Page 1107 – RTO Insider

October 22, 2018January 18, 2024

SPP MOPC Briefs: Oct. 16-17, 2018

LITTLE ROCK, Ark. — SPP’s Market and Operations Policy Committee last week unanimously approved staff recommendations to revise the SPP-MISO Coordinated System Plan by eliminating the RTOs’ joint transmission model and the $5 million minimum cost threshold on interregional projects, while adding adjusted production cost and avoided-cost benefit metrics.

The RTOs have told their stakeholders they will use only their individual regional planning models to evaluate interregional projects. Members on both sides of the seam have complained that a “triple hurdle” has contributed to the lack of interregional projects. (See MISO, SPP Loosen Interregional Project Requirements.)

“We have concerns … about getting rid of the joint model, because it is clear up front that the joint model will determine the way costs are allocated,” The Wind Alliance’s Steve Gaw said. “We lose that stability in the new process, and it remains to be seen if efficiency gains in the new process will outweigh this risk.”

MOPC Endorses Battery Storage as Market Participant

The committee endorsed several market design changes for SPP’s compliance filing with FERC Order 841.

RR323 defines batteries as electric storage resources (ESRs), capable of being dispatched and participating in price formation. Excluded as ESRs are those resources that are either contractually barred or physically incapable of injecting energy back onto the grid because of their design or configuration.

The Tariff change also creates a new registration type, “market storage resource,” to be used only by ESRs. The resources are not required to use the MSR model but must specify ancillary services offered — e.g., energy, regulation up, regulation down, spinning reserves and/or supplemental reserves — and provide at least a tenth of a megawatt to be eligible for any market product.

“The resource can be committed as a charging resource or as a non-charging resource. It’s no different than a regular resource,” SPP’s Yasser Bahbaz said. He pointed out that pumped hydro, a non-charging resource, already qualifies as an ESR.

Renewable interests were hoping to see more on capacity accreditation but were satisfied to learn that the Supply Adequacy Working Group is considering a four-hour accreditation for ESRs. Existing governing language allows ESRs to qualify for capacity credits if the resource meets the planning criteria’s testing requirements.

The measure passed with 10 abstentions.

“Our impression is this has gone little bit beyond what we need to do to comply with the FERC order,” American Electric Power’s Richard Ross said, explaining his company’s abstention. “[SPP] already [has] a storage resource, and it seems to have found a way to operate under the current guidelines.”

The MOPC also approved tweaks to the Market Working Group’s RR266, which modeled joint-owned units as single resources and the committee had approved in July. “Ownership” was changed to “interest,” recognizing that the former term doesn’t capture stakeholder intent that power purchase agreements and other non-ownership interests be included.

Stakeholders approved the change with one abstention.

MOPC Approves 2 Revised Futures in 2020 Study

The committee agreed with the Economic Studies Working Group’s recommendation to study only two futures in its 2020 Integrated Transmission Planning assessment: a reference case and an emerging technologies scenario.

It also agreed with the ESWG that there is no need to study a third future that assumes a carbon adder or carbon-emissions reduction and accelerated emerging technologies. The third future would have increased the 2020 ITP’s study costs, adding about 6,600 consulting hours.

ESWG Chair Alan Myers, with ITC Holdings, said many of the third future’s assumptions will be included in SPP’s first 20-year assessment, which will begin in 2022. “That might be a good vehicle for studying these types of things,” he said.

Staff will use the 2019 ITP’s two futures as a starting point, adding fossil fuel retirements, ESRs and an increase in utility-scale solar and wind additions to the original assumptions. Both futures will assume coal plants retire at 56 years old, a decrease of four years over previous assumptions.

“We think the shift from 60 to 56 [years] … is definitely a movement in the right direction,” said Keith Collins, executive director of SPP’s Market Monitoring Unit, which has joined the ESWG’s discussions. “But [based on] what we’re seeing in other markets, it’s not [reducing] it enough.”

Collins favored including the third future, saying SPP’s market indicates that uneconomic resources are likely operating, as evidenced by the self-commitment of generation and negative prices.

“The economics Keith talks about are driven by the inability of a coal plant to recover its fixed costs,” Board of Directors Chairman Larry Altenbaumer said. “To a large extent, that fixed cost is subject to the regulatory environment that exists. I’m not at all convinced Future 3 is the right way to [address] that.”

SPP Updates Members on Western RC Effort

Peak Reliability’s decision to cease operations may slow SPP’s pursuit of the Mountain West Transmission Group, but it is also giving the RTO some business with the group.

Operations Vice President Bruce Rew told stakeholders the 16 entities who have signed up for SPP’s reliability coordinator services include all original Mountain West members: Black Hills Energy (Black Hills Power, Black Hills Colorado Electric Utility Co. and Cheyenne Light Fuel & Power); Colorado Springs Utilities; Platte River Power Authority; Tri-State Generation and Transmission Association; the Western Area Power Administration (Rocky Mountain Region and Desert Southwest Region); and Xcel Energy’s Public Service Company of Colorado.

Xcel’s surprise April announcement that it was leaving the Mountain West shelved SPP’s integration of the group. (See Xcel Leaving Mountain West; SPP Integration at Risk.)

That news was followed up by Peak’s decision in June to wind down its RC operations by the end of 2019. (See Peak Reliability to Wind Down Operations.)

The other entities who have signed up with SPP are: Arizona Electric Power Cooperative; the city of Farmington, N.M.; El Paso Electric; Intermountain Rural Electric Association, in Colorado; Tucson Electric Power; Arlington Valley, in Arizona; and Griffith Energy, also in Arizona.

SPP will continue strengthen its toehold in the West with its RC services, expanding its footprint to 16 states with the addition of Arizona and Utah.

SPP’s Western RC will serve approximately 20% of the non-CAISO load in the Western U.S., accounting for 100 TWh of net energy for load, Rew said. A Western Reliability Executive Committee and a Western Reliability Working Group will provide governance. Three task forces have already been formed: Congestion Management and Seams, RC Readiness and West Modeling.

Rew said the groups are currently populating the transmission models, with the hopes of exchanging real-time data with transmission owners, balancing authorities and neighboring RCs by May 1, 2019. The Western RC is scheduled to begin shadow operations with Peak by Oct. 1, with the cutover set for Dec. 1, 2019.

Rew also briefed the MOPC on the major operations events with MISO in January and September, calling the latter a “success story” because of the improved coordination between the RTOs.

