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December 17, 2025

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PJM MIC Briefs: Sept. 11, 2019

VALLEY FORGE, Pa. — After a one-month delay, the PJM Market Implementation Committee on Wednesday endorsed two packages to update the RTO’s opportunity cost calculator.

The latest plan from Dominion Energy and Panda Power Funds would make what the sponsors called “modest improvements” to the calculator and include Manual 15 revisions so that it more closely resembles the Independent Market Monitor’s calculator that most stakeholders prefer using. Just under 84% of members voted in favor of the new package.

Jim Davis, Dominion Energy | © RTO Insider

When polled on PJM’s package — which maintains the status quo but also makes minor clarifications in Manual 15 — 51% of stakeholders also approved. Both plans will advance to the Markets and Reliability Committee for consideration, with the Dominion/Panda proposal considered first.

Critically, Panda and Dominion withdrew three other proposals that were discussed at the August MIC meeting, including one that eliminated PJM’s calculator altogether. (See “Opportunity Cost Calculator Vote Delayed,” PJM MIC Briefs: Aug. 7, 2019.)

“We thought that this would be a good compromise,” Dominion’s Jim Davis said. “We worked with PJM to see what they would be willing to change in a timely fashion.”

Monitoring Analytics, however, disagreed that the latest changes made PJM’s calculator any more similar to its own and said that Manual 15 changes were unnecessary.

“We think these are modest changes, we agree with that, but this brings us a little closer to the IMM calculator and lets us just focus on further documentation of the IMM calculator,” Davis said.

Monitor: Review ARR/FTRs to Improve the Allocation of Congestion Rights

The Monitor told the MIC that the existing constructs for auction revenue rights and financial transmission rights leaves some load zones unable to sufficiently offset their congestion costs.

“There is a significant misalignment between congestion as it has been allocated and congestion as it has occurred,” said Howard Haas, chief economist for Monitoring Analytics. “Even if you were to claim all the rights made available to you, you cannot offset all off the congestion assigned to you.”

Zonal ARR and FTR total congestion offset (in millions) for ARR holders for the 2018/2019 planning period | Monitoring Analytics

Existing rules generated a 91.8% rate of congestion offset recovery across all of PJM last year, but the rate varies wildly from zone to zone, Haas said. For example, Dayton Power & Light only offset 27.2% of its congestion costs, while Baltimore Gas and Electric offset 367.3% of its costs, despite producing significantly different amounts of congestion, according to the Monitor’s table.

Howard Haas, Monitoring Analytics | © RTO Insider

Both PJM and stakeholders said they were generally supportive of exploring the issue, but some worried the problem statement and issue charge as presented were “too narrow.”

“I believe the GreenHat [Energy] report said we should take a comprehensive look at the FTR/ARR design,” said Exelon’s Sharon Midgley, noting that the Financial Risk Mitigation Senior Task Force is instead focusing on other credit and risk policies post-default. “This issue charge is leading towards a solution that is perhaps a little too narrow.”

Haas said that the key work activities listed in the issue charge provide appropriate room for that discussion. The deliverables would require stakeholders to identify the causes of congestion misalignment and decide whether changes to the market design could fix the problem.

“I would like to keep this more broad,” Midgley insisted. “All stakeholders might not necessarily share the same exact view on your description of the problem to be solved here.”

Other stakeholders agreed. Vitol’s Joe Wadsworth said he would like to see the rolling monthly auction option that PJM has presented at prior task force meetings added into the scope of the Monitor’s proposed review. The issue charge will be up for approval at the October MIC meeting.

Regulation Historic Performance Score

PJM presented revised Manual 11 language that would address a gap in missing historical performance scores used for regulation market clearing.

The MIC endorsed the manual changes in August, but at the MRC on Aug. 22, stakeholders took issue with the proposed value PJM would use when a system failure or other issue prevents the transfer of timely data.

The latest revisions will note that “if no historic performance scores are available from the last three days, then the latest available regulation qualification or regulation requalification test score for each resource by signal type is used.” A previous version indicated PJM would use a default value of 1 instead.

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NEPOOL Participants Comm. Briefs: Sept. 13, 2019

ISO-NE COO Vamsi Chadalavada’s operations report to the New England Power Pool Participants Committee on Friday showed the region’s energy market value dropped to $321 million in August, down $93 million from July 2019 and down $240 million from August 2018.

