections were relocated.
Manual 37: Reliability Co o rdination as part of the periodic review.

Members Committee

Voting Rule Waived

The Members Committee unanimously approved one-time revisions to Section 11.11 of Manual 34 regarding voting requirements for board elections in response to the cancellation of PJM’s annual meeting originally scheduled for May 4-5 in Chicago.

Section 11.11 calls for votes on board members to be taken by secret paper ballot by those at the meeting and by secret ballot over the phone for members participating by teleconference, PJM’s Dave Anders said.

Anders said that because this year’s meeting will now take place solely by teleconference, the members have been left with an “untenable situation” with collecting votes over the phone. PJM suggested a one-time waiver of the requirement of a secret ballot to allow the use of the RTO’s voting application.

In response to members’ concerns to keep the vote secret, Anders said PJM staff will delete the record of individual votes immediately after tabulating the results.

Some members suggested using an independent third party to tally the votes.

Anders said using a third party was a legitimate suggestion for future votes but would be difficult to implement in time for the May vote.

The revision passed unanimously by acclamation.

January Minutes Still not Approved

The minutes for the Jan. 23 MC meeting were not approved for a second consecutive month. Initially the minutes weren’t approved at the February meeting because they weren’t posted in time.

Sharon Midgley of Exelon requested Thursday that the minutes not be approved because of potential “voting anomalies” at the meeting. Midgley said she relayed questions to PJM after the meeting regarding the vote, but the voting discrepancies have not been resolved and are still being investigated.

Anders confirmed that Midgley had told the RTO that a member who voted at the January meeting may be affiliated with another member. The member organization was not identified.

Anders said PJM is working with legal staff to resolve the inquiry by Midgley. He said he had no issues with deferring the approval of the January minutes until the next meeting scheduled for May 4.

“Our concern is around two companies who appear to potentially be affiliates that both participated in the voting at the MC that day,” Midgley explained after the meeting.

Liaison Committee Meeting Rescheduled

Katie Guerry, vice chair of the MC, said the Liaison Committee meeting with the board scheduled for April 21 has been rescheduled until July. Guerry said members decided it was “not a responsible decision” to move forward with an in-person meeting for April because of the COVID-19 pandemic and have instead looked to have it in the summer. An additional Liaison Committee meeting will also be added on the calendar for December, Guerry said, so that four meetings can still be held within the calendar year.

Guerry also said PJM officials are considering whether to re-evaluate priorities in the MC Annual Plan because of the pandemic.

“There’s a mindfulness of the reality of the situation that we are all in and the limited resources that we all have,” Guerry said. “We want to minimize the burden on folks in this extreme time.”

New Finance Committee Member Elected

Mike Peters of industrial and medical gas producer Messer LLC was selected to fill an open position on the PJM Finance Committee within the End Use Customer sector.

Peters will fill the seat vacated by George Waidelich of Safeway, which recently left PJM membership. Peters’ term expires at the end of 2020.

— Michael Yoder

March 31, 2020

Revised Fuel-cost Policy Approved by PJM MC

By Michael Yoder

The PJM Members Committee approved cha n g es Thursday to the RTO’s fuel-cost policy (FCP) rules, but not before another round of animated debate over force majeure events.

The new rules, which are spelled out in revisions to Schedule 2 of the Operating Agreement and Manual 15: Cost Development Guidelines, were approved by a sector-weighted vote of 3.9 (78%).

The package, proposed by the PJM Industrial Customer Coalition, was approved by the Markets and Reliability Committee last month on a sector-weighted vote of 3.57 (71%) despite concerns that new safe harbor provisions would create loopholes permitting the exercise of market power. (See PJM MRC OKs Revised Fuel-cost Policy.)