Unseasonably warm conditions in mid-September led to higher loads than forecast in SPP’s southern region and in MISO South. When several units tripped, MISO was forced to call a maximum generation alert and a Level 2 Energy Emergency Alert on Sept. 15. SPP sent 300 MW of emergency assistance for three hours to help resolve the situation. (See MISO: Sept. Emergency Response Improved by Jan. Event.)

“With our operational preparations, we were able to make it through,” Rew said.

HITT Group Continues its Education Sessions

The Holistic Integrated Tariff Team has moved into a second phase of education, listening to and discussing presentations by various stakeholders as it eyes an April 2019 deadline for delivering a report on the optimal alignment of SPP’s planning processes, cost-allocation methodologies, and market products and services.

The team, which reports to the board, was only formed in April. (See SPP’s Tariff Team Begins Carving up the Elephant.)

“I won’t disagree that it’s an ambitious schedule,” said SPP General Counsel Paul Suskie, who serves as the HITT’s staff secretary.

The HITT expects to begin its third phase in December, when it will begin drafting its recommendations to the board and Members Committee.

The team meets next Oct. 23 and has scheduled meetings through April 2019.

The meetings continue to be limited to team members, with those stakeholders not delivering presentations “encouraged” to call in to listen.

Suskie acknowledged the lack of face-to-face interaction and stakeholders’ complaints about technological problems during conference calls. “We tried to line the meetings up with board meetings as best we could, but we haven’t been able to do that,” he said.

Competitive Transmission Group Kept on Standby

The committee agreed to keep the Competitive Transmission Process Task Force on “hot standby” rather than disband it, should a future Order 1000 issue deserve its attention.

Several committee members agreed with the group’s recommendation that it disband, saying its work has been completed. But task force Chair Bill Grant, of Southwestern Public Service, argued the group’s expertise should be leveraged by keeping it on standby, rather than disbanding it.

“We had a pretty balanced group of people who had transmission experience and know how projects are put together. We also had financial people who could look at and analyze bidding forms,” he said. “If MOPC wants to disband and bring it back up if needed, I would caution you that we have the right people at the table.”

Formed in 2015, the CTPTF picked up where a previous task force left off to revise SPP’s Tariff to comply with FERC’s 2011 order introducing competition to transmission development. The group has worked to improve the competitive process following the first two solicitations, neither of which resulted in an approved project.

Admin Cost Recovery Looks at Demand, Energy Charges

Evergy’s John Olsen, chair of the Schedule 1A Task Force, told the MOPC his group will propose revisions to SPP’s administrative fee recovery mechanism at the committee’s January meeting. Olsen said that timeline would give members a year to work with their regulators before final revisions are filed with FERC in 2020.

Olsen said the group favors a mix of demand and energy charges, with market costs recovered through energy charges and planning costs recovered through demand charges. Contested issues include scheduling and dispatch costs and what “determinants” should be included in cost allocation calculations, he said.

“The debate has been whether generators or loads pay for all cost,” Olsen said.

He shared a picture of Grant and Tenaska’s John Varnell, wearing seemingly identical plaid shirts and body language during a task force meeting.

“That’s what five hours of talking about denominator billing determinants will do to a person,” Olsen said, drawing laughs.

The task force has been asked to simplify the rate structure and include energy transactions into the design. The RTO’s administrative fee of 42.9 cents/MWh is budgeted to recover $164 million in the current budget year. The administrative fee is collected on contracts between transmission providers and customers. Point-to-point contracts are billed against reserved transmission capacity, and network service is billed against the prior year’s average monthly zonal peak. (See SPP Stakeholders to Study Admin Fee Changes.)

MOPC Approves Order 845 Compliance Language

The MOPC easily endorsed the Regional Tariff Work Group’s revisions to the pro forma large generator interconnection procedures and large generator interconnection agreement to comply with FERC Order 845. The commission’s order is designed to address delays in interconnection queues, a common complaint among SPP’s membership.

RTWG Chair David Kays, with Oklahoma Gas and Electric, said Revision Request 325 will not be filed until a pending rehearing request before the commission is resolved, which would likely add another 90 days to the timeline.

The vote was unanimous, with only ITC abstaining.

Consent Agenda

The MOPC rejected a change to the ITP’s operational model development, agreeing that ESWG/TWG RR317 would be undoing the Transmission Planning Improvement Task Force’s work.

The change would have removed the day-ahead reliability unit commitment to evaluate economic flowgates in planning models. It was removed from the consent agenda, with two members abstaining from the vote.

The committee unanimously approved the rest of the agenda, which included 10 revision requests, updates to the 2019 ITP assessment’s scope, removal of references to the SPP Regional Entity from the MOPC’s scope, the MWG’s annual violation relaxation limits analysis, and charter changes for the Operating Reliability, Operations Training Project Cost and Regional Compliance Working Groups. (RR318 was discussed separately but also passed unanimously.):

BPWG RR319: Standardizes market import service (MIS) over all SPP ties by adding MIS to the Miles City DC tie in Montana, which is partially owned by the Western Area Power Administration.
ESWG/TWG RR321: Cleans up several items, grammatical errors and small improvements in the ITP manual that were discovered since its approval.
MWG RR288: Allows non-dispatchable variable energy resources converting to dispatchable to use control statuses not originally available to them. SPP’s control statuses are: offline (the resource is not operating); non-regulating (online and capable of following a dispatch instruction or contingency reserve deployment but not eligible to clear regulation service); regulating (online and capable of following dispatch or contingency reserve instruction, and regulation deployment); and manual (online but not able to follow dispatch; e.g., start-up, shutdown, testing, etc.).
MWG RR316: Updates the multi-configuration (combined cycle) resource market design by adding two additional commitment parameters: group minimum down time and plant minimum down time. Also removes sync-to-min and min-to-off times from the submitted minimum down time or group minimum down time when the resource transitions between operational configurations. The current design only allows individual registered configurations to submit a minimum down time.
MWG RR328: Allows the automation of out-of-merit energy and RUC make-whole payment calculations when a contingency reserve deployment test is issued.
MWG RR332: Corrects protocol calculations from designs implemented in RR200 (design change for bilateral settlement schedules and over-collected losses (OCL) distribution) and RR235 (correction to RR200) necessary to ensure bilateral settlement schedules are receiving their correct OCL. The change — which also must be approved by the Regional Tariff Working Group — ensures corrected resettlements back to the original May 1, 2018, release date. The RTWG next meets Oct. 25.
MWG RR333: Modifies four charge types necessary to implement RR229 (FERC Order 831 compliance) and discovered by staff during a recent settlements system replacement project. It also must go before the RTWG for approval.
ORWG RR318: Changes the contingency reserve requirement calculation to allow the use of the “most severe single contingency” as the basis of the minimum contingency reserve requirement on an hourly basis. SPP said the revision allows it to more accurately and reliably set the reserve requirement.
RTWG RR305: Updates Tariff language following modifications to the aggregate facilities study process by removing the requirement to file a service agreement before modeling new transmission service in the ITP models. Also removes the requirement that SPP issue notifications to construct (NTC) and notifications to construct with conditions (NTC-C) before filing a service agreement. Adds a financial commitment date of four years to the issuance of an NTC or NTC-C.
RTWG RR322: Changes the Tariff and other documents to reflect that the RTO is no longer using U.S. Energy Information Administration data in monthly load forecasts. SPP said the data in the EIA report are not granular enough because they are at the balancing authority level, rather than the local balancing authority level required. In January, the RTO began using forecast data that are available through the NERC system data exchange (SDX) and historical data where forecasts are not available.