August natural gas prices were 11% lower than the previous month’s average values, with average RT Hub LMPs ($23.58/MWh) down 19% from July. The average day-ahead Hub LMP was $25.69/MWh for the month, and average August 2019 natural gas prices and RT Hub LMPs were down 36% and 40%, respectively, from August 2018 averages.

The average day-ahead cleared physical energy during the peak hours as percent of forecasted load was 101.3% during August, up from 99.9% during July. Day-ahead cleared physical energy is the sum of generation and net imports cleared in the day-ahead energy market.

ISO-NE results shared at the NEPOOL Participants Committee
| ISO-NE

Chadalavada drew attention to slides showing that forecasting trends are shifting fast. He said the RTO is continuing efforts to improve load forecast models and tools to produce better day-ahead and long-term load forecasts.

Consent Agenda

The Participants Committee voted unanimously to approve the single item on the consent agenda, revisions to OP-14E to incorporate energy storage as a type of asset-related demand that can be selected on ISO-NE’s form NX-12E, which provides the RTO with details that are not included in bid information.

ISO-NE and NESCOE Budgets Update

Kenneth Dell Orto, chair of the Budget and Finance Subcommittee, presented an update of the RTO’s proposed 2020 operating and capital budgets, as well as the 2020 budget of the New England States Committee on Electricity.

The budgets are in the final stages of development and will be voted on at the Oct. 4 Participants Committee meeting in Boston.

A more detailed presentation was provided to the subcommittee last month.

ISO-NE’s budget presentations to the New England state agencies, with their questions and the RTO’s answers, can be found here.

—  Michael Kuser

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Michigan PSC Settlement Resolves PURPA Clashes

By Amanda Durish Cook

Michigan regulators last week approved a settlement between Consumers Energy and solar developers, resolving arguments over the utility’s obligation to support small generation projects under the Public Utility Regulatory Policies Act.

The Public Service Commission’s approval of the agreement means that Consumers will interconnect new solar projects and is allowed to establish a new avoided-cost rate (ACR) for qualifying facilities (U-20615).

Consumers will now purchase power from an additional 584 MW worth of solar projects to be interconnected by 2023. About 170 MW of the projects will receive the current ACR, while the remaining 414 MW will be eligible to enter contracts at a rate based on MISO LMPs plus the capacity prices established in the RTO’s annual capacity auction. Solar developers Geronimo Energy, Cypress Creek Renewables and sPower stand to receive a cut of the first 170 MW of projects at higher rates.

The move will more than triple solar capacity in Michigan, which currently has more than 153 MW of solar. The settlement puts to rest five separate cases between Consumers and more than 40 entities. The settlement was signed by several QFs, Consumers, PSC staff and the Solar Energy Industries Association.

Public Utility Regulatory Policies Act benefits solar
Solar panel construction | Consumers Energy

Under PURPA, utilities such as Consumers are obligated to purchase electricity from independently owned QFs at rates that reflect a utility’s own cost to build new generation. Consumers’ existing avoided costs generally range from about $95 to $110/MWh, but the company has alleged the figures are outdated and above-market.

While the settlement will put some QFs in operation, its leaves many awaiting approval and compensation from Consumers. The company’s current PURPA interconnection queue is jammed at 3.3 GW, and several QF owners complained that the first version of its integrated resource plan didn’t do enough to clear the backlog. Consumers has previously mounted an unsuccessful bid with its state regulators to waive deadlines on reviewing QF applications for approval. The utility claimed it was simply overwhelmed by the more than 1,700 QF applications in the pipeline.

A previous settlement in June modified Consumers’ IRP so that the utility will now conduct an annual competitive bidding supervised by a third party for adding new capacity (U-20165). Consumers can only own up to half of the new capacity it secures through competitive bidding; the rest must come from power purchase agreements with unaffiliated companies. Any remaining capacity needs after bidding is complete can be filled by QFs.

Consumers this fall will bid out about 1,200 MW of new solar energy for the 2019-2021 time frame. Although the bidding will focus on solar generation, the utility said QFs of all fuel types will be allowed to bid.

