Page 1172 – RTO Insider

November 19, 2019

SPP Strategic Planning Committee Briefs: Nov. 12, 2019

JUNO BEACH, Fla. — Convening a Strategic Planning Committee meeting last week in South Florida, SPP Board of Directors Chair Larry Altenbaumer apparently couldn’t resist adding a little local flavor to the proceedings.

The Strategic Planning Committee gathers at NextEra’s headquarters Nov. 12. | © *RTO Insider*

Altenbaumer focused the committee on the future and a plan “for how to get there” by quoting from Jimmy Buffett’s “Changes in Latitudes, Changes in Attitudes“:

“Oh, yesterday’s over my shoulder,
So I can’t look back for too long.
There’s too much to see waiting in front of me,
And I know that I just can’t go wrong.”

After quoting Margaritaville’s most famous resident, Altenbaumer told the committee during its Nov. 12 meeting at NextEra Energy’s corporate headquarters that SPP’s new strategic plan needs to focus on what the RTO delivers “that is better than other options that are out there.”

“Focus on our performance and effectiveness and the quality of the services we provide,” he said.

SPP — Board Chair Larry Altenbaumer leads the strategic discussion. | © *RTO Insider*

The committee will spend the near term developing an official SPP vision statement. “There’s a sentiment that SPP should consider a vision at this juncture,” Altenbaumer said.

The SPC will begin revising SPP’s strategic plan in April after taking feedback it gathers from the board and Members Committee in January. “Critical areas of focus” will include effective communication, strengthening relationships, a Western strategy and transmission planning in an uncertain future.

SPP Senior Vice President of Engineering Lanny Nickell outlined three “areas of competition” to consider: competition between RTOs, ensuring SPP doesn’t lose load to ERCOT and keeping load where it is.

“How do we compete for loads that are not in an RTO?” he asked, rhetorically. “How do we compete, as a region, for loads that love the renewable resources and low prices? They’re looking for opportunities to add warehouses and data centers. How do we compete for those? As loads move off the transmission system and onto the distribution system, is that an issue we need to look out for, or be aware of, and compete for?”

“If you’re trying to contain costs, you have to make sure you’re keeping all the load you have,” NextEra Energy Resources’ Holly Carias said. After adding Entergy as MISO South in 2013, MISO’s administrative fee fell below SPP’s, she said.

SPP will raise its administrative fee by 9.1% in 2020 to a record 43 cents/MWh. (See “Directors Approve 9.1% Administrative Fee Increase for 2020,” SPP Board of Directors/MC Briefs: Oct. 29, 2019.) That has raised concerns among some members who have seen several loads on the SPP-ERCOT seam transfer into the Texas grid.

“Reality is rate cases,” Southwestern Public Service’s Bill Grant said. “Asking for recovery of all these expenses and having to justify transmission increases … a lot of customers are not enamored with the rising cost of transmission … on their bills.”

Staff Working on HITT Escalation Process

In briefing the committee on the Holistic Integrated Tariff Team’s (HITT) recommendations, COO Carl Monroe described an escalation process that starts with staff that worked on an issue addressing questions around that issue before it potentially ends up at the SPC or before the board.

“We’re trying to get the teams responsible for facilitating the issue to resolve those issues too,” Monroe said. “We suspect there will be times where there are disagreements over whether it’s a good recommendation or being implemented as intended. Is it going in the direction where it will be improving something?”

HITT’s yearlong work resulted in a package of 21 recommendations intended to integrate renewable energy’s growth, boost reliability, and improve transmission planning and the wholesale market. The recommendations have since been parceled out to the SPC and other stakeholder groups. (See SPP Board Approves HITT’s Recommendations.)

SPP Director Bruce Scherr explains his thoughts. | © *RTO Insider*

Several committee members who participated on the HITT pointed out that they agreed on the package as a whole but still had concerns about individual recommendations.

“This very same conversation is reflective of some of the conversations and discussions at HITT. This is the kind of difficulty we saw coming,” said Oklahoma Gas & Electric’s Greg McAuley, who called into the meeting. “These are some very big changes that are being proposed. Without a lot of due diligence or thorough analysis, we can’t say it’s a package deal and it’s all or nothing.”

“Anything that came through the HITT as a recommendation came with the understanding that it was a general idea,” Lincoln Electric System’s Dennis Florom said. “With the development of tariff language that comes through the process, we may end up with something where there is no unity.”

Nickell reminded the committee that the Markets and Operations Policy Committee sets the RTO’s policy.

“HITT didn’t include the full membership. MOPC will have the opportunity to weigh in as a full membership body,” he said. “It’s important that MOPC expresses why or why not a certain policy [being] advocated is better than what the HITT recommended, and the SPC needs to understand that.”

SPC Agrees to 2 HITT Recommendations

The committee approved two actions it was assigned by the HITT: a draft strawman that adds an “understanding and evaluation of technological advances” to SPP’s strategic plan and a continued “high priority” focus on seams issue.

The HITT report identified technological advances as presenting opportunities for SPP “to provide improved service, higher reliability assurance, greater market efficiencies and tools to manage the evolving generation portfolio.” The SPC agreed that staff should report to the committee about potential technological breakthroughs developed through their work with stakeholder groups, NERC, the Electric Power Research Institute, the ISO/RTO Council and other industry groups.

The committee agreed SPP should continue to “foster mutually beneficial cooperative and joint transmission projects with its neighboring systems to support broader interregional planning.” The comprehensive effort should include identifying how to plan, estimate and “optimize” the facilities on an interregional level.

— Tom Kleckner

November 19, 2019

Anbaric Seeks FERC Help on OSW Tx

By Rich Heidorn Jr.

Anbaric Development Partners asked FERC on Monday to order PJM to allow developers of offshore transmission “platforms” to obtain injection rights, saying the RTO’s Tariff violates the commission’s open access requirements and is discriminatory.

The transmission developer said it was forced to file its complaint after a stakeholder initiative to consider changing PJM’s rules stalled in September.

PJM’s Tariff allows merchant transmission developers to obtain transmission injection and withdrawal rights for DC facilities or controllable AC facilities connected to a control area outside the RTO. Under a problem statement approved in February, stakeholders considered allowing merchant transmission developers to request injection rights for non-controllable AC transmission offshore. But after six special sessions, stakeholders opted against recommending changes. (See “PJM Recommends Sunsetting Offshore Wind Special Sessions,” PJM PC/TEAC Briefs: Sept. 12, 2019.)

“The nature and scope of fundamental open access rights under the PJM Tariff cannot be left to the whims and commercial interests of stakeholders,” Anbaric said in its complaint. “Put simply, the PJM Tariff does not contemplate the interconnection of transmission platform projects and denies them the opportunity to interconnect to the PJM transmission system and obtain meaningful and material interconnection rights.”

In response to the complaint, PJM spokesman Jeff Shields said the RTO “has been and will continue to engage with members, project developers, and impacted states on the procedures that will enable states to integrate offshore wind into their generation portfolios.”

Bottlenecks

Anbaric and other transmission developers have argued that having individual wind farms build separate radial lines to shore will be more expensive, more environmentally intrusive and less resilient than networked open access facilities that multiple wind farms could use. (See Anbaric Pushes Offshore Grid Plans.)

“What we’ve seen is — and this is true in New York and New England too — if you’re going to scale offshore wind up past the first couple thousand megawatts, radials are going to run into a bottleneck,” Theodore Paradise, Anbaric’s senior vice president for transmission strategy, said in an interview. “There’s not enough interconnection points.”