— Tom Kleckner

October 22, 2018

SPP Strategic Planning Committee Briefs: Oct. 18, 2018

LITTLE ROCK, Ark. — SPP Board of Directors Chair Larry Altenbaumer last week unveiled a proposal to reduce the number of face-to-face meetings and add more executive sessions, saying it would improve the board’s focus on its strategic plan.

SPP Chair Larry Altenbaumer shares his thoughts on changes to the Board meetings. | © *RTO Insider*

While no final decisions have been made, Altenbaumer told the Strategic Planning Committee he is proposing adding two executive time slots to the board and Members Committee’s quarterly meetings and eliminating the two non-quarterly face-to-face board sessions. The executive time would be used for discussions with the state regulators’ Regional State Committee and the Members Committee.

Altenbaumer called the changes part of the board’s “broader evolution,” but that he was sensitive to concerns about taking discussions behind closed doors. He said the executive sessions are not intended to be decision-making meetings but will improve the quality of the discussions.

“Does this reduce the transparency of the organization? We want to be very much on guard that does not happen,” Altenbaumer said. “We want to ensure that in the forums where decisions are made that all stakeholders have the opportunity to participate. I think [meeting with] an outside resource in a smaller setting provides a greater quality of interaction.”

The new chairman, who took his position at the head of the table following April’s board meeting, said he was driven by the outcome of efforts to integrate the Mountain West Transmission Group. SPP received pushback late in the process from the RSC and members, who felt cut out of some of the earlier discussions.

The work to integrate Mountain West is officially ongoing, but most Western entities are now focused on securing reliability coordination services from SPP and CAISO with the pending shutdown of Peak Reliability. (See Peak Reliability to Wind Down Operations.)

“Despite a lot of effort and a ton of meetings [with Mountain West], I think we failed at effectively communicating with both the RSC and our members,” Altenbaumer said. “I had a lot of one-on-one interactions with members to address an issue. On many strategic issues, there is a variety of opinions on how those items need to be addressed. If we can facilitate a discussion with all members on the Members Committee, we’ll get a more robust discussion and up-front direction for all our stakeholder groups to address those issues.”

Altenbaumer said the organizational strategy should be determined by the board and Members Committee, but he remarked, “I don’t think we’ve always acted as owners of that strategy.” He said he prefers setting aside time to “discuss matters of strategic importance” in place of quarterly reports.

The chairman reassured the SPC that it is still the committee responsible for developing SPP’s strategic plan.

“This is where the technical expertise resides,” he said. “I hope there will be dialogue back and forth to ensure we’re discussing issues of strategic matters.”

Altenbaumer wants to eliminate the board’s June education session and the December meeting in which the board approves the budget. The December meeting would become a conference call.

He is also proposing the board delegate to the Markets and Operations Policy Committee decisions “that need not be brought to the board.”

SPC Takes No Action on Clean Energy Rule

The committee decided not to have SPP provide comments on EPA’s proposed Affordable Clean Energy (ACE) rule, determining there is little to be gained, but much to lose.

In explaining the ACE rule to the SPC, Vice President of Engineering Lanny Nickell said the rule is “less onerous” than the Obama administration’s Clean Power Plan, which required a 32% cut in emissions below 2005 levels by 2030.

SPP’s Lanny Nickell (r) discusses the proposed Affordable Clean Energy rule as Director Mark Crisson takes notes. | © *RTO Insider*

The ACE rule applies only to existing coal-fired plants and does not set a federal carbon-emission rate, requiring states to set unit-specific standards, Nickell said.

“From a reliability perspective, it’s a lot more flexible and easier to anticipate than output limitations,” he said.

Nickell conducted several CPP studies after its 2014 release. The final analysis indicated that a state-by-state compliance approach could result in nearly 40% higher costs than a regional approach.

Nickell said there is no reason for SPP to study the ACE rule’s “rate-based approach” or to issue a statement. “I don’t have any personal concerns about its reliability implications,” he said. EPA has issued an Oct. 31 deadline for public comments.

SPP Director Phyllis Bernard in discussion with Evergy’s Denise Buffington. | © *RTO Insider*

“We haven’t made a quantitative analysis” of the new rule, he pointed out. “It would be an opinion we are offering, what we think the implication of ACE would be. We would be making an opinion without a quantitative analysis.”

“I love you guys, but you’re thinking like electrical engineers rather than politicians,” said Director Phyllis Bernard, who has a strong background in administrative law. “Your opinion, while qualitative, is far superior from the opinion of someone out there who is putting out spin. You can make a difference. If you say nothing, the default position may go back to something you don’t want to hear. If you think something in the proposed rule is positive, you should say that.”

Several members urged SPP to rely on the facts — no reliability impact; the market is producing emission-reductions through the dispatch of cleaner fuels — and provide comments.

“If you don’t say anything, someone will go on the record and dictate the final rule,” said Basin Electric Power Cooperative’s Mike Risan.

“Once we say something, it invites questions,” Altenbaumer countered. “One of the first questions I would ask is, ‘How can you make that assertion if you haven’t done any studies?’ I don’t know why you go down that path if there are no benefits, other than a feel-good.”

Mike Ross, SPP’s senior vice president of government affairs and public relations and a six-term member of the U.S. House of Representatives for Arkansas, cautioned against going public with comments on the rule.

“If we’re not careful, we’re going to be labeled pro-environment or anti-environment, pro-coal or anti-coal, pro-Trump or anti-Trump. That’s not our job,” Ross said.