The June settlement also stipulates that Consumers will use a five-year horizon instead of the previous 10-year outlook to determine whether it has a capacity need. Consumers will also have to file new ACRs for regulatory approval within 30 days of each annual bidding process. Current QFs with a PURPA-based contract will continue to get new PPAs regardless of Consumers’ capacity needs. Additionally, QFs 150 kW or smaller will receive PPAs based on the full avoided cost, also regardless of Consumers’ capacity status.

Last year, Michigan regulators lifted a 10-month suspension on the state’s new avoided-cost calculation for Consumers. The utility argued it didn’t need any additional capacity over the next 10 years and had put about 700 MW of solar projects on hold. The PSC rejected the argument, saying the utility’s IRP would determine whether it needed new capacity.

PURPA in Flux

Michigan isn’t the only state in the MISO footprint where utilities have tried to alter or discontinue their obligation to pay independent developers under PURPA, arguing that rates exceed actual avoided costs for new generation.

The 9th U.S. Circuit Court of Appeals ruled in June that it could not force the Montana Public Service Commission to compel NorthWestern Energy to purchase power from solar developers at originally established and higher ACRs. (See Montana PSC Racks up 2nd Lawsuit over PURPA Rates.)

FERC this summer also avoided addressing whether the addition of storage facilities at the Beaver Creek wind farm in Montana would put the project’s QF standing in jeopardy under PURPA when the owner withdrew applications to recertify the four 80-MW projects (EL18-195). NorthWestern argued last year that the addition of storage units to 80-MW wind facilities would put them over the PURPA megawatt limit.

In comments to the petition, the Edison Electric Institute said the case raised new issues for PURPA’s treatment of energy storage and urged FERC to hold off on deciding on the motion until it could address the issues of “modernizing” PURPA in a more comprehensive proceeding, given that on-site storage capability could increase a facility’s capacity beyond 80 MW.

FERC has been reviewing its implementation of the law since 2016, holding a technical conference in June of that year, but it has languished under numerous shakeups at the commission. However, one of its agenda items (E-1) for this month’s open meeting Thursday concerns “qualifying facility rates and requirements” and “implementation issues” under PURPA. The item is listed under both the docket FERC opened in 2016 (AD16-16) and a new rulemaking docket (RM19-15), indicating a Notice of Proposed Rulemaking is potentially imminent.

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PJM OC Briefs: Sept. 10, 2019

VALLEY FORGE, Pa. — Exelon told the PJM Operating Committee last week it is near agreement with RTO staff on business rules for non-retail behind-the-meter generation (NRBTMG) that would exclude retail community solar and aggregate net energy metering programs.

Exelon told the Markets and Reliability Committee in August that it approves of the concepts and reporting requirements outlined in the changes to Manuals 13 and 14D but wanted more time to review the differences in the application of the rules — specifically whether community solar programs and aggregate net energy metering are within scope. It asked the MRC to delay its vote for 30 days. (See “Non-retail BTM Generation Vote Delayed,” PJM MRC Briefs: Aug. 22, 2019.)

PJM Operating Committee underway
PJM’s Operating Committee met on Sept. 10 in Valley Forge, Pa. | © RTO Insider

Since then, both parties have agreed that neither program should fall under the category of NRBTMG. Exelon will bring its revisions to the MRC meeting scheduled for Sept. 26, Sharon Midgley, the company’s director of wholesale development, told the Operating Committee on Sept. 10.

NRBTMG refers to resources used by municipal electric systems, electric cooperatives or electric distribution companies to serve load. They do not participate as supply resources in PJM markets but can be netted against their wholesale load to reduce transmission, capacity, ancillary service and administrative fee charges.

Hot August Spawned 4 Weather Alerts

Soaring temperatures last month spawned four hot weather alerts Aug. 18-21. A feedwater control valve issue also tripped units at Salem 2, creating the first spinning event of the summer.

Manuals Endorsed

Staff must update all three manuals to comply with FERC Order 841’s energy storage participation mandates.

Manual 14D adds metering requirements specific to energy storage resources, outage reporting requirements and generating unit reactive capability curve specification and reporting procedures.

In Manuals 36 and 40, PJM updated the exception to critical cranking power to include non-hydro energy storage resources and added a lower megawatt threshold for electric storage resource training requirements.