The company said there are no technical reasons for blocking transmission platform projects, citing transmission built to deliver onshore wind from Texas’ Competitive Renewable Energy Zones and California’s Tehachapi Pass.

Anbaric CEO Ed Krapels said he’d like to see PJM adopt the European model of allowing states to offer solicitations for multiple transmission developers to compete for OSW transmission.

“That’s how the Dutch and the Germans are now getting responses from wind generators that don’t even require long-term contracts,” he said in an interview.

Anbaric — which helped build the 660-MW Neptune HVDC cable linking PJM to Long Island and the 660-MW Hudson project connecting Manhattan to the RTO — envisions a network of transmission “platforms” that could deliver 52 GW or more of offshore wind generation to PJM, NYISO and ISO-NE.

Anbaric envisions a network of transmission “platforms” that could deliver 52 GW or more of offshore wind generation to PJM, NYISO and ISO-NE. | *Anbaric Development Partners*

New England’s states are seeking 5,200 MW of OSW by 2035, and New York has ordered 9,000 MW by 2035.

New Jersey has a goal of developing 3,500 MW of OSW by 2030. The state’s Board of Public Utilities in June 2019 selected a 1,100-MW project off the coast of Atlantic City and plans additional solicitations for 1,200 MW in 2020 and 2022. Last week, the BPU held a stakeholder meeting at which officials discussed developing a separate solicitation for offshore transmission.

Maryland has ordered the development of at least 400 MW of offshore wind generation by 2026, at least 800 MW by 2028 and 1,200 MW by 2030.

In Virginia, Dominion Energy plans to develop 2,600 MW of OSW in three 880-MW phases between 2024 and 2026.

Relief Sought

In March 2018, Anbaric submitted interconnection requests for two proposed AC transmission platform projects, each requesting 1,100 MW of injection rights. PJM told the company it would need to partner with a generator to obtain the rights under current rules.

In June 2018, Anbaric submitted an interconnection request for a proposed DC transmission platform project seeking a 1,200-MW injection into Public Service Electric and Gas’ transmission system in North Brunswick, N.J. More than a year later, after completing a feasibility study that assumed the injection, PJM informed Anbaric on Nov. 1 that it would only model the project without injection rights. Anbaric said the project has obtained almost all its required environmental permits.

Anbaric said it was seeking relief like that granted by FERC’s Order 845, which required RTOs to improve the interconnection process and expand the definition of “generating facilities” to include electric storage. (See FERC Order Seeks to Reduce Time, Uncertainty on Interconnections.)

It said the current rules effectively give offshore generation developers a right of first refusal like one that the commission outlawed for incumbent transmission owners in Order 1000.

Anbaric asked FERC to order PJM to revise its Tariff to remove the requirement that all merchant transmission facilities interconnect with another control area and to create a new category of merchant transmission facilities called a “remote generation resource interconnection platform” (ReGRIP).

The company also asked the commission not to order a PJM stakeholder process, saying that could result in delays that would prevent states from issuing solicitations for offshore transmission.

Krapels and Paradise said they are hopeful the commission will respond to the PJM complaint with an order that sets a precedent for other RTOs, saying they have similar concerns in New York and New England.

November 19, 2019

PJM PC/TEAC Briefs: Nov. 14, 2019

VALLEY FORGE, Pa. — The PJM Planning Committee deferred voting again on a problem statement and issue charge for a proposed review of the RTO’s critical infrastructure management.

The second delay follows a plea from Exelon and other transmission owners on Thursday to hold off on the issue until after a webinar scheduled for Friday to address stakeholders’ concerns about a proposed Tariff attachment that creates a process to mitigate existing facilities on NERC’s CIP-014 list. (See “Critical Infrastructure Vote Deferred,” PJM PC/TEAC Briefs: Oct. 17, 2019.)

“A number of things on this issue charge could be removed or modified,” said Pulin Shah, director of transmission strategy and contracts for Exelon. “The M4 [attachment] hasn’t been approved. We are still working through this process. A lot of the things that are in here may or may not even be applicable [after the webinar].”

He clarified that a second 30-day delay would give stakeholders more time to “focus the scope on the areas of concerns that everyone has alignment on in terms of creating new CIP-014 facilities.”

DER Ride Through Task Force Sunset

PJM wants to sunset the Distributed Energy Resources Ride Through Task Force after saying its work considering a default standard is done.

The RTO said distributed energy resources currently function on settings designed to respond to unexpected system malfunctions that disrupt power flow. Some sources “ride through” the event, providing much-needed reliability, while others trip off to prevent system damage. Solar panels and other DERs also can’t tell the difference between a transmission fault and a distribution fault, causing inappropriate responses and overstressing the system.

The task force had been considering ways to fix this problem — even going so far as to bring in federal experts to help develop new standards — but decided against an RTO-wide rule because of the uniqueness of local distribution systems. (See DER Ride Through Task Force Considers New Direction.) Instead, the task force suggested that PJM create a recommendation when a local distribution system lacks an official policy.

Competitive Transmission Proposal Fee Restructuring

As PJM moves forward with its proposed fee restructuring for competitive transmission proposals, stakeholders remain concerned about the associated revisions to Manual 14F required as part of the update.

The revisions, borne out of a stakeholder motion endorsed by the Markets and Reliability Committee last year, will codify the comparative cost framework the RTO will use to evaluate these projects. (See “PJM Unveils Flat Fee Cost-containment Plan,” PJM PC/TEAC Briefs: Aug. 8 , 2019.) Since implementation of FERC Order 1000 in 2014, PJM has reviewed 850 competitive proposals, of which less than 20% included cost-commitment provisions.

TOs continue to question the appropriateness of revisions proposed by both PJM and the Independent Market Monitor that would memorialize an ongoing collaborative role between the two entities in reviewing competitive transmission proposals. (See PJM TOs Wary of Cost Containment Rules.)

In an effort to bridge the gap, LS Power proposed a paragraph that would clarify PJM’s precedence over the Monitor in reviewing proposals, a suggestion that fellow TOs found promising but still imperfect.

Some 77% of stakeholders at the PC approved of PJM’s current proposal. PJM’s Mark Sims said staff will take the restructured fee and its associated Operating Agreement and manual changes to the MRC for endorsement next month.

Manual 19 Revisions Endorsed

Stakeholders endorsed revisions to Manual 19: Load Forecasting and Analysis, a periodic cover-to-cover review that also removes load forecast model overview from the manual and adds it to an annual white paper. The revisions also update sections 3.2, 3.4 and 4.2 to update the weather-normalization procedure for peak load and energy to be directly tied to the load forecast model.

Supplementals from AEP, ComEd, Dominion, PSE&G

American Electric Power wants to replace 18 remaining ELF-SL8-4 Type SF6 breakers at its Sullivan 765/345-kV and Rockport 765-kV substations in Rockport, Ind., after documenting more than 16 issues, including compressor failures, since 2002.

Commonwealth Edison proposed a $200,000 rebuild of its Quad Cities-Cordova 345-kV line to fix obsolete relays and servicing difficulties. The line is an intertie between PJM and MISO and needs the upgrade to address equipment condition, performance and risk.