“Our job is to be fuel agnostic and let the markets choose the fuel source and to focus on reliability. The proposed rule by this administration is going to be adopted, whether we comment or not, and since it won’t impact reliability, I don’t think we should comment. It’ll be tied up in the courts for years. When we are trying to make decisions on 40- and 50-year assets, our country needs a national energy policy that transcends administrations and political parties.”

Asked whether the ISO/RTO Council has weighed in on the ACE, CEO Nick Brown noted that the industry group was silent on the CPP.

“It’s certainly not going to step up as a group and comment on this, as it doesn’t appear to have any impact on the bulk power system,” Brown said.

— Tom Kleckner

October 22, 2018

SPP Stakeholders Stop Work on Unreserved Tx Waiver

By Tom Kleckner

LITTLE ROCK, Ark. — SPP stakeholders last week directed the Seams Steering Committee to stop work on proposed Tariff changes that would have granted a waiver from charges for unreserved transmission use across the seams.

The Market and Operations Policy Committee’s action during its Oct. 16-17 meeting means SPP’s current practices for unreserved use will continue. They have resulted in about $23,000 in service charges since 2016, but only when that unreserved use is reported to the RTO.

The revision request (RR308) would have granted transmission customers a four-hour grace period for unreserved service during an unplanned transmission outage. SPP’s Tariff and its business practices do not allow exemptions for transmission customers using the RTO’s system to take transmission service because of outages, whether planned or unplanned.

The SSC was unable to reach a consensus during its monthslong discussions, with some members saying temporary use of interconnected systems should be a benefit and others calling for transmission owners to be compensated. The four-hour grace period was a compromise position.

“Several members thought the four-hour grace period was at least some justification to take this to FERC and stakeholders,” American Electric Power’s Jim Jacoby, chair of the SSC, told the MOPC. “It seemed to have at least some backing. From an AEP perspective, that’s a benefit of interconnected systems. We ought to give customers some time [to arrange service during an unplanned outage].”

SPP attorney Mike Riley | © *RTO Insider*

RR308 received little support from SPP’s legal department. Associate General Counsel Mike Riley pointed to excerpts from FERC Orders 890 and 890-A, which address situations where a customer is unaware of changing conditions that result in additional service requirements. Riley said FERC’s language does not exempt “any class of transmission customer from the potential assessment of unreserved use penalties” and refers to entities “serving native load in multiple control areas.”

“Not being a FERC commissioner, it’s hard to say what the [language] is intended to cover, but when I read words like ‘multiple control areas,’ that seems applicable to us,” said SPP’s David Kelley, director of seams and market design.

“If SPP and the stakeholders have a basis for filing and justifying this four-hour window, or grace period, we’ll absolutely file it,” Riley said. “But based on 890’s provisions, where FERC appears not to make a distinction between reserved use and unreserved use, we’ve got an uphill battle.”

Riley agreed with the concept of a grace period before assessing penalties, saying it should be a business practice in the Tariff.

“We just haven’t seen or found a justification that would get us over the 890/890-A hurdle, but it’s up to FERC,” he said.

Several members suggested SPP could conform its practices with those of MISO — which Southwestern Public Service’s Bill Grant said MISO does not apply unreserved charges in similar situations — through their joint operating agreement. But Kelley pointed out, “Even if we address this issue through the JOA, we’ll still have to make a filing at the commission. We still have to get around the hurdles of what we’re arguing.”

“This is not being applied consistently,” Grant said. “Only when SPP knows about it.”

“What we’re trying to do is address the unfortunate bystander that doesn’t know what’s going on, and only finds out about it when they get a bill,” AEP’s Richard Ross said.

On the sidelines, some members referred to the TOs who reported unreserved use as “tattletales.”

The MOPC’s motion passed over 10 opposing votes and five abstentions.

October 22, 2018

SPP Generator Interconnection Group Wraps up Work

By Tom Kleckner

LITTLE ROCK, Ark. — SPP members last week approved one of two Generator Interconnection Improvement Task Force recommendations but took no action on the second and agreed to disband the group.

The task force was formed last year to identify improvements in the RTO’s transmission study process, which is backlogged with more than 62 GW of interconnection requests. Its work will be carried on by various working groups.

The Market and Operations Policy Committee approved the GIITF’s suggestion to address generator interconnection studies in regions where the amounts of new generation being requested exceed load during spring and other light load periods.

SPP currently divides its footprint into cluster groups for individual study. In the high variable energy resource case, all VERs inside the cluster are set to 100% of capacity while external VERs are set to 20% to simulate counterflow to the internal generation.

With the increase in VERs, the amount of counterflow contained in the Integrated Transmission Planning models is high enough that the simulation is no longer needed, and the 20% setting has resulted in situations with insufficient load to absorb all the generation being requested. Under the new rules, the external VERs remain at the base reliability dispatch setting used in the ITP process.

“The changes here allow the energy to flow a further distance to a neighboring zone, which should identify [needed] transmission upgrades,” said Tradewind Energy’s Derek Sunderman.

Task force Chair Al Tamimi, of Sunflower Electric Power, said the change “might help us move forward with [definitive system impact studies].” Staff is working on study requests that date back to 2015.

OG&E’s Greg McAuley (right) states his position as AEP’s Richard Ross listens. | © *RTO Insider*

“That should tell us something,” Oklahoma Gas & Electric’s Greg McAuley said. “We’re dancing around the problem. We have too much generation coming in, and we have no place to put it.”

McAuley pointed out that the Holistic Integrated Tariff Team is also working on the problem. “We don’t know where they’re going to land,” he said.

The measure passed with six opposing votes, mostly from transmission owners, and 14 abstentions.

Members declined to take a vote on the GIITF’s recommendation to change the criteria for allocating network upgrade costs to interconnection customers by adding a new energy resource interconnection service (ERIS) criterion.

Under the proposal, SPP would have first allocated cost responsibility to requests with 20% or more of the generator’s output flowing across a constrained element, as under current practice.

After applying the 20% transfer distribution factor (TDF) test, the proposal would have added a second screening to determine which requests have at least a 5% TDF. If the number of such requests resulted in a cumulative TDF of 20% or more, a mitigation would be assigned to the cluster, with the cost allocated to those requests with at least a 5% TDF.

SPP said the change would have resulted in the identification of four additional constraints in the DISIS-2016-001 study.