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MISO Resource Adequacy Subcomm. Briefs: Sept. 12, 2019

CARMEL, Ind. — MISO will suspend updates on its resource availability and need (RAN) project through November to allow time for analysis that may drive future draft rules.

During a Resource Adequacy Subcommittee meeting Wednesday, MISO planning adviser Davey Lopez said the RTO will skip the monthly RAN presentation at next month’s meeting to analyze its loss-of-load methodology, a possible seasonal auction and new capacity accreditation for planning resources.

By the first half of 2020, MISO expects to finish a filing to alter capacity accreditation.

MISO is mulling an available capacity estimate that includes a measure of historical availability and the impact of planned and maintenance outages in addition to already-counted forced outages. The RTO is also considering distinct accreditations for intermittent, load-modifying and emergency-only resources.

MISO RASC underway
The MISO RASC met in Carmel, Ind., on Sept. 11. | © RTO Insider

MISO also wants its loss-of-load expectation modeling “more closely aligned to the real world,” Lopez said. The new LOLE may rely on seasonal data and might become a seasonal result itself. More detailed data, including extreme weather scenarios, historical outages, actual load-modifying resource participation, external assistance from neighboring balancing authorities and the capabilities of intermittent resources may be incorporated.

Customized Energy Solutions’ Ted Kuhn urged MISO to be innovative in adjusting or redefining seasons. He said it might be that September is found to be sufficiently risky that it warrants a spot among the summer months, or a separate loss-of-load risk might need to be defined for winter.

“Just be thoughtful when you go through these, and don’t straight jacket solutions,” Kuhn urged.

Lopez said MISO will examine monthly risk and whether it should change the calculations behind its planning reserve margin and local reliability requirements.

MISO’s fall pause doesn’t mean other smaller RAN initiatives are on hold. The RTO expects to make a filing by October to improve the modeling of LMR participation in the capacity auction and create “reasonable expectations” for capacity availability during the planning year.

New PRA Deadlines Before FERC

MISO has filed with FERC to shift the offer window times and data submission deadlines for its Planning Resource Auction (ER19-2559).

The changes would allow more time for market participants to prepare data submittals to MISO and end the RTO’s middle-of-the-night closings and openings of the offer window.

MISO Manager of Capacity Market Administration Eric Thoms said the RTO expects a FERC ruling before the RASC meeting Oct. 9.

The filing would take effect beginning with the 2020/21 PRA, altering deadlines for demand response testing, submission of generator verification testing data, behind-the-meter registration, unforced capacity values and the posting of preliminary auction data. In most cases, the deadlines would be extended into the winter from late fall. (See “Timeline Change Next Year,” MISO Ponders Changes After Latest PRA.)

MISO is also proposing to open and close the offer window during normal business hours instead of the usual midnight-to-midnight run of the four-day window. The RTO requested permission to open the offer window at 8 a.m. ET and close at 6 p.m.

Thoms also said the RTO is readying the 2020/21 PRA in MISO software.

CONE Increases

MISO also filed its annual update of cost of new entry values this week, with prices up over last year’s estimates across all local resource zones (ER19-2781).

Michael Robinson addresses stakeholders at the MISO RASC
Michael Robinson, MISO | © RTO Insider

This year, staff and the Independent Market Monitor calculated the CONE at an average $251/MW-day for the entire footprint. Last year, the average CONE was about $238/MW-day footprint-wide.

Arkansas and East Texas’ Zone 9 has the lowest CONE value of about $237/MW-day, while Lower Michigan’s Zone 7 has the highest, with about $258/MW-day.

MISO’s CONE is used as the RTO’s maximum clearing price and maximum clearing offer in the PRA. CONE represents the estimated cost of constructing a 237-MW combustion turbine in different locations in the footprint.

Stakeholders asked why CONE numbers were up year-over-year. To that, MISO adviser Michael Robinson pointed to the philosophy behind Isaac Newton’s and Gottfried Wilhelm Leibniz’s calculus of infinitesimals.

Robinson said “several contributing factors” — including small upticks in cost of debt, operation and maintenance costs, and tax rates — contributed to the increase.

“When you add them all up, it contributes to about a 5 to 6% increase,” he said.