PJM fuel-cost policy — Heat rate and cost curves for 550-MW natural gas-fired team unit | *PJM*

It eliminates the FCP annual review, the FCP requirement for zero-marginal-cost offer units, and market seller submission deadlines. The deadlines for reviewing FCPs was changed: The Independent Market Monitor will have an initial 10 business days to review a policy and an additional five business days when a market seller revises the policy. PJM will have 20 business days to review a policy and an additional five business days for reviewing revisions, although that time frame can be changed if agreed to by PJM and the market seller.

The ICC included a safe harbor provision proposed by generators but modified the terms for imposing penalties for noncompliance. It would impose the full penalty if the unit clears in the day-ahead market or runs in real time on a cost-based offer and is paid day-ahead/balancing operating reserves. The full penalty also would apply if the unit fails the three-pivotal-supplier (TPS) test for constraints or the cost offer is above $1,000/MWh.

Susan Bruce, representing the ICC, said the concerns raised in February about the proposal “resonate with industrial customers,” but she said she will continue to support the measures.

“We offered [changes] in the spirit of compromise, and we believe that compromise is an essential element of the stakeholder process,” Bruce said.

The safe harbor section of the proposal allows a generator to avoid penalties if it deviates from its FCP because of a force majeure event.

PJM will determine whether the evidence proves the force majeure event “directly impacted the market seller’s ability to conform to the methodology” in its FCP. “The applicability of this provision shall not apply for economic hardship nor obviate the requirement for a market seller to submit cost-based offers that are just and reasonable, and utilize best available information to develop fuel costs during a force majeure event,” the revised OA says.

Greg Poulos, executive director of the Consumer Advocates of the PJM States, cited concerns over the safe harbor provision in requesting a sector-weighted vote on the proposal, saying he was surprised to see the revisions listed in the consent agenda because it had been the subject of a contentious vote at the MRC. “Many of us will be voting ‘no,’” he said of his group’s members. He said he would like to see PJM create a policy on what items can be included in the consent agenda.

Monitor Joe Bowring said he continued to oppose the revised force majeure language because no one has identified an event that would prevent market sellers from following their fuel-cost policies. With the emergence of the COVID-19 pandemic since February’s meeting, he said, sellers could argue “that every single fuel-cost policy would now be moot.”

“There’s actually no reason to have a force majeure exception, and the current state of the world indicates that even more clearly,” Bowring said. “The proposal is equivalent to not having any fuel-cost policies now and having every single unit be subject to unit-specific review based on the actual facts. That is not workable. The purpose of fuel-cost policies is to address unusual and unexpected conditions, and current fuel-cost policies do that.”

Paul Sotkiewicz of E-Cubed Policy Associates disagreed with the classification of the current pandemic, saying he believed it was “alarmist and also wrong” to use the coronavirus as a force majeure event because there have been no issues in getting pricing for fuels.

“I think the fuel-cost policies are still in effect here, even with the coronavirus,” Sotkiewicz said. “It’s a scare tactic.”

March 31, 2020

Major MISO Tx Projects Face Various Hurdles

By Amanda Durish Cook

Two market efficiency transmission projects already approved by MISO face continued obstacles, while two others slated for belated inclusion in the 2019 Transmission Expansion Plan must wait longer for approval, stakeholders heard last week.

Speaking during a conference call of the Board of Directors’ System Planning Committee on March 24, MISO Executive Director of System Planning Aubrey Johnson said uncertainty lingers for the nearly $129 million Hartburg–Sabine Junction project because of the passage of a Texas law granting incumbent utilities the right of first refusal for any transmission projects built in the state. The law may mean incumbent Entergy ultimately takes up the project. (See Appeals Court Sets Dates in Texas ROFR Challenge.)

The RTO is currently using its established variance analysis process to study the project and developments around it. The analysis is used to study projects already approved under the MISO Transmission Expansion Plan that are later disrupted by circumstances that affect the project’s cost, schedule or “the ability of selected developers and transmission owners to complete.”

“We are now continuing to gather information as part of the variance analysis and continuing to work with legal teams,” Johnson said.