But several members said the recommendation didn’t go far enough in identifying constraints caused by interconnection requests. Staff agreed the current process doesn’t catch enough constraints.

The committee also accepted a storage white paper for incorporation into SPP’s generator interconnection processes. The document describes proposed rules for processing and evaluating storage interconnection requests. Two members opposed the motion and three abstained.

October 22, 2018

Overheard at Storage East 2018

WASHINGTON — Infocast’s inaugural Storage East summit drew policymakers, grid operators, utilities and companies looking to break into energy storage to the Washington Plaza Hotel last week. Panelists discussed the optimism surrounding the industry, as well as strategies for locating resources and optimizing their services for maximizing returns.

Infocast’s inaugural Storage East summit was held at the Washington Plaza Hotel in D.C. on Oct. 16-17, 2018. | © *RTO Insider*

Here’s some of what we heard.

Chatterjee Touts FERC Orders

FERC Commissioner Neil Chatterjee delivers the keynote address of the conference. | © *RTO Insider*

FERC Commissioner Neil Chatterjee kicked things off by recalling actions the commission has taken on storage since he joined in August 2017. The highlight of these was the February issuance of Order 841, which directed RTOs and ISOs to revise their tariffs to allow energy storage resources full access to their markets. (See FERC Rules to Boost Storage Role in Markets.)

When Chatterjee joined FERC as chairman, he restored the commission’s quorum, which it had been without for six months. He said he had expected to be able to vote on a final version of the commission’s November 2016 Notice of Proposed Rulemaking as soon as he walked in, but he found that staff were still working on “a number of complex, legal and technical issues.”

“Understanding the importance of what was at stake, during my tenure as chairman, I worked closely with staff to push that final rule forward,” he said proudly. “I believe in the potential for storage to be a transformative technology for our grid. Storage is a game-changer. I’ll admit it’s a bit cliche, but there’s truth to it.”

He also noted the importance of Order 845, which revised the commission’s pro forma large generator interconnection procedures and interconnection agreement. One of the 11 changes the commission approved was to include storage in the definition of “generating facility.” (See FERC Order Seeks to Reduce Time, Uncertainty on Interconnections.)

Another change allows generators to sell their surplus interconnection capacity to other resources. Storage owners can purchase surplus capacity for their resources so they can interconnect without having to go through the full queue, Chatterjee said.

“While this change in policy sounds very wonky — and it is — I think it’s a subtle but important action we’ve taken to improve opportunities for storage development.”

Chatterjee also noted the challenges storage still faces. RTOs and ISOs face a Dec. 3 deadline for their Order 841 compliance filings. FERC is “likely to take several months” to review them, and any deficiencies it finds will delay implementation further, Chatterjee said.

He also said grid operators have been slow to develop new products to compensate storage resources for their different services.

“With the exception of PJM’s RegD product, there’s been little momentum toward expanding the traditional set of ancillary services in the past few years,” Chatterjee said. “The increasing penetration of renewables might provide additional momentum for such products, but in any event, whether and how these products come to fruition could have a significant effect on the opportunities for storage.”

Siting and Co-location

Multiple panelists discussed the best strategies for deciding where to develop storage resources.

energy storage east neil chatterjee — Michael Harrington, Utility of the Future department manager for Consolidated Edison | © *RTO Insider*

Storage can receive the federal investment tax credit when added to existing qualifying resources, mainly solar facilities. But Michael Harrington, of Consolidated Edison’s Utility of the Future department, pointed out that the New York State Energy Storage Roadmap, issued in June, predicted that more than half of the 1,500 MW of storage the state aims to procure by 2025 would be downstate, close to New York City’s load.

“We do think there’s opportunity with upstate renewables, but certainly we recognize that storage is going to follow where the economics are the best,” he said.

Ascend Analytics CEO Gary Dorris | © *RTO Insider*

Ascend Analytics CEO Gary Dorris explained why being near the city is so attractive for storage. The best way to determine where to site storage resources, he said, is finding where prices are most volatile: where congestion on the grid is most persistent.

Price spikes occur very infrequently on a typical New York node — only 1.5% of a 24-hour day — but they represent 22% of the average real-time energy price, according to Dorris. “So storage can be a wonderful physical hedge against price spikes, and that’s a real opportunity to mitigate uncertainty in supply by having that physical hedge in attacking those price spikes.”

“Co-located storage with renewables certainly has benefits, but is co-locating renewables with storage going to become standard practice?” Chatterjee posited. “The answer to that question could have major implications for storage. We have evidence that the cost-benefit ratio of co-located storage is tipping in favor of adding storage.”

He pointed to a 2017 resource solicitation by Xcel Energy’s Public Service Company of Colorado. While individual wind and solar resources received median offers of $18/MWh and $29 MWh, respectively (“amazing numbers in their own right”), wind and solar resources co-located with storage received a $3 and $7 premium.

“When you consider market incentives like … capacity constructs in PJM and ISO-NE, co-location could be extremely beneficial in allowing renewables to avoid performance penalties and take advantage of high prices,” he said.

Wish List from States, RTOs

Several speakers said grid operators and states could be doing more to value storage’s services.

In introducing a panel on innovative business models for storage, Dorris suggested that states should lower their property taxes for storage. Taxes are particularly high in the Northeast, where storage is most in demand. “That’s probably not being talked about as much as perhaps it could be given the nature of these projects,” he said.

The panelists focused on the lack of a “T&D benefit” in RTOs and ISOs, saying storage should be compensated for its congestion-reducing benefits as energy efficiency programs are. Such programs are valued in part for reducing the voltage levels on transmission and distribution lines, allowing transmission owners and utilities to defer costly upgrades.

“Just level the playing field between how you treat conservation and how you treat storage,” Dorris urged.

From left, Thomas Leyden, EDF Renewables; Adam Rousselle, Renewable Energy Aggregators; and Stephen Wemple, Consolidated Edison. | © *RTO Insider*

“As a developer, we need to have certainty, and we need to have predictability going forward,” said Thomas Leyden of EDF Renewables. “That’s not easy in a market-based system, but there are things that can be done to help our investors become more comfortable.”

Adam Rousselle, CEO of Renewable Energy Aggregators, went further. He noted that transmission owners get paid fixed rates of returns based on the value of their assets. “If we can not align the development of storage with the transmission owner, we won’t be building storage any time soon in PJM,” he said. “And if your solution delays their transmission investment, they’re competing with you, make no mistake about it.”