Wind, Solar, Storage Focus of New Deliverability Proposal

MISO will move ahead with a stricter capacity deliverability requirement for its intermittent planning resources.

“This is something we’re going forward with, so it’s not up for debate if we are or aren’t going to do this,” MISO’s Darrin Landstrom said.

Landstrom said MISO would return with a proposal and examples at the Oct. 9 RASC meeting.

According to the RTO, stakeholders were most receptive to an approach that would use an intermittent resource’s transmission service request value as the maximum output for calculating the average capacity factor, which would reduce capacity credits. (See MISO Deliverability Plan Prompts Skepticism.)

MISO expects to make a FERC filing in December. The proposal would only apply to wind, solar and electric storage resources that offer capacity beginning in the 2020/21 planning year. The RTO draws a distinction between conventional and intermittent resources for deliverability.

Still, some MISO stakeholders maintained last week that the RTO has not demonstrated its current process is causing stranded intermittent capacity during peak hours.

But Landstrom said the proposal will stave off potential problems from MISO assuming planning resources will perform to an installed capacity deliverability level when they’re only required to demonstrate deliverability up to an unforced capacity level.

“The IMM [and] FERC have recommended we close this gap, and MISO agrees with them,” Landstrom said.

— Amanda Durish Cook

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UPDATED: LaFleur Elected to ISO-NE Board

By Michael Kuser

Former FERC Commissioner Cheryl LaFleur was elected to a three-year term on the ISO-NE Board of Directors on Friday, just two weeks after leaving her job in D.C.

LaFleur will replace Director Raymond Hill, who is completing his third consecutive three-year term this month.

Re-elected were Directors Barney Rush and Vickie VanZandt, each of whom will begin their third consecutive term, the maximum allowed. Absent a waiver, an incumbent board member cannot serve more than three consecutive three-year terms.

Former FERC Commissioner Cheryl LaFleur appointed to ISO New England board

FERC Commissioner Cheryl LaFleur speaks at the Energy Bar Association’s annual meeting in May 2019. | © RTO Insider

Although LaFleur’s second term on FERC ended June 30, she served until the end of August, as allowed by law in the absence of a successor. She announced she would not be appointed to a third term in January. (See LaFleur Announces Departure from FERC.)

Returning to New England

The announcement represents a homecoming for LaFleur. Prior to joining the commission, LaFleur worked at National Grid, ultimately serving as executive vice president and acting CEO of the U.S. subsidiary. She had served at various times as COO, president of the company’s New England distribution companies, and general counsel.

LaFleur said in a statement that she was excited to join the board. “New England is my home and where I have spent most of my career, and I welcome the opportunity to be part of an organization that serves electricity consumers across the region.”

ISO-NE Board Chair Philip Shapiro said LaFleur “not only will bring insights from her long tenure at FERC, but also from her experience at National Grid.”

“Cheryl is a welcome addition to the ISO New England board,” ISO-NE CEO Gordon van Welie said. “The sum of her career experience will be put to good use as the region’s grid continues its transition to a future with cleaner, more distributed resources.”

Mr. Rush was re-elected to the ISO New England Board

Barney Rush | ISO-NE

Rush also serves on the board of Azure Power Global, which develops solar plants in India, and is a senior representative for Fieldstone, a regional investment bank that raises capital for power plants and infrastructure in Africa and other emerging markets. He is the former group CEO for Mirant Corp. in Europe. He is also the mayor of the town of Chevy Chase, Md.

VanZandt runs VanZandt Electric Transmission Consulting, based in Washington state, and is the Western Electricity Coordinating Council’s program manager for the Western Interconnection Synchrophasor Program. She retired from the Bonneville Power Administration in 2009 after 35 years, including a position as its senior vice president of transmission services. She served as BPA’s chief engineer for a decade.

Committee Assignments

Ms. VanZandt was re-elected to the ISO New England Board
Vickie VanZandt | ISO-NE

The slate of board candidates is selected by the Joint Nominating Committee, endorsed by members of the New England Power Pool’s Participants Committee and confirmed by the board and the New England Conference of Public Utilities Commissioners (NECPUC). The nominating committee is composed of 14 members: six PC members representing their sectors; one member of NECPUC; and seven members of the board.