The proposed 23-mile 500-kV transmission line, four short 230-kV lines and new substation would connect three county networks in East Texas and alleviate longstanding congestion and import limitations in the area.

MISO has acknowledged the recent court action, but confidentiality restrictions limit its ability to talk publicly about the project. Spokesperson Allison Bermudez said the RTO will make a further statement once it completes the variance analysis, which is expected soon.

“MISO is committed to delivering the benefits of the Hartburg-Sabine Junction transmission project in East Texas. Under our Tariff, MISO is currently executing a process to assess the Texas state law developments and their impact on the project,” Bermudez told RTO Insider earlier this month.

Huntley-Wilmarth Costs Up

MISO is similarly conducting a variance analysis on the nearly $156 million Huntley-Wilmarth line, which now faces cost overruns after a route change.

Huntley-Wilmarth met the criteria to qualify as a market efficiency project in MISO’s 2016 Transmission Expansion Plan. It would have been open to competitive bidding if not for Minnesota’s right-of-first-refusal law. Original estimated costs on the project ranged from $88 million to $108 million.

MISO said costs increased 30% because of state-ordered changes to the routing plans. The new permitted route will cross the Watonwan River in Minnesota.

Johnson said a variance analysis is automatically triggered when a project experiences cost overruns of more than 25% of original baseline costs.

MISO President Clair Moeller said the analysis is performed to provide a clear public record of the project, not to re-evaluate its merits or halt work.

“Once we approve a project, we don’t really have the ability to stop it,” Moeller said.

MISO executives said they believe Huntley-Wilmarth will still be able to deliver benefits in excess of its cost.

Meanwhile, MISO’s first competitively bid project from 2016 — the $67 million Duff-Coleman 345-kV transmission project in Southern Indiana — is making progress and could be completed as early as June 2020.

MISO-PJM Interregional, 1st SATA Projects not yet Approved

Two holdover projects from MTEP 19 have yet to receive the board approval MISO hoped for by March.

MISO’s first-ever storage-as-transmission project is now on hold after MISO SATOA Proposal Set for Technical Conference.)

“We will not seek approval until Tariff revisions are approved,” Johnson said, noting that MISO staff must first attend a technical conference that will probably be set for late spring.

American Transmission Co.’s Waupaca area energy storage project was meant to ease transmission reliability issues in central Wisconsin.

“What happens — is this project just in limbo? So how do we deal with the congestion that this project was supposed to alleviate?” Director Nancy Lange asked.

Vice President of System Planning Jennifer Curran said MISO wants to “let the process play out a little more” before it decides on a direction or project alternative. She said it is in communication with the developer in the meantime.

MISO also faces more work before the board can approve its first major interregional market efficiency project with PJM.

The $22 million reconstruction of the 138-kV Michigan City-Trail Creek-Bosserman line in the northwestern corner of Indiana can save about $5 million in congestion costs per year, MISO said. (See MISO, PJM Poised for 1st Major Interregional Project.) PJM’s Board of Managers has already approved the project.

But MISO doesn’t yet have an approved regional cost allocation for interregional projects with PJM. FERC rejected its newest interregional cost allocation filing in late March, finding the proposal to reserve regional allocation for market efficiency projects 230 kV and above ignored the potential regional benefits of lower-voltage projects. MISO proposed that its share of interregional economic projects with voltages below 230 kV — but at or above 100 kV — be allocated 100% to the transmission pricing zones where the project is located, barring lower-voltage projects from cost-sharing.

Before the order, MISO staff said the Michigan City-Trail Creek-Bosserman project would not be regionally allocated in, reasoning that the project’s 138-kV rating disqualified it from a regional allocation.

The commission ordered MISO to instead use a design based on adjusted production costs for economic interregional projects 100 kV and above with PJM. MISO has a month to make the filing. (See “Interregional Filing Also Rejected,” Another Rejection for MISO Cost Allocation Plan.)