A second ComEd project to rebuild 16 miles of the 345-kV Kendall-Lockport double-circuit towers, increase the line rating and eliminate 10.5 miles of wood poles that are 60 years old will cost $12 million, Exelon said. The utility considered two other $20 million solutions as part of its review process but instead settled on a cheaper plan to install quad-circuit towers between the Kendall and Lockport substations, string 138-kV conductor and cut part of line 9117 over new towers.

PJM — PSEG’s proposed solution for the overloaded Marlton substation in the Voorhees, N.J., area | *PSE&G*

Dominion Energy wants to spend $69 million to preserve its remaining outdoor equipment at the Mt. Storm substation in West Virginia. The utility proposes installing a second gas-insulated substation (GIS) building in the switchyard to house the breakers and switches for Lines 550 and 536 and two generators. The existing GIS building would be expanded to include breakers and switches for lines 529, 572 and Capbank 3.

The company also presented a $400,000 plan to install a 1,200-ampere, 50-kAIC circuit switcher and associated equipment to feed a new transformer at Poland Road.

Finally, Public Service Electric and Gas proposed a $39 million plan to build a new 230-kV substation in Echelon, N.J., to alleviate the overloaded Marlton substation nearby. The utility also considered building a $68 million 69/13-kV substation but decided on the less expensive proposal because it decreases the amount of exposure and increases the reliability of the 230-kV circuit.

November 19, 2019

SPP COO Monroe to Retire in Early 2020

By Tom Kleckner

SPP COO Carl Monroe, one of the key players behind the grid operator’s growing footprint, has said he will retire in early 2020.

Monroe is a 22-year veteran with SPP. As executive vice president and COO, he has been responsible for operations across the RTO’s 14-state balancing authority area and administration of the wholesale electricity market.

SPP Monroe — Carl Monroe speaks at a recent SPP meeting. | © *RTO Insider*

“It has been the opportunity of a lifetime to work at SPP and a privilege to work alongside such bright, talented and caring people in the interest of a worthwhile shared mission,” Monroe said in a statement. “SPP is poised for continued success, which I’ll observe with great interest, but the time is right for me to begin a new chapter with regard to family, travel and other experiences.”

“I’ve had the great privilege of working with Carl during his entire career at SPP,” Mike Wise of Golden Spread Electric Cooperative — one of the RTO’s more prominent members — told RTO Insider. “I believe his personal efforts, contributions and leadership were critical to the tremendous development and success of the Southwest Power Pool.”

Monroe has been credited with the expansion of SPP’s service territory from eight to all or part of 14 states. He also led the organization’s recent growth into the Western Electricity Coordinating Council, where the RTO will begin offering reliability coordination and market services over the next two years.

“In nearly 15 years as a director at SPP, I’ve met no one with greater knowledge of markets and operations or with such ability to collaboratively address complex issues,” Board of Directors Chair Larry Alternbaumer said.

“Carl has helped to shepherd us through tremendous change and growth. We just wouldn’t be where we are today without his leadership,” CEO Nick Brown said.

An SPP spokesman said Monroe’s responsibilities for westward expansion, implementing the Holistic Integrated Tariff Team’s recommendations and other duties “will be transitioned to other members of the officer team.”

Monroe’s retirement — along with Brown’s in April 2020 and the year-end departures of former board Chair Jim Eckelberger and Directors Phyllis Bernard and Harry Skilton — will wipe out much of the leadership that has been in place at SPP since 2004.

The COO vacancy has opened up a potential slot for inside candidates for Brown’s position. SPP is looking at both internal and external candidates for the CEO’s position.

Monroe joined SPP from Entergy, originally being hired to manage the RTO’s growing information technology department. He was elected as an officer and promoted to executive vice president and COO in 2004.

November 19, 2019November 13, 2023

Texas PUC Briefs: Nov. 14, 2019

Texas regulators last week granted a request by staff and Texas Industrial Energy Consumers (TIEC) for a list of investors behind the investment fund involved in a $4.3 billion acquisition of El Paso Electric. An administrative law judge had ruled against the intervenors’ request during discovery in October (49849).

TIEC’s attorney Katie Coleman, a partner with Thompson & Knight, noted during the Public Utility Commission’s open meeting Thursday that the state’s Public Utility Regulatory Act allows the PUC to require a utility or its affiliates to identify owners of more than 1% of the company.

“This seems pretty straightforward,” Coleman said. “We have a fund that consists of private equity coming in to buy a Texas utility. We are asking, ‘Who is that fund? Who provides this capital?’ This is going to be [EPE’s] long-term source of capital. We feel it’s relevant to get a list of the investors and their ownership shares.”

Eversheds Sutherland’s Lino Mendiola, representing J.P. Morgan Investment Management’s Infrastructure Investments Fund (IIF), said the investors behind the $12.2 billion fund were not trying to hide anything and offered to share a list of the pension funds that make up the top 100 investors. The fund is composed of 517 limited partners and three general partners, he said.

“It’s an open-ended infrastructure fund. It invests in buy-and-hold strategies. It’s not a hedge fund,” Mendiola said. “These are passive investors: limited partners that have no ability to control capital deployment. They don’t control the fund; they don’t control any company in the fund. Our argument is the identity of the passive investors, who change over time and who have no control over anything, are not relevant.”

The commission determined otherwise. “If this were a contract dispute, we might give you the discovery win,” Commissioner Arthur D’Andrea told Mendiola.

The PUC will hold a public hearing on the merger Nov. 20 to 22 in Austin. Coleman said TIEC could likely review the list before then and address any issues during the hearing.

The identities of IIF’s investors have also drawn the attention of consumer watchdog Public Citizen, which has protested the proposed deal at FERC (EC19-120). FERC and the Texas PUC are among several regulatory agencies that must approve the acquisition.

EPE and IIF announced the deal in June. It is expected to close in the first half of 2020.

Briefings on CenterPoint Rate Case

The commission requested briefings from CenterPoint Energy and intervenors following a discussion attempting to iron out a preliminary order approving CenterPoint’s Houston electric utility rate case (49421).

The commission discussed and adopted several ring-fencing proposals made by staff and TIEC, including requirements limiting CenterPoint’s dividend payments to an amount not to exceed its net income and suspending the payments if the utility’s credit rating falls below a certain level.

CenterPoint Houston Electric’s adherence to the PUC’s 60-40 debt-to-equity ratio would require it to make an $800 million payment to its corporate parent, the company said.

The commission asked CenterPoint and the intervenors to file briefings on whether the recommended 60-40 capitalization would “necessitate noncompliance” on CenterPoint’s part. It also asked the parties to suggest options to avoid or mitigate the conflict.

An ALJ in September reduced the utility’s proposed $154.6 million rate increase to $2.6 million, or 0.11% of its present rate base. CenterPoint CEO Scott Prochazka made the decision a central point of the company’s third-quarter earnings report. (See Hot Summer Yields Positive Earnings for CenterPoint.)

PUC Approves ERCOT 2020-21 Budget

The PUC approved ERCOT’s 202 0-21 biennial b udget and its 55.05-cents/MWh administrative fee. The budget includes $268.3 million in 2020 and $275.2 million in 2021 for operating expenses, project spending and debt-service obligations (38533).

The system administrative fee has remained level since 2016. The fee and the budget were approved by ERCOT’s Board of Directors in June. (See “Board Approves Budget, Change Requests,” ERCOT Board of Directors Briefs: June 11, 2019.)

AEP’s Purchase of Oncor South Texas Assets OK’d

The commission approved the sale of Oncor’s distribution facilities in the Rio Grande Valley cities of McAllen and Mission to AEP Texas for $18 million. (49402). The deal affects approximately 3,000 residential and small commercial customers in the area.