Van Welie announced that the board had also elected Director Kathleen Abernathy to replace Shapiro as chairperson. Committee assignments, as listed in the CEO report posted with the meeting materials, are as follows:

  • Audit and Finance Committee: Michael Curran, LaFleur and Shapiro, with Christopher Wilson as chair;
  • Compensation and Human Resources Committee: Abernathy, Brook Colangelo and VanZandt, with Roberto R. Denis as chair;
  • Joint Nominating Committee: Abernathy, Curran, LaFleur, Rush, VanZandt and Wilson, with Shapiro as chair;
  • Markets Committee: Curran, LaFleur and Wilson, with Rush as chair;
  • Nominating and Governance Committee: Abernathy, Curran and Rush, with Shapiro as chair;
  • System Planning and Reliability Committee: Colangelo and Denis, with VanZandt as chair; and
  • Special Committee on Information Technology and Cyber Security: Colangelo and Wilson will serve on the temporary committee, with Colangelo as chair.

Age Limit

Voting directors on the RTO’s board serve staggered, three-year terms. A nominee cannot stand for election or re-election if they have reached the age of 71.

However, on Aug. 15, ISO-NE and NEPOOL filed amendments to the Participants Agreement to authorize the Joint Nominating Committee to waive the age limit (ER19-2616). That filing is currently pending and, if accepted, would permit the amendments to become effective Oct. 15.

ISO-NE said each of the candidates on the 2019 slate was under the age limit but declined a request for the current board members’ ages, calling it “personal information.”

“I can tell you that candidates’ ability to meet eligibility requirements are evaluated by the members of the Joint Nominating Committee and then by members of the NEPOOL Participants Committee, and all members of the board, including the slate taking office Oct. 1, currently meet the eligibility requirements,” ISO-NE Spokeswoman Marcia Blomberg said.

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PG&E and Insurers Agree to Settle Wildfire Claims

By Hudson Sangree

PG&E Corp. announced Friday it had reached an $11 billion settlement agreement with nearly all the insurers trying to recoup their payments to victims of wildfires sparked by the utility’s equipment in the past two years.

The insurers — collectively known as the Ad Hoc Subrogation Group — were the second largest bloc financially, after wildfire victims, that PG&E had to confront in its Chapter 11 reorganization proceedings begun in January.

The agreement must be approved by the bankruptcy court, along with other settlement offers by PG&E. The company had already agreed in June to settle claims by local governments and agencies against it for $1 billion.

“Today’s settlement is another step in doing what’s right for the communities, businesses and individuals affected by the devastating wildfires” of 2017 and 2018, PG&E CEO Bill Johnson said in a news release.

PG&E is attempting to exit bankruptcy by June 2020 to be able to take advantage of a new $21 billion wildfire recovery fund established by the state of California to compensate fire victims. The fund was created by Assembly Bill 1054, passed in July. (See Calif. Wildfire Relief Bill Signed After Quick Passage.)

It’s also trying to head off what’s essentially a hostile takeover attempt by its unsecured bondholders, which have offered PG&E a $30 billion cash infusion in exchange for a controlling interest in the utility and guaranteed payment of their notes. (See Judge Weighs Competing PG&E Bankruptcy Plans.)

In a separate statement, the Subrogation Group said it was accepting a settlement that’s a little more than half of what insurers claim they’re owed.

“While this proposed settlement does not fully satisfy the approximately $20 billion in group members’ unsecured claims, we hope that this compromise will pave the way for a plan of reorganization that allows PG&E to fairly compensate all victims and emerge from Chapter 11 by the June 2020 legislative deadline,” it said.

The deal PG&E struck with insurers is $2.5 billion more than the trust, capped at $8.5 billion, that PG&E proposed in its reorganization plan filed Sept. 9. In that plan, $16.9 billion was to be split about equally between individual wildfire victims and insurance companies. (See PG&E Offers $16.9B for Wildfire Claims in Chap. 11 Filing.)

Whether the increase for insurers means wildfire victims could get less will be determined in court, but victims’ lawyers had already criticized PG&E’s initial plan of compensation as falling far short of what they deemed acceptable.

PG&E filed a document Friday with the U.S. Securities and Exchange Commission showing it had secured promises of $14 billion in new equity investment to help cover its wildfire payment plan. It also said it was increasing its total compensation package for victims, insurers and local governments by $1 billion — still $1.5 billion short of Friday’s proposed increase for the subrogation claimants.