MISO will submit the filing within FERC’s 30-day deadline, Johnson confirmed. He said the wait for FERC’s response would probably push approval of Michigan City-Trail Creek-Bosserman to MISO’s June Board Week.

March 31, 2020

FERC OKs Broader Market Protections for MISO

FERC on Thursday approved MISO’s proposal to bar participants from its market when it identifies evidence of default, manipulation or unreasonable risk. The new procedures took effect Saturday (ER20-877).

The Tariff changes allow MISO to request additional collateral when it perceives an unreasonable credit risk from a market participant. The new rules will also allow the RTO to reject applications from new market participants and from former market participants that have an uncured financial default in its markets and attempt to rejoin under a different name.

Finally, the RTO will ask prospective and current market participants for more specifics on their annual certifications. It will inquire about past defaults, bankruptcies, dissolutions, mergers or acquisitions and any investigations. (See MISO Looks Beyond FTRs for Market Protections.)

MISO Market Protections — MISO control room | *MISO*

“The proposed revisions will allow MISO to improve the protection of its market participants from financial losses that result from unreasonable credit risks and defaults while also providing additional clarity and transparency to market participants,” FERC said.

The commission also pointed out that MISO has pledged to “preserve in writing” any decision it makes to reject or suspend a market participant from participation. FERC said the RTO’s written reasoning could “form a record before a commission proceeding if necessary.”

FERC said MISO made the filing “in light of significant credit events in other” RTOs/ISOs, referencing GreenHat Energy’s record default in PJM’s financial transmission rights market in June 2018. PJM last week approved tightened credit requirements to prevent future defaults. (See related story, PJM Members OK Tighter Credit Rules.)

The revisions are an extension of stepped-up requirements in MISO’s FTR market. The RTO received FERC permission in November to apply higher collateral requirements to the market (ER20-73).

— Amanda Durish Cook

March 31, 2020

Board OKs 11th MISO Sector, Orders Redesign

By Amanda Durish Cook

MISO’s Board of Directors last week cleared the Advisory Committee to create an 11th stakeholder sector while also instructing the committee to overhaul its sector design to produce a fuller participatory model.

The board said the committee’s recent recommendation to create a new “Affiliate” sector for hard-to-define members works only in the short term. It directed it to develop a long-term solution that guarantees all members full participation in the stakeholder process. (See MISO Advisory Committee OKs 11th Sector.)

In the meantime, MISO should file with FERC revisions to its Transmission Owners’ Agreement (TOA) to include the new sector, the board said.

Board Chair Phyllis Currie said the board met to discuss the proposal and agreed that it should be in place only until the AC creates a new proposal focused on fair participation for sectors and mindful of voting power. She also said the AC should ensure that sectors are divided into groupings of likeminded members.

MISO 11th Sector — The MISO Advisory Committee last March | © *RTO Insider*

“I say ‘short term’ because I think in the longer term, there still needs to be more discussion on how various sectors participate,” Currie said during a committee conference call Wednesday. The meeting took place via conference call instead of in New Orleans as originally planned because of the spread of the COVID-19 coronavirus. (See Virus Fear Sends MISO Board Week to the Web.)

Currie urged the AC to examine its current voting structure and think about affording members an equal voice. She said the board would give the committee a year to draft a fuller solution for incoming — and increasingly diverse — members.

The new sector would not be allowed a vote in either AC or Planning Advisory Committee matters, but it would have one designated seat for AC meetings and be allowed to offer opinions during the committee’s quarterly hot topic discussions.

The sector would serve as a home for any MISO member that isn’t participating in another sector. Prospective MISO members must declare a sector affiliation before they can join the RTO.

“I think other interest groups, other businesses, other NGOs will come to the table,” Director Nancy Lange told the AC.