Gexa Energy Docked $35,000

In other business, the commission:

- Agreed to consider a rehearing request by two landowners over its earlier selection of a preferred route for the second of two 345-kV transmission lines needed to integrate about 470 MW of the city of Lubbock’s load into ERCOT. (See “Commission Approves 1 of 2 Lubbock Projects,” Texas PUC Briefs: Sept. 26, 2019.) Applicants Oncor and Lubbock Power & Light said the two routes have “very similar characteristics, and either one would be a reasonable option” in submitting additional testimony. The move allows the commission to further contemplate and consider the scope of the rehearing (48668).
- Ordered retailer Gexa Energy to pay $35,000 in administrative fees and issue refunds to 7,610 customers for using misleading energy charges on electric bills (49930). Gexa has already refunded more than $10,423 to 37,122 current customers. The penalties raised the commission’s assessments in 2019 to $2.96 million, according to the PUC’s Oversight and Enforcement Division and the Customer Protection Division. The commission has also ordered more than $89,800 in customer refunds through its enforcement actions this year (50019).
- Approved requests by Entergy Texas and EPE to adjust their energy-efficiency cost recovery factors. Entergy can recover $8.01 million in costs (49493) and EPE $5.47 million in costs (49496) for the 2020 program year.
- Agreed to intervene in three FERC dockets: MISO’s proposal to prevent generating resources expecting full or partial outages lasting more than 90 days of the planning year’s first 120 calendar days from participating in a fixed resource adequacy plan and the RTO’s Planning Resource Auction (PRA) (ER20-129); MISO’s Tariff changes regarding the market procurement of short-term reserves (ER20-42); and Wolverine Power Supply Cooperative’s Federal Power Act Section 206 complaint that MISO’s PRA fails to establish an appropriate forward price signal (EL19-102).

— Tom Kleckner

November 19, 2019

MISO Renewable Study Shows More Tx, Tech Needed

By Amanda Durish Cook

CARMEL, Ind. — MISO’s system can operate on 50% renewable generation if the RTO greenlights dramatically more transmission and ups reserve requirements, and if its members embrace new technologies, new study results show.

MISO laid out the possible realities of a 50% scenario at a special Nov. 14-15 workshop to discuss the third round of results of the RTO’s ongoing Renewable Integration Impact A ssessment.

MISO Renewable Study — Jordan Bakke, MISO | © *RTO Insider*

To reach 50% renewables, MISO could retire 17 GW of its existing thermal fleet and add about 100 GW of renewable capacity. Results show even at a 50% renewable penetration, “the majority of the thermal fleet remains available to maintain adequacy,” Policy Studies Manager Jordan Bakke said.

According to the study, renewables would reach 50% of the generation mix as utility-scale solar proliferates in MISO South while wind generation multiplies in the northwestern portion of the footprint. MISO also foresees distributed solar generation becoming more commonplace and concentrated near major cities.

The RTO also said the complementary characteristics of wind and solar generation — on a daily and seasonal basis, solar is generally available when wind isn’t as plentiful — “decreases the probability of not serving load during periods of high risk.”

MISO’s current generation interconnection queue contains 569 projects with 89 GW of estimated capacity, including 51 GW worth of solar and 22 GW of wind. According to a recent report, MISO expects about 3.5 GW of new wind generation to interconnect this year and more than 6 GW to come online throughout 2020.

MISO reported that it executed 43 generation interconnection agreements in 2019, breaking the previous record of 38 set in 2003. However, the RTO also reported 157 project withdrawals so far this year, just short of the record 168 withdrawals set in 2017.

President of Market Development Strategy Richard Doying said MISO now is nearing 20 GW of wind generation, which can have zero marginal cost.

“That is the right economic price, but it’s terrible for baseload generation,” Doying said at an Organization of MISO States meeting in October.

Pad Reserves?

The latest results also line up with earlier studies that conclude MISO’s daily loss-of-load risk compresses into a sharper risk during a smaller set of hours later in the day under a high-renewables scenario. (See MISO Renewable Study Predicts Later Peak, Narrower LOLE Risk.)

At 40% renewables, MISO may need to increase its reserve requirement to manage quick changes in load, the study found.

MISO research and development adviser Long Zhao said the RTO will need ramping capability to manage discrepancies between early evening reductions in solar generation and increases in wind generation and load. Going forward, sunset would probably be a particularly challenging time of day for MISO to manage, Zhao said.

When renewable generation climbs from a 40 to 50% share of the generation mix, it begins to nudge out nuclear and natural gas resources footprint-wide in economic dispatch. MISO envisions its footprint will contain a wind-dominated northern region, a southern region where solar and natural-gas fired generation begin jockeying for position, and a central region that draws on both types of renewables. It also found a significant increase in imports as renewables climb to 50% — more than 10 GW in some cases during summer days. Today, MISO does not exceed 5 GW in imports, even on summer days.

Veriquest Group’s David Harlan said he had a problem with MISO assuming that solar generation could replace the baseload generation of MISO South. He argued that solar’s production capability is simply not predictable enough for heavily industrial areas of the South.

“In MISO South, we have a heavy industrial load planned to be served by coal and nuclear and later by combined cycle,” Harlan said.

Clean Grid Alliance’s Natalie McIntire asked if the shorter and more pronounced loss-of-load risk is good or bad from MISO’s standpoint.

MISO adviser Brandon Heath said the sharper risk is simply a future reality. “It’s neutral. It’s not a good thing or a bad thing just yet,” he said.

Miles and Miles of Lines

It’s not until renewables take a 40% share of the generation mix that MISO foresees a need for transmission projects to “significantly reduce curtailment.” Without transmission solutions, renewable additions beyond a 40% penetration cannot continue displacing thermal generation because there isn’t enough transmission capacity, the RTO found.

“We see needs at the very beginning, but the needs are very small. We see energy adequacy needs when we get to 40%,” Bakke said.

MISO Policy Studies Engineer Yifan Li said while some areas might exhibit needs for local transmission solutions, there’s no need for anything major beyond the normal annual planning cycles until 40% renewable penetration.

“From the bulk amount of energy flow paths to deliver energy and reduce curtailment, an overall systemwide [extra-high-voltage] rebuild is not needed until the 40% milestone,” he said.

But McIntire pushed back on the idea that a 40% renewables mix is the inflection point for new transmission needs. She argued that MISO will require steady transmission buildout as renewable generation rises.

“I just don’t want us to minimize that message. We’re going to need significant transmission before 40%,” McIntire said.

Li agreed that annual transmission buildouts would continue to be needed, but at the 40% penetration level, MISO’s usual annual plans would fail to keep pace with transmission capacity needs.

“I like to compare it to a fever. … Our system is having a high fever around 40% renewables without significant amount of additional transmission,” he said.

At a 40% penetration, Li said, about 80 new transmission projects located all over the footprint might provide the necessary energy delivery. The bundle of projects includes 2,400 miles of 345-kV and lower-voltage lines, 320 miles of 500-kV lines, 270 miles of 765-kV lines and 410 miles of HVDC lines.

At 50% penetration, an additional 70 projects across the footprint could help, including 590 miles of 345-kV and lower-voltage lines, 820 miles of 500-kV, 2,040 miles of 765-kV and 640 miles of HVDC. Li said the transmission additions would be particularly helpful in reducing wind curtailment in the northern part of the footprint, where wind capacity will be ubiquitous.