— Michael Brooks

October 22, 2018

Methane Tax Suggested to Reduce Emissions

By Rory D. Sweeney

PHILADELPHIA — Fugitive methane emissions might be reduced throughout the natural gas supply chain by making accidental leaks and routine venting part of the carbon markets being considered for the power industry, panelists told attendees Wednesday at a policy forum hosted by The Kleinman Center for Energy Policy at the University of Pennsylvania.

The key would be developing a market that taxes emitters but also pays those who capture emissions, as the technologies would also be useful for reducing methane emitted by nature — either as part of natural processes or negative feedback loops exacerbated by global climate change.

“If you can price greenhouse gas emissions and you put in that financial incentive for capturing it, and then whatever brilliant technology gets developed, it faces the right incentives and it has a financial ability to move forward,” said Catherine Hausman, an assistant professor of public policy at the University of Michigan. “The carbon tax, the flip of that is the subsidy or whatever for what gets captured.”

She suggested a policy, which she acknowledged has legal concerns, where every potential source of methane in a region would be responsible for a share of the area’s emissions unless it can prove it wasn’t the source. That would incentivize gas producers and pipelines to monitor their operations to prove themselves innocent.

The panelists weren’t afraid to promote increased governmental regulation.

“Tax the emission if you can. Absent a tax … you need regulations on the way they run. … I am totally happy with regulatory measures that are not market-based in situations where you can’t develop market-based solutions,” Hausman said. “I always teach that zero pollution is not the right answer because it stops all economic activity. Now, very aggressive action is certainly needed.”

“I would love to get to the place where methane emissions from the oil and gas industry are appropriately taxed. … Our view is we’re not there yet,” the Environmental Defense Fund’s Ben Ratner said. “Where we really want to get to over time is prevention. … There’s just no way around government action.”

Kleinman Center for Energy Policy methane tax carbon markets — From left, Environmental Defense Fund’s Ben Ratner, Catherine Hausman, assistant professor of public policy at the University of Michigan, and moderator Karen Goldberg, a chemistry professor at the University of Pennsylvania and the director of the Vagelos Institute for Energy Science and Technology. | *(c) RTO Insider*

Another challenge for developing a carbon market will be defining what values are used to determine payments. As hard as it is to nail down a valuation of carbon — the panelists noted suggestions from $40 to $400/ton — so too is calculating the amounts emitted. And while researchers can estimate global emissions, “knowing the precise location [of the source] is what’s hard,” Hausman said.

“You have to solve the measurement problem,” she said.

“There’s still so much uncertainty about global emissions … that we don’t know yet what [each source’s emissions limit] should be,” Ratner said.

Hausman suggested the key might be locating “super-emitters.”

The panelists also criticized the Trump administration for attempting to reverse regulations on methane emissions in the oil and gas industry. The Clean Air Act’s procedural rules barred the Obama administration from expanding its more stringent regulations for new and modified facilities to existing facilities, Ratner said.

The hope was for the next administration to make that expansion, he said. But “not only is this new administration not doing that, it seems to be intent to roll back” the Obama revisions, he said.

October 22, 2018

UPDATED: Chatterjee Dodges as DOE Spins on Coal Bailout

By Rich Heidorn Jr.

ARLINGTON, Va. — FERC Commissioner Neil Chatterjee and Assistant Energy Secretary Bruce Walker pledged to continue their work on grid resilience Wednesday following the apparent demise of the Trump administration’s latest plan to prop up struggling coal and nuclear plants.

The two appeared at the Department of Energy’s Electricity Advisory Committee meeting, where Walker charged the panel with reconsidering current practices on spinning reserves, calling it wasteful to have 15% of capacity “doing no work.”

Walker also did a little spinning of his own, insisting that DOE’s “leaked pre-decisional memo” calling for price supports for “fuel secure” generation was never about propping up nuclear plants or the coal industry. The memo became public at the beginning of June, after Trump — who had made saving the coal industry a signature campaign promise — directed Energy Secretary Rick Perry to “prepare immediate steps to stop the loss” of fuel-secure generators facing retirement. (See Trump Orders Coal, Nuke Bailout, Citing National Security.)

ferc neil chatterjee department of energy — Assistant Energy Secretary Bruce Walker | © *RTO Insider*

“It was not focused on coal or nuclear,” Walker said. “It was a recognition that there has been a significant change in the portfolio of generation throughout the United States … most notably a significant reliance on natural gas pipelines for electric generation.”

Talking to reporters after his speech, Walker elaborated. “The fact is, the words in the pre-decisional memo were ‘all fuel secure generation.’ Everybody misinterpreted the words for whatever political reasons they chose to,” he said. “There’s liquid natural gas that can have on-site fuel. There’s biomass conversion that has on-[site] fuel. … Pump storage, that’s fuel-secure generation. Hydro, that’s fuel-secure generation.”

Chatterjee in a Rush

The normally gregarious Chatterjee rushed with aides to an awaiting SUV immediately after his remarks from the podium, declining to take questions from the committee and refusing to talk with reporters.

Asked how the apparent failure of the Trump/Perry plan would affect FERC’s work, Chatterjee said, “We’ve got our resilience docket open.

“We’ll continue to work on it,” he said, getting into the car. FERC opened the resilience docket in January after rejecting DOE’s earlier bid to help coal and nuclear plants. (See FERC Rejects DOE Rule, Opens RTO ‘Resilience’ Inquiry.)

Was the demise of the DOE plan disappointing to him? “I didn’t even know what they were considering,” Chatterjee said.

McIntyre’s Future

Chatterjee’s haste may have had less to do with the coal and nuclear plan than with rumors that FERC Chairman Kevin McIntyre, who has been battling a brain tumor, may announce his resignation. Chatterjee — who had reportedly visited the White House on Oct. 16 — declined to respond to reporters’ questions about McIntyre’s status and whether he would resume as acting chairman.

McIntyre did not attend the commission’s open meeting Thursday, the second he has missed since a fall that left him visibly uncomfortable at the meeting in July. (See Ailing McIntyre Absent from FERC Open Meeting.)

Chatterjee noted McIntyre’s absence as he opened Thursday’s meeting, saying “My prayers are with him and his family.”

“I’m very sorry Chairman McIntyre is not able to be here today, and I continue to send warm wishes to him for his recovery,” Commissioner Cheryl LaFleur said.

In March, McIntyre issued a statement saying he had undergone “successful surgery” for a “relatively small” brain tumor that was discovered in summer 2017. He said he did not intend to provide further details or updates for privacy reasons.