The AC began debating the merits of an 11th sector last year when Lignite Energy Council, a North Dakota coal lobbying group, approached MISO about membership. The organization did not fit neatly into any of the existing 10 sectors and was almost relegated to the Environmental and Other Stakeholder Groups sector. But some AC members said it wasn’t appropriate for a sector to contain entities with diametrically opposed views and said the new sector was necessary to allow the Environmental/Other sector to have a singular voice. The Environmental/Other sector would be able to drop its “other” designation if FERC accepts the changes to the TOA.

Environmental/Other sector representative Beth Soholt said that, save for the Energy Storage Association, all other entities in the sector have an environmental focus.

So far, the proposed Affiliate sector seems destined for a fossil-fuel focus — at least at the onset. LEC indicated that it has drummed up interest among other entities interested in joining the new sector, including coal and iron mining organizations, coal trade organization America’s Power and various chambers of commerce.

LEC CEO Jason Bohrer said his organization had been “working on earning a seat at the table for the past 18 months.” He said the board’s decision was “a significant step in this long process.”

“We applaud the work of the MISO Advisory Council, the Board of Directors and MISO staff, as well as our partners like America’s Power, for their support of opening up the regional market planning stakeholder process to more voices and perspectives, which now will include coal producers along with chambers of commerce and other organizations that have strong electricity market interests,” Bohrer said in an email to RTO Insider. “We look forward to providing a strong voice for the coal miners and utilities who provide the electricity that is the ‘always-on’ backbone for the electric grid and the economy in our region.”

Hot Topic Panel Delayed

On the same conference call, the AC postponed the policy discussion portion of its meeting until June.

The committee was supposed to hold a panel-style discussion featuring industry experts as its quarterly hot topic discussion during the March Board Week. The panel was meant to focus on how RTOs deal with resource transition and would have featured one executive apiece from NYISO, CAISO and ERCOT. However, AC leadership said a panel discussion was too difficult to navigate in a teleconference-only format.

March 31, 2020

Renewable Tax Credit Extensions Not in Stimulus Bill

By Michael Brooks

The wind and solar industries were disappointed last week that Congress’ massive $2 trillion stimulus bill did not include extensions of the production and investment tax credits.

In a joint letter to Congress, the American Wind Energy Association (AWEA) and the Solar Energy Industries Association (SEIA) said the COVID-19 coronavirus pandemic was causing “delivery delays, necessary employee absences, serious financing concerns, and project cancellations or postponements. This is jeopardizing the jobs of our combined 364,000 workers, threatening to sidetrack tens of billions of dollars in investment.”

President Trump on Friday signed the bill, the largest stimulus legislation in U.S. history, as shelter-in-place rules grind the U.S. economy to a near halt.

The major provisions of the Coronavirus Aid, Relief and Economic Security (CARES) Act (S. 3548) include $1,200 checks for millions of taxpayers “as rapidly as possible”; programs to disburse nearly $900 billion in loans to business impacted by the pandemic; and an expansion unemployment benefits.

AWEA CEO Tom Kiernan said “relief provisions ensuring renewable projects can secure financing and meet safe harbor continuity schedules are critical to preserving a strong domestic clean energy sector. Making these adjustments to existing tax credits would provide the industry the flexibility needed to accommodate COVID-19 delays, without costing the federal government any additional money. … Without assistance, 35,000 American jobs, $43 billion of investment and $8 billion in payments to local communities are at risk.”

renewables stimulus bill — President Trump signed the CARES Act on March 27. | *The White House*

SEIA CEO Abigail Ross Hopper acknowledged that some of the bill’s provisions for individuals and displaced workers would benefit solar industry workers. But she warned that “as a result of this pandemic, the solar industry stands to lose half of our jobs.”

The tax credit extensions were also not part of a separate bill introduced by House Democrats while Senate leaders and Treasury Secretary Steve Mnuchin negotiated over the Republican-crafted CARES Act, though the House bill did include emission limitations for airlines. When Democrats blocked passage of the Senate bill March 22, Majority Leader Mitch McConnell (R-Ky.) the next day falsely accused them of holding up the bill over the extensions and emission limits.