“We evaluated more than 11,000 [transmission project] candidates,” Li said. MISO staff have repeatedly said the results will not be used directly in transmission planning. They also clarified the study was not conducted with the goal of carbon reduction, saying it only demonstrates the challenges the system might encounter as solar and wind generation flourish.

“That’s a lot of transmission,” McIntire quipped to laughter. She urged MISO to examine the benefits of co-located storage and other ways to maximize existing transmission capability before it starts studying new transmission plans.

Other stakeholders agreed that MISO was suggesting a need for a staggering amount of transmission. Some said the jump in transmission needs from a 30% to 40% share of renewables seemed too high to be believable.

No Agenda

“We do see these drastic needs at certain intervals. It’s a non-linear trend as we deploy renewables,” Bakke said. “That discontinuity at very high renewable levels requires more transfer capacity.”

Bakke said MISO will begin relying more on regional energy transfers, which in turn will become more unpredictable, leading to a need for increased EHV thermal line capabilities.

“Existing infrastructure becomes inadequate for fully accessing the diverse resources across the MISO footprint,” Bakke said.

Not only will the footprint eventually need new physical lines, but it will require more technology on transmission lines, including synchronous condensers, more transformers and HVDC capabilities, staff said.

“As we see more renewable integration, we see additional types of technology needed to help support the system,” Bakke said. “It’s a portfolio of solutions that best enable renewable deployment in the system.”

Bakke said MISO is making no proposals for new technology or lines as a result of the study. “We’re trying to point out where we see these issues … to see if our processes should change and what we need on the system long-term,” he said.

MISO found that a diversity of technologies and geography improves the ability of renewables to serve load. Bakke said storage facilities, the load-taming abilities of electrification and other demand-side management can enable more renewable penetration. He also noted that thermal generation can begin scheduling outages during times where renewable output is predicted to be abundant.

The RTO also said the number and severity of thermal overloads starts to increase at a 20% renewable penetration and becomes widespread especially in the western portion of the footprint at a 50% penetration. It said it will need more thermal mitigations on higher-voltage lines. Likewise, it will encounter dynamic stability issues beyond a 20% penetration.

To counter small-signal instability, MISO said it may need must-run units equipped with power system stabilizers or specially tuned batteries to support grid reliability beyond a 30% penetration.

But MISO now says frequency response performance remains stable up to 60% renewable penetration. The newest result is even more optimistic than its July announcement that its grid can withstand major reliability risks even when renewables reach 40% of the generation mix. (See MISO: Grid Can be Stable at 40% Renewables.)

“We see needs on the thermal side greater than needs on the voltage side,” Bakke said.

WPPI Energy’s Steve Leovy said MISO may need to more thoroughly examine steady-state issues starting with the generation interconnection queue. He recommended the RTO screen for such issues there.

Where’s the Storage?

McIntire pointed out that much of future solar development is predicted to be solar paired with storage, which could change what system needs MISO identifies.

Examining how storage can help a future fleet mix will be included in the upcoming phase of MISO’s renewable impact study. Stakeholders have repeatedly asked the RTO to study heavy wind and solar generation balanced by storage facilities. Some stakeholders predicted that if storage is optimizing wind and solar generation, MISO won’t forecast nearly as many energy delivery issues.

McIntire urged that the next phase of the study examine other less traditional solutions.

“Largely you’ve been looking to transmission and the existing thermal generation,” she said.

Bakke asked stakeholders to send his team examples of nontraditional solutions for evaluation.

November 19, 2019

PJM MIC Briefs: Nov. 13, 2019

VALLEY FORGE, Pa. — The FERC to PJM Gens: Use or Lose Capacity Rights.)

The changes, endorsed by the Markets and Reliability Committee in April, require existing capacity resources not offered in three consecutive auctions to change to energy-only status. A resource receiving a must-offer exception must also file a plan showing how it will satisfy Capacity Performance requirements or forfeit its capacity interconnection rights. Resources would be granted exceptions for no more than two auctions. (See Load Interests Endorse PJM-IMM M u st-offer Proposal.)

Manual 15 Clarifications on VOM Costs

PJM offered a first read of Manual 15 revisions that clarify that market sellers can only change the format of maintenance adders — such as $/MMBtu, $/MWh or $/start — during the annual review period for energy offer components.

Staff will add section 2.6: Variable Maintenance Costs to reflect this after promising to do so in the proceedings for ER19-210, PJM’s filing to include variable operations and maintenance costs in energy offers. FERC partially accepted the RTO’s Tariff revisions in April but asked for more clarity on what maintenance costs sellers can include in their energy market offers. (See FERC to PJM: Clarify Allowable Costs for Energy Offers.) FERC accepted that compliance filing in August.

PJM will seek endorsement from the MRC in December and from the Members Committee and Board of Managers in January.

Border Rates

PJM presented a first read of revisions to Manual 27: Open Access Transmission Tariff Accounting that will reflect FERC’s recent order on border rate calculations (ER19-2105).

In June, PJM transmission owners submitted a filing that updates the yearly border charge to prevent network integrated transmission service (NITS) customers — network load located outside the RTO’s boundaries but served from within — from subsidizing border and non-zone service rate customers who use transmission service through and out of PJM. (See Settlement Hearing Set for PJM Border Dispute.)

FERC accepted the TOs’ filing subject to refund, with an implementation date of Jan. 1, 2020, but also set a paper hearing and settlement procedures for involved parties to work out their differences over the proposed methodology behind the rates.

Ray Fernandez, of PJM’s market settlements development department, said the manual revisions will move forward but acknowledged that refunds will be issued if changes to the methodology are approved in a settlement.

Fuel-cost Policies

Stakeholders from the MIC special session for fuel-cost policies brought updated proposals to the committee on Thursday, five months after a first round of debates among stakeholders produced no further consensus. (See PJM Stakeholders Still Divided on Fuel-cost Policies.)

PJM — Adrien Ford, ODEC | © *RTO Insider*

PJM moved off the status quo and offered an alternative package of rule changes that included a much desired “impact factor” when assessing penalties on market sellers for breaking their fuel-cost policies. A joint stakeholder plan and another sponsored by the Independent Market Monitor would also offer impact factors — though the specific calculations differ — and reduce penalties when market sellers self-identify violations.

Adrien Ford of Old Dominion Electric Cooperative said the joint plan aims to “encourage a culture of compliance” among market sellers.

“According to PJM, 75% of the penalties were assessed on generators that had no market impacts,” she said. “That’s why we want to introduce the impact factor. We are just trying to say, ‘Look, if there’s an impact, there should be a penalty. If there’s no impact, there should be a penalty, but it should be a traffic ticket approach.’”

PJM’s interpretation of the fuel-cost policy debate | *PJM*

While PJM’s plan would reduce penalties by 50% when market sellers self-identify, the RTO did not agree with stakeholders’ creation of a safe harbor provision that protects against situations “not contemplated by the fuel-cost policy.” Melissa Pilong, of PJM’s operations analysis and compliance department, said the provision would encourage market sellers to provide less detailed fuel-cost policies.

Then there’s the issue of temporary fuel-cost policies and PJM’s ability to revoke existing policies, potentially forcing market sellers to submit a zero cost-based offer. Current practice allows market sellers to provide temporary policies that include just heat rate and selling hub — a rule that PJM’s alternative package would eliminate.