At the July meeting, he wore a sling after disclosing he had injured his arm and suffered compression fractures in two of his vertebrae in a fall. (See “McIntyre Toughs it out,” FERC Says Farewell to Powelson.)

Although he was not present for the September meeting, McIntyre participated in its votes; he was not recorded as voting on Thursday.

Sources have told RTO Insider that the chairman is often absent from FERC headquarters and that meetings with him have been frequently rescheduled as a result. Spokeswoman Mary O’Driscoll last month declined to answer questions on the subject.

Chief of Staff Anthony Pugliese told reporters after Thursday’s meeting that the chairman would issue a statement on his status within a few days.

With the resignation of Republican Commissioner Robert Powelson in August, the commission is now split 2-2 between Republicans and Democrats. Earlier this month, President Trump nominated the Department of Energy’s Bernard McNamee as Powelson’s replacement. (See Trump Nominates DOE’s McNamee to FERC.)

Perry: Out of Our Hands

DOE’s Walker, who heads the Office of Electricity, did not explicitly confirm the numerous news reports that the White House had rejected DOE’s proposal following opposition from the National Security Council and National Economic Council. Perry told reporters in September that DOE had finished its resilience proposal and was awaiting a White House decision.

The memo outlined “one of the many possible solutions,” Walker said. “We are focused on national security. We will continue to look at what are the things that best support the infrastructure that’s needed under national security.”

October 21, 2018

SPP MMU: Evergy Changing Market Dynamics

By Tom Kleckner

Great Plains Energy’s merger with Westar Energy in June has increased market concentration in the new company’s reserve zone, but it “is not necessarily a cause for concern at this time,” SPP’s Marketing Monitoring Unit said in its most recent quarterly State of the Market report.

The new company, Evergy, is the largest energy consumer in SPP, accounting for 19.7% of summer consumption, according to the Oct. 15 report, which covers June through August.

System summer energy consumption | *MMU*

Evergy, American Electric Power (17.1%), Oklahoma Gas and Electric (11.6%) and Southwestern Public Service (10.2%) consumed almost 60% of the RTO’s total energy in the summer, pushing the market’s post-merger Herfindahl-Hirschman Index (HHI) above 1,000 at times, indicating a “moderately concentrated market.”

“If a continually increasing trend is observed in the future, it would require further analysis,” the report says.

Evergy has 1.58 million customers in Kansas and Missouri. (See Westar-Great Plains Merger Wins Final Approval.)

The Evergy reserve zone’s average summer prices were below 2017 levels for July and August, at around $30/MWh and $25/MWh, respectively. June prices were more than $30/MWh, primarily because of higher temperatures and loads across SPP.

The report notes:

Low energy prices, with summer prices averaging around $25/MWh;
A continued decrease in intervals that experienced negative energy prices; and
A decline in overall congestion across the footprint.

MMU Executive Director Keith Collins | © *RTO Insider*

The report’s “special issues” section also reviews the market’s manual commitment process. The MMU said that while SPP operators have improved their consistency in coding and reporting manual commitments, they should add more detailed and consistent reasons for local, transmission, capacity and stagger commitments.

Noting that FERC Order 844 in April added market-transparency requirements for resource commitments, the Monitor recommended SPP report publicly all manual commitments. It also noted the high number of manual capacity commitments for ramping needs and renewed its call for a ramp product, saying it would be more effective.

The MMU will host a webinar on Nov. 8 to discuss the report.

October 21, 2018

Familiar Winter Story: ISO-NE Braces for Gas Shortages

By Michael Brooks

WASHINGTON — Observers of FERC’s technical conference on grid operators’ preparations for winter on Thursday would be forgiven if they experienced deja vu.

Most of the RTOs say they are ready; CAISO is keeping an eye on natural gas storage levels but not concerned; and the possibility of fuel shortages during an extended cold spell is keeping ISO-NE officials up at night.

The regions gave similar reports to FERC in 2017 and 2016. (See RTOs Brief FERC on Winter Preparations.)

“You know, I feel like we’re in a long-running production of ‘same time next year,’ where every fall you come and say, ‘We have plenty of capacity, we might not have enough gas, I’m cautiously optimistic we can make it through,’” FERC Commissioner Cheryl LaFleur told Peter Brandien, ISO-NE vice president of system operations.

Commissioners Cheryl LaFleur and Richard Glick | © *RTO Insider*

The National Oceanic and Atmospheric Administration is predicting a warmer-than-normal winter for most of the U.S., including New England. But Brandien said it is not the average temperature that concerns him; it’s the duration of low temperatures.

“It’s not that the electric load increases; it’s that the fuel kind of disappears” because home heating takes priority over electricity generation, he said. “Last winter, December, January and February were all above average temperatures and weather. But we experienced extreme cold weather Dec. 26 through Jan. 8, and it’s those kind of spells that cause us concern.”

When gas is short, ISO-NE relies on oil as backup fuel. But severe weather can cause delays not only for barges shipping in LNG, but for trucks carrying barrels of oil. Generators burning oil also face emission limits.

In their presentation to commissioners during their open meeting earlier that day, FERC staff also noted this will be the first winter under ISO-NE’s Pay-for-Performance capacity construct, which became effective June 1. The program is intended to better incent generators to perform during scarcity and emergency conditions, and influenced PJM’s Capacity Performance construct.

Staff also noted ISO-NE’s integration of price-responsive demand into its markets, also implemented June 1. (See ISO-NE Begins Real-time Dispatch of Demand Response.)

From left, Peter Brandien, ISO-NE; Emilie Nelson, NYISO; Dave Souder, PJM; Rob Benbow, MISO; Bruce Rew, SPP; and Nancy Traweek, CAISO. | © *RTO Insider*

But being the first years of these programs, Brandien said anything beyond a weeklong cold spell was unknown territory for the RTO.

No Worries Elsewhere

Representatives from the other FERC-jurisdictional grid operators reported that they were able to maintain reliability last winter despite two major cold snaps in January — one including the so-called bomb cyclone — and that they were similarly prepared for this winter.

FERC staff on Thursday led a technical conference on RTOs’ and ISOs’ reliability preparations for the upcoming winter. | © *RTO Insider*

Emilie Nelson, NYISO vice president of market operations, also referenced the late December/early January cold snap, which led to the ISO’s third highest winter peak load since 2004, at about 25.1 GW. Nelson said NYISO does not expect any problems this winter, but it is undertaking several efforts to plan for the long term. One of these is a fuel security study next year “to evaluate the ability to meet electric system needs during stressed system conditions, such as prolonged cold weather events and disruptions in fuel availability.” (See related story, NY Ready for ‘Average’ Winter; Burman Worried.)