“Democrats won’t let us fund hospitals or save small businesses unless they get to dust off the Green New Deal,” McConnell said. “They’re continuing to hold up emergency measures over tax cuts for solar panels.”

In truth, McConnell was outraged by Democrats blocking a procedural motion on the bill after he had rallied his caucus members to bite their tongues and pass a House Democrat-crafted bill the week before as an initial response to the crisis. Minority Leader Chuck Schumer (D-N.Y.) and his caucus were likewise peeved that Republicans had included a $500 billion fund in the CARES Act to bail out corporations harmed by the crisis without any oversight provisions. The partisan rancor led to a rare, actual debate on the Senate floor, between McConnell and Sen. Joe Manchin (D-W.Va.).

After two days of negotiations, however, the Senate ended up passing the bill early Wednesday morning, 96-0. The House of Representatives followed on Friday, passing the bill by voice vote, rather than unanimous consent off the floor as Speaker Nancy Pelosi (D-Calif.) and Minority Leader Kevin McCarthy (R-Calif.) had wanted, after Rep. Thomas Massie (R-Ky.) indicated he would object and attempt to force members to record their votes.

This forced 218 members of the House to travel back to D.C., some of whom drove to avoid flying, to assemble a quorum to block Massie’s motion — this despite the Centers for Disease Control and Prevention’s advisory not to have 10 or more people gathered in one place.

Trump signed the bill into law hours after the House passed it.

March 31, 2020

FERC Denies AMP Request for OASIS Waiver

By Rich Heidorn Jr.

FERC last week rejected AMP Transmission’s request for a waiver of the commission’s Standards of Conduct and requirements to maintain an Open Access Same-Time Information System (OASIS) (TS19-1).

AMP Transmission (AMPT) is an affiliate of American Municipal Power that was created to own and operate the transmission facilities of AMP and AMP’s members. AMP has purchased a 138-kV ring bus from the city of Napoleon, Ohio, and plans to purchase a similar transmission facility from Wadsworth, Ohio, both less than 50 feet in length. It also owns a 1.84-mile, 69-kV transmission line and two 69-kV station facilities in Amherst, Ohio.

AMPT said it qualified for a waiver of the OASIS and Standards of Conduct requirements because its facilities are “limited and discrete,” geographically dispersed and do not form a contiguous network.

FERC AMP OASIS — American Municipal Power headquarters in Columbus, Ohio | *American Municipal Power*

AMPT said its transmission function employees work independently from AMP’s marketing function employees and that it has contracted with Gridforce Energy Management to provide NERC transmission compliance services.

But PJM and its Transmission Owners sector told FERC the waiver should be rejected because the marketing affiliates of AMPT will have access to nonpublic transmission information through its participation in the PJM Transmission Owners Agreement-Administrative Committee and other committees where planning or operational transmission information is discussed.

The TOs said that if the commission approved the waiver, it should prohibit AMPT from participating in PJM activities and TO meetings in which nonpublic transmission information is disclosed or discussed, noting that Old Dominion Electric Cooperative committed to similar conditions when it sought waivers from the commission.

The TOs expressed concern that a waiver would give AMP the ability to use nonpublic information available to PJM transmission operators to benefit AMP’s merchant trading — the kind of behavior the Standards of Conduct’s no-conduit rule was designed to prevent.

The commission agreed.

“We find that an entity like AMPT that participates as a transmission owner in an RTO or ISO cannot qualify for waiver of the commission’s OASIS or Standards of Conduct requirements on the basis that its facilities are limited and discrete,” FERC ruled. “Although AMPT’s facilities are limited in size, AMPT’s participation as a transmission owner in PJM qualifies its facilities as an integral part of the integrated PJM grid and therefore AMPT’s facilities cannot be considered as limited and discrete under our waiver precedent.”