“If a fuel-cost policy were to be revoked and mitigation would be offered at zero, the incentives for the generation owner would be, in many cases, submit a forced outage,” said E-Cubed Policy Associates President Paul Sotkiewicz, representing Elwood Energy. “From a reliability standpoint, I can’t imagine why PJM would want to do that.”

PJM staff bristled at the implication that they would revoke fuel-cost policies randomly and at will, noting that the RTO would act in good faith to discuss issues with a market seller first.

“We’ve never revoked a policy,” said Glen Boyle, a manager in PJM’s operations analysis and compliance department. “But we need to have the ability to do so.”

Ford said existing manual language about revocation “isn’t precise” and leaves too much undefined for market sellers.

“The market sellers are just looking to understand when and why something might be revoked and not be forced into a must-offer obligation or a must-offer of zero,” she said. “I don’t think it’s reasonable to have this unclear, looming threat that can really turn things completely upside down for a company. The more we talk about it, the more uncomfortable I am with the status quo.”

Boyle agreed that further consensus could be reached where the RTO allows temporary fuel-cost policies to be submitted alongside their permanent counterparts in the event that revocation occurred.

November 19, 2019

PJM Operating Committee Briefs: Nov. 12, 2019

VALLEY FORGE, Pa. — PJM staff told the Operating Committee last week that questions still remain about why their load forecast veered so far off course during a two-day spell of hot weather across the region last month.

Speaking at the committee’s Nov. 12 meeting, Rebecca Carroll, PJM’s director of dispatch, said staff’s backcasting analysis found that an early-arriving cold front in the ComEd and FirstEnergy zones on Oct. 2 impacted temperatures during the two-hour demand response event, accounting for a portion of the 4,500 MW of anticipated load that never materialized on the system. (See PJM, Stakeholders Baffled by DR Event.)

That same analysis, however, revealed that temperatures in the Mid-Atlantic and AEP zones were higher than initially forecast — meaning the missing load and unusual price signals have a different, unknown cause.

“According to all of our data, the load in AEP should have come in higher and quicker and more significant than what it did, even though we called the pre-load management in this area,” she said. “There’s several hundred megawatts we can’t account for.”

The trouble began Oct. 1, when PJM’s peak load exceeded its forecast by 5,500 MW, knocking the RTO into a spinning reserves event and triggering shortage pricing for three five-minute intervals. Carroll said PJM also called upon 800 MW of shared reserves from the Northeast Power Coordinating Council to compensate.

The following morning, operators lost a 765-kV line in the AEP zone, and 2,000 MW of generation called upon the day before failed to start. Those losses, in combination with a peak load forecast of 131,000 MW and anticipated congestion over the Hyatt transformer and the Peach Bottom-Conastone 500-kV line, prompted staff to call up 725 MW of long-lead DR resources for a pre-emergency load management event. The decision triggered a performance assessment interval (PAI) that lasted from 2 p.m. until approximately 4 p.m. in the AEP, Dominion, Pepco and BGE zones.

What should have happened next, according to several stakeholders, was a rise in LMPs for those zones, set by DR operating during the PAI. Instead, prices in the AEP zone tanked, and 4,500 MW of load never came onto the system.

PJM had hoped backcasting could solve the mystery of the missing megawatts, but Carroll said last week that more answers will likely come when the official DR data become available next month.

“I don’t buy this missing load argument,” said Dave Mabry, of McNees Wallace & Nurick. “I’m not sure we’ve got a missing load issue as much as we have a forecast issue. It seems like there is something else going on with the backcasting.”

Zonal contribution to load forecast error on Oct. 2, 2019 | *PJM*

Mabry suggested that a large industrial-use customer participating in DR could account for the “missing nodal load” — a possibility that Joseph Mulhern, a senior engineer at PJM, said staff were still considering.

“That’s one of the things that we are trying to look into now … mapping the nodes where we see this behavior to demand response customers,” he said. “It’s the first time we’ve looked into anything like this, so we aren’t sure what we will get or what the outcome will look like.”

He said staff attribute “a significant amount of missing load to DR,” but not all of it. He also said a lack of visibility at the distribution level and the rarity of 90-degree weather in October may also have played a role.

“When there is an unusual day that’s not got a lot of history, that can lead to errors,” he said.

Black Start Packages Anticipated in ‘Early 2020’

PJM’s Janell Fabiano said that stakeholders will present new rules for black start resource fuel requirements in “early 2020.”

Stakeholders began meeting in July 2018 to reconsider whether the existing fuel requirement of 16 hours proved sufficient given PJM’s focus on resilience in recent years. The group is also considering ways to mitigate high-impact, low-frequency events across all black start resources and fuel types.

The D.C. Office of the People’s Counsel, Calpine, PJM and Monitoring Analytics continue to work on four similar plans to define fuel assurance and tweak the hourly reserve requirement. Fabiano said stakeholders will bring the finalized packages to both the OC and the Market Implementation Committee for votes early next year. Changes will not move forward without support from both committees, she said.

Winter Weekly Reserve Target Endorsed

The OC endorsed weekly winter reserve targets for 2019 that remain unchanged from last year. The targets for December, January and February are 22%, 28% and 24%, respectively.

Part of the reserve requirement study, the targets help staff coordinate planned generator maintenance scheduling during the winter and cover against uncertainties associated with load and forced outages.

PJM also sets a 0% goal for its loss-of-load expectation (LOLE) in the winter, preferring instead to expect higher LOLEs throughout the summer.

PJM’s Operating Committee meets Nov. 12 at the Training and Conference Center in Valley Forge, Pa. | © *RTO Insider*

Preliminary Day-ahead Scheduling Reserve Requirement Approved

The committee also endorsed PJM’s new day-ahead scheduling reserve requirement (DASR) of 5.07%.

The DASR is the sum of the requirements for all zones within PJM and any additional reserves scheduled in response to a weather alert or other conservative operations.

PJM will seek endorsement for the change at the Markets and Reliability Committee and implement the new requirement in Manual 13 revisions.

Stakeholders Sunset NERC Ratings Initiative Task Force

Stakeholders approved PJM’s request to sunset the 2011 NERC Ratings Initiative Task Force.

The group held more than 30 webinars over three years to address a NERC alert that asked RTOs to “verify that field conditions are consistent with established ratings.”

The task force created an automated process to notify members of pending NERC outages. Since adopting the new procedures, PJM has received 1,386 outage and derate tickets, completing about 65% of submitted requests. About 9% impacted the system, according to PJM’s data.

OC Meetings Moving to Thursday in 2020

PJM’s standing committee week will look a little different in 2020.

The OC will convene on Thursdays, while PJM’s Planning Committee and Transmission Expansion Advisory Committee will move to Tuesdays. The MIC will remain on Wednesdays.

PJM Manuals Endorsed

Manual 03A: Energy Management system (EMS) Model Updates and Quality Assurance (QA) — Cover-to-cover periodic review. Adds a new section on PJM’s modeling philosophy.

Manual 3: Transmission Operations — Cover-to-cover periodic review. Updates dozens of terms and values in sections 1, 3, 4 and 5 and Attachments A and B.

Manual 14D: Generator Operational Requirements — Minor changes identified through the Distributed Energy Resources Ride Through Task Force that apply to distribution-connected generators connected to radial distribution lines of voltage less than 50 kV. The revisions also direct DERs to appropriate transmission owner engineering and construction standards, a standalone document on PJM’s website. The term “generating facilities” was also added in section 7.1.1: Generator Real-Power Control.