Both Robert Benbow of MISO and Bruce Rew of SPP noted the mid-January cold snap in the South, when both MISO South and SPP set new all-time winter peaks on Jan. 17 of 32.1 GW and 43.6 GW, respectively.

While MISO maintained reliability through the event, Benbow said the RTO saw opportunities to improve its coordination with members and neighbors. Those lessons helped improve performance during a maximum generation event in September attributed to a major load forecasting error, he said. (See MISO: Sept. Emergency Response Improved by Jan. Event.)

Nancy Traweek, executive director of system operations for CAISO, said nothing has changed in regards to gas since last winter. Two pipelines in California — Southern California Edison’s Line 235-2 and Line 4000 — remain out of service, and her “favorite friend,” the Aliso Canyon storage facility, is still a last-resort resource for withdrawals. Rather than winter, Traweek said, the ISO is still concerned about summer.

“Right now we’re still considered in summer; it’s very warm and dry in California, and really the biggest risk we have right now is the risk of wildfire,” Traweek said. “It’s becoming a year-round issue. It used to be October would be our big wildfire season, and now we can see it any time of the year.”

October 21, 2018

PJM MRC/MC Preview: Oct. 25, 2018

Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees on Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.

RTO Insider will be in Wilmington, Del., covering the discussions and votes. See next Tuesday’s newsletter for a full report.

Markets and Reliability Committee

1. PJM Manuals (9:15-9:35)

Members will be asked to endorse the following proposed manual changes:

A. Manual 3A: Energy Management System (EMS) Model Updates and Quality Assurance (QA). Revisions developed to clarify the process for considering external bulk electric system facilities for modeling.

B. Manual 13: Emergency Operations. Revisions developed as part of PJM’s comprehensive security-threat review.

C. Manual 11: Energy & Ancillary Services Market Operations. Revisions developed to address FERC approval of Tariff changes related to a new day-ahead pseudo-tie transaction product designed to address overlapping congestion for units pseudo-tied out of PJM.

D. Manual 28: Operating Agreement Accounting. Revisions developed to address FERC approval of Tariff changes related to a new day-ahead pseudo-tie transaction product for units that are pseudo-tied out of PJM.

2. RPM Credit Requirement Reduction Clarifications (9:35-9:50)

Members will be asked to endorse draft Tariff language to remove an apparent overlapping credit reduction provision for qualified transmission upgrades, to clarify milestone documentation requirements for internally financed projects, and to clarify that capacity market sellers should submit requests for reductions.

3. Transmission Constraint Penalty Factors (9:50-10:05)

Members will be asked to endorse the joint PJM-Independent Market Monitor package developed at the special Market Implementation Committee sessions related to transmission constraint penalty factors and draft Manual 11 and Manual 33 revisions, as well as Operating Agreement and Tariff language. (See “Transmission Constraint Relaxation Removed,” PJM Market Implementation Committee Briefs: Sept. 12, 2018.)

4. FERC Order 831 – Offer Caps (10:05-10:20)

Members will be asked to endorse draft Manual 11 language that describes the long-term automated process for price-based offers greater than $1,000/MWh. (See “Automating Offer Confirmation,” PJM Market Implementation Committee Briefs: Sept. 12, 2018.)

5. 2018 Reserve Requirements Study Results (10:20-10:35)

Members will be asked to endorse the 2018 Reserve Requirements Study results. (See “IRM Study,” PJM PC/TEAC Briefs: Oct. 11, 2018.)

6. Regulation Market Pricing Issue (10:35-10:55)

Members will be asked to endorse a problem statement and issue charge to address recent regulation market clearing price issues as well present a proposed solution. (See “Regulation,” PJM Operating Committee Briefs: Oct. 9, 2018.)

7. Summer-only Demand Response (10:55-11:20)

Members will be asked to endorse either of two proposals to better value summer-only demand response resources. One proposal was endorsed by the Summer-Only Demand Response Senior Task Force, and the other was developed by EnerNOC. (See Plan Would Reduce PJM Capacity Curve Through Peak Shaving.)

Members Committee

Consent Agenda (1:20-1:25)

Members will be asked to endorse proposed Tariff and OA revisions developed by the Governing Documents Enhancement & Clarification Subcommittee.

1. Opportunity Cost Calculator (1:25-1:45)

Members will review progress to date on PJM’s review and approval of the Monitor’s opportunity cost calculator and then be asked to approve proposed OA Schedule 2 revisions related to opportunity cost calculators. (See “PJM, Monitor Come to Agreement on Opportunity Cost Calculator,” PJM MRC/MC Briefs: Sept. 27, 2018.)

2. M15: Cost Development Manual Biannual Review (1:45-1:55)

Members will be asked to endorse draft revisions to Manual 15 developed through the required biannual review, which include addressing terminology inconsistencies and updating the Handy Whitman Escalation Index.

3. Market Seller Offer Cap Balancing Ratio Proposal (1:55-2:10)

Members will be asked to endorse proposed Tariff revisions that would change how PJM estimates the expected future balancing ratio used in the default market seller offer cap. The proposed method would take the average balancing ratios during the three delivery years that immediately precede the Base Residual Auction using actual balancing ratios calculated during RTO performance assessment intervals (PAIs) of the delivery years, along with estimated balancing ratios calculated during the intervals of the highest RTO peak loads that do not overlap a PAI for any preceding delivery year with less than 360 intervals (30 hours) of RTO PAIs. (See “Balancing Ratio,” PJM Market Implementation Committee Briefs: July 11, 2018.)

4. Transmission Constraint Penalty Factors (2:10-2:25)

Members will be asked to endorse proposed Tariff and OA revisions related to transmission constraint penalty factors. (See MRC item 3 above.)

5. Super Forum (2:25-2:40)

Members will be asked to endorse a proposed problem statement and issue charge related to potential enhancements to the stakeholder process developed in response to feedback gathered in the Stakeholder Process Super Forum held on July 25, 2018. (See Poll: PJM Stakeholder Process Imperfect, Necessary.)

6. 2018 Reserve Requirements Study Results (2:40-2:50)

Members will be asked to approve the 2018 Reserve Requirements Study results. (See MRC item 5 above.)

7. Nominating Committee (2:50-3:00)

Members will be asked to elect members of the 2018/19 Nominating Committee.

— Rory D. Sweeney