PG&E filed for bankruptcy in January, saying it couldn’t afford at least $30 billion in wildfire claims from a series of deadly and hugely destructive fires in 2017 and 2018.

Investigators with the California Department of Forestry and Fire Protection (Cal Fire) said PG&E equipment sparked November’s Camp Fire, the deadliest and most destructive in state history, and a rash of fires in Northern California wine country in October 2017.

PG&E is till being sued for the Tubbs fire
Insurance is helping homeowners rebuild from the Tubbs Fire, which destroyed part of Santa Rosa, Calif. | City of Santa Rosa

Cal Fire determined a private landowner’s faulty wiring started the Tubbs Fire, which leveled part of the city of Santa Rosa, killed 22 people and caused billions of dollars in damages in October 2017. But Judge Dennis Montali, of the U.S. Bankruptcy Court in San Francisco, allowed fire victims and insurers to move ahead with lawsuits in state court that blame PG&E for the Tubbs Fire.

Friday’s settlement includes the Tubbs Fire, a PG&E spokeswoman said, though the lawsuit remains active for now, pending the bankruptcy court’s approval of the settlement.

PG&E’s beleaguered stock price rose nearly 11% after Friday morning’s announcement, going from $10.10/share at close of trading Thursday to $11.18/share by 4 p.m. Friday.

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MISO Unruffled by Fall Supply-demand Outlook

By Amanda Durish Cook

CARMEL, Ind. — MISO doesn’t expect any challenges meeting demand this fall, announcing last week that its supply should outpace its relatively tame peak forecast by about 36 GW.

The RTO estimates it will have 148 GW in total available capacity for the season, plenty to cover an expected 112-GW fall peak.

Jenna Furnish discussing MISO's probable load for fall
MISO’s Jeanna Furnish | © RTO Insider

“That 112 GW is 3 GW lower than what we experienced in September 2017,” Jeanna Furnish, MISO manager of outage coordination, said at Thursday’s Market Subcommittee meeting.

But in keeping with the past several seasonal assessments, the RTO was careful to say that high-load, high-outage scenarios could trigger emergency procedures.

To generate its load forecasts, MISO partly relies on data from the National Oceanic and Atmospheric Administration, which has predicted higher-than-normal temperatures for the southern and eastern portions of the RTO’s footprint.

Furnish began the seasonal outlook by polling stakeholders on a family dispute. “When does fall start? The astronomical definition of Sept. 23 at 3:50 a.m. [EDT], or the meteorological definition of Sept. 1?”

Those at MISO’s headquarters overwhelmingly favored the astronomical approach.

MISO’s fall, however, is effective throughout September, where the risk of emergency procedures is most pronounced in the face of high load. During the month, the RTO could dip into its load-modifying resources and operating reserves in a 117-GW, high-load scenario even when outages aren’t considered a problem.

Furnish said a high-load, high-outage scenario paints a “bleaker picture” in which MISO might use the top end of its 13.7 GW in reserves. However, the RTO expects an average 111.3 GW of probable load during September. In October and November, MISO load is not expected to exceed 96 GW, and probable load will likely hover around 90 GW.

Furnish ended by joking she wouldn’t be doing her MISO duty if she didn’t urge members to submit outages as early as possible.

“Please make sure your company’s outages are in, for not only this fall, but also next spring. … It’s never too early to think about spring,” she said.

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Anticipating Boom, MISO Extending Dispatch to Solar

By Amanda Durish Cook

CARMEL, Ind. — After experiencing a surge in new projects, MISO is hoping bring solar generation under the umbrella of its dispatchable intermittent registration for market participation, the RTO signaled last week.

MISO’s proposal, issued Thursday, seeks to put solar generation on par with wind generation in the dispatch process. The method to be used provides a bit of déjà vu for some seasoned stakeholders.

Ken Zhu discussing how MISO would like to handle solar projects
Kun Zhu, MISO | © RTO Insider

Kun Zhu, MISO manager of resource retirement, said the proposal was precipitated by the flood of solar projects lining up for interconnection. “Quick story: Based on what’s coming in the queue, we’re