– Christen Smith

November 19, 2019February 12, 2025

NEPOOL Markets Committee Briefs: Nov. 12-13, 2019

In a two-day meeting last week, the New England Power Pool Markets Committee continued work on ISO-NE’s proposed Energy Security Improvements (ESI) proposal, with discussions on LNG supplies, market mitigation and a second demand curve.

The RTO has five months to file a long-term fuel security mechanism under FERC’s second extension since its original order last July (EL18-182). The new deadline is April 15, 2020.

The RTO’s lead analyst for market development, Ben Ewing, started the two-day meeting by presenting on the forecast energy requirement (FER) and clearing energy imbalance reserve (EIR) awards to clear the constraint.

The FER constraint ensures that the RTO can meet forecast load throughout the next operating day. It currently is applied after the clearing of the day-ahead market through the reserve adequacy assessment (RAA) process, an “out-of-market” approach, Ewing said.

Under ESI, the FER will be applied in the clearing of the day-ahead market — satisfied by physical generation, net scheduled interchange and EIR awards.

NEPOOL rules prohibit RTO Insider from quoting stakeholders’ comments during the meeting. However, after the meeting, ISO-NE and other speakers approved the quotes attributed to them to amplify their written presentations.

“Including the FER in the day-ahead will provide a clear market solution to ensuring we’re able to meet the forecast load in real time and will better signal the cost of having a reliable operating plan, and provide compensation and incentives for those resources we’re relying on for meeting that reliability requirement,” Ewing said.

The day-ahead clearing typically results in excess supply to meet the FER and operating reserve requirements, making supplemental commitments in the RAA process rare — with zero in 2019 to date, he said.

The RTO is proposing to begin compensating that excess “online” capacity — the capability, or headroom, of scheduled generators above what they cleared in the day-ahead market.

The FER would create a second demand curve in addition to the existing one for bid-in energy demand of market participants. Similarly, it would result in a second constraint, simultaneously clearing physical energy supply offers and energy options to satisfy the FER.

The day-ahead LMP would remain the incremental cost to satisfy another unit of bid-in energy demand. The FER price is the incremental cost to satisfy another unit of forecast demand.

“An online EIR approach is reasonable and practicable, and we will be glad to consider refining it further as technology permits,” Ewing said.

“I think this is a big step toward resolving some of our issues,” Brett Kruse, vice president of market design at Calpine, told RTO Insider after the meeting.

Interchangeability between the different products has been an issue for Calpine all along the design process, he said.

“I’m not sure that some product bifurcation isn’t necessary, but I’m finally getting an appreciation of why [ISO-NE planners] are doing things without regard to which option they get paid for, and why they currently think that they should all get one price,” Kruse said.

The schedule calls for further discussion by the MC over the next few months and a vote on Tariff language and submitted stakeholder amendments at its March 2020 meeting ahead of a vote in April by the Participants Committee.

Enhancing ESI Impacts Analysis

ISO-NE economist Chris Geissler and Todd Schatzki of Analysis Group presented enhancements to the modeling used in the impact assessment of ESI, with Schatzki taking the lead for a “look under the hood” at the specifics of three key changes to the modeling: evaluation of non-winter months independent of winter months; enhancements to the model’s fuel inputs and logic; and adding price-responsive demand (PRD) to EIR.

The RTO is responding to stakeholder concerns and will evaluate non-winter months independent of winter months but will not aggregate the studies into a single annual case, he said.

“Separate analysis of winter months will allow continued focus on the energy security outcomes that are of greatest concern during the winter months and will enhance the information given to the committee as it deliberates the proposed rule changes,” Schatzki said.

Modeling of fuel supply accounts for storage and delivery limitations, while modeling EIR ensures that there is enough energy available to meet the forecast energy level in each hour, he said.

The planners are analyzing resource-level fuel inventory based on multiple parameters:

- - Initial, beginning of winter, inventory levels;
  - Trigger levels for replenishment: balancing costs of refilling too frequently (holding costs) and costs of refilling too infrequently (lost revenues);
  - The replenishment lag: one day for trucks, four for barges; and
  - Replenishment rate: Different replenishment rate for resources relying on trucks and barges. The rate is projected to be 33% higher with ESI.

“Re-evaluation of fuel parameters will allow the model to better represent potential market and reliability impacts associated with ESI,” Schatzki said.

The New England States Committee of Electricity (NESCOE) submitted a memo expressing its concern that a market power analysis “might not show a problem if it fails to evaluate the conditions that could create vulnerability to exercise of market power (such as a tighter supply/demand balance), or if it fails to model ‘real world’ conditions.”

Schatzki said changes in global LNG prices could affect the LNG supply at the terminal.

“In principle, if LNG prices went way down or way up, that might affect the LNG storage decision and the eventual in-winter supply, given the resulting risk of forward committing to LNG supplies,” Schatzki said. “A lot of that procurement happens in advance of the winter.”

Schatzki said his company’s analysis was “very conservative.”

“We assume every day that the terminal, in this case Repsol, is full every day,” Schatzki said. “And whether that’s a reasonable assumption or not … we made the conservative assumption that there is fuel available.”

On EIR, Schatzki said that properly accounting for day-ahead energy and EIR interactions requires modeling PRD.

“Without price-responsive demand, the model cannot substitute between energy and EIR, but including price-responsive demand allows the model to endogenously solve for energy and EIR quantities,” he said.

Market Power Analysis and Mitigation

Concurrent with discussions regarding conceptual mitigation approaches, ISO-NE will conduct a market power assessment (MPA), according to a memo submitted by Mark Karl, the RTO’s vice president of market development.

The central purpose of an MPA is to determine whether market power is an empirically supported concern. If so, an MPA helps to identify the specific conditions, frequency and extent to which individual participants may be able to profitably exercise market power, the memo said.

ISO-NE Chief Economist Matt White said the memo addresses stakeholder concerns by laying out what the RTO expects External Market Monitor David Patton to address in his market mitigation analysis:

- - How mitigation of co-optimized day-ahead energy and ancillary services are implemented in other regional markets where Potomac Economics is also the EMM, and the EMM’s perspective on the effectiveness of those mitigation measures;
  - Whether and how the mitigation lessons from those regions could be usefully applied to the co-optimized day-ahead energy and ancillary services market proposed by ISO-NE;
  - Any expectations regarding potential competitiveness of the proposed day-ahead energy and ancillary services market in New England, given the information presently available and Potomac Economics’ experience; and
  - Its perspectives on must-offer requirements for resources with capacity supply obligations (CSOs).

“Our understanding is this is a voluntary market, and if there is any change that will be known to stakeholders before moving forward,” White said.

Stakeholder Proposal Updates

Jeff Bentz, NESCOE director of analysis, reiterated the states’ position.

“We continue to believe that the possible modifications to the strike price formula, a must-offer requirement as part of a market power mitigation approach and no [replacement energy reserves] in the non-winter months, benefit consumers and will do so without adversely impacting the changes ISO-NE is trying to achieve,” Bentz said.

“Our main concern continues to be market power and mitigation, and the must-offer requirement is only a component of this, so we look forward to the continued work on mitigation in the following months,” he said.

Christina Belew, of the Massachusetts attorney general’s office, confirmed that the office has withdrawn its alternative prop o sal prepared by London Economics that recommended a simple auction format of sealed bids with a uniform clearing price.

With respect to proposed amendments to ISO-NE’s ESI design, Belew said, “We wanted to let you know that the three amendments we offered in September are still in play, and depending on how ESI develops over the coming months, we may re-urge one or more of them, perhaps offer new ones.

“Like NESCOE, we have requested additional analysis that we haven’t received yet, so the results are going to inform our actions,” Belew said. “We expect to be back with substantive comments after the first of the year.”

NESCOE Intent on EER Revisions

Bentz presented NESCOE’s proposal for Tariff revisions regarding energy efficiency resources (EER) and related capacity obligations during scarcity conditions.

He said that NESCOE is seeking stakeholder feedback and intends to move forward in proposing a Tariff change that would implement Shaping Option A as taken from the Demand Resources Working Group final report issued in July.

Shaping Option A would estimate hourly EER performance as a function of established on-peak EER savings and system load levels.

“Under the current implementation, such resources are guaranteed to always incur a penalty during any event that occurs outside of on-peak or seasonal peak hours, which contradicts the language in the FERC order,” Bentz said.

FERC ruled in May 2014 that energy efficiency capacity performance payments should be calculated only for capacity scarcity conditions occurring during peak hours (ER14-1050).

Providing certainty to EERs is important to New England states, he said.

EERs are not similarly situated to other capacity resources because they do not actively perform in real time — they represent a predetermined level of load reduction that is constant as a percentage of that resource’s load — and therefore are not able to respond to the ISO-NE proposal’s performance incentive.

NESCOE will work with the RTO to create the appropriate Tariff and manual changes needed to implement Shaping Option A and present those changes at next month’s MC meeting ahead of a vote in January 2020. The organization will then seek a Participants Committee vote in February.

IMM Reports Q3 Energy Costs down 27% Y-o-Y

The RTO’s Internal Market Monitor issued a quarterly report showing summer 2019 energy and capacity market costs down significantly, with energy costs at $967 million, down 27% from a year ago, driven by a decrease in natural gas prices and lower loads.

Wholesale market costs totaled $1.74 billion, a 26% decrease from $2.36 billion in summer 2018, IMM David Naughton said.

COO Vamsi Chadalavada reported earlier in the month that prices in the region’s energy markets have been hitting historic lows. (See NEPOOL Participants Committee Briefs: Nov. 1, 2019.)

Naughton highlighted that two new rule changes went into effect on June 1: delayed commercial operation rules; and must-offer requirements for do-not-exceed (DNE) dispatchable capacity market resources such as wind. Early market reaction has been consistent with expectations, he said.

The first change shifted responsibility for covering “undemonstrated” capacity from the RTO to the participant, to address new resources that fail to meet their commercial operation target. Late resources that fail to shed their CSOs in secondary markets face a failure-to-cover charge for the “undemonstrated” capacity.

Over the first three months, 19 resources, predominantly demand response, were charged $500,000 for capacity shortages. Charges declined as resources reacted by offloading CSOs.

In addition, he said three new gas-fired generators with a combined CSO of more than 1,000 MW achieved commercial operation and did not incur failure-to-cover charges: Canal 3 (333 MW), Bridgeport Harbor 5 (484 MW) and the Medway Peaker (195 MW).

Naughton said wind generation offer behavior changed as expected now that DNE dispatchable generators with CSOs must offer all of their expected real-time generation into the day-ahead market. DNE wind generators increased their quantity of energy offered in the day-ahead market and offers reflected the expected level of real-time production, Naughton said.

Cleared volumes increased in the first month but declined to pre-rule change levels as offer prices began to increase, while cleared virtual supply at wind nodes decreased from 25% to 16% of real-time wind production.

State Changes to GIS, Rules

The MC by a show of hands unanimously approved sending changes to the NEPOOL Generation Information System to the GIS Operating Rules Working Group.

The Maine Public Utilities Commission and the Massachusetts Department of Energy Resources requested the changes, which relate to the Maine renewable portfolio standard and the Massachusetts Clean Peak Standard (CPS).

The Maine Legislature in September made several changes to the state’s RPS that require changes to the GIS.

The CPS was signed into law in August, and the addition of the CPS certificates to the GIS would require, at a minimum, the addition of “CPS Resources” and “Clean Peak Standard” to various provisions of the rules, NEPOOL Counsel Lynn M. Fountain said.

The changes to the GIS and the rules related to the CPS would become effective on July 1, 2020.

Sunset of Fuel Security Reliability Review

The MC voted to recommend the PC approve the sunset of the fuel security reliability review provisions following Forward Capacity Auction 14, one year earlier than currently planned.

The RTO’s assistant general counsel, Chris Hamlen, presented the proposed changes to Market Rule 1.

The MC in September approved amending Market Rule 1 to limit the retention of resources needed for fuel security to a two-year maximum.

The RTO wants the change to become effective prior to March 13, 2020, the FCA 15 deadline for retirement delist and permanent delist bids.

— Michael Kuser

November 17, 2019

Online Voting Tops WECC MAC Charter Proposals

By Holden Mann

Members of the Western Electricity Coordinating Council’s Member Advisory Committee heard a number of proposed changes to the MAC charter at Wednesday’s meeting, most prominently a plan to authorize electronic voting.

The idea to allow electronic voting arose in last December’s strategic planning meeting, when members discussed ways to improve efficiency, said Utah Office of Consumer Services Director Michele Beck, who presented the proposals to the committee. As proposed, the measure would permit the MAC chair to call for a vote on specific issues discussed in at least one previous committee meeting, with seven to 10 calendar days’ notice before voting begins and at least three business days for members to submit their votes.

WECC voting — Utah Office of Consumer Services Director Michele Beck | *NASUCA*

In response to questions from some members about the wisdom of conducting committee business online, Beck emphasized that the electronic voting system is not envisioned as a replacement for MAC’s current approach. Online voting would initially be limited to “yes or no” votes, and normal quorum rules would still apply. The requirement that the issue under consideration was discussed at a prior meeting would ensure that MAC members have had an opportunity to suggest amendments or modifications before the vote.

“This is … a way to keep the business of the MAC moving forward, in particular in a case where we have … a very fulsome discussion in one meeting, that folks want to think on it a little further before making their actual vote, and it keeps our work moving forward in between meetings,” Beck said. “[But if] MAC representatives aren’t committed to that process, then … it won’t increase our efficiency and we should delete it.”

Also discussed at the meeting was a proposal to change the way MAC measures nonparticipation. Under the current standard, if a member has not attended six consecutive meetings, the chair may designate the position as vacant. However, this rule was created when MAC met every month; the committee now meets about every six weeks, and some members have expressed concern that this could result in seats being effectively unfilled for prolonged periods.

Several alternative measurements were proposed, with most members supporting vacating a seat after four consecutive missed meetings. This would ensure that the chair has the ability to remove a member after six months without contributing.

“Unless they’re ill, which would be an extenuating circumstance … [if you miss] four meetings, you’re out of here. There’s no excuse for that,” said Grace Anderson of the California Energy Commission. “I would be as clear and strong as possible here and say, definitely not less than four meetings would be a good approach.”

Other proposals brought to the committee included standardizing the formats of documents on WECC’s website, implementing term limits for MAC members and updating the charter to formalize the role of liaisons with other committees. These generated less discussion at the meeting, but Beck left the door open for members to request changes via email. Suggested changes will be considered for incorporation into the final version of the proposals, on which MAC members will vote at the next meeting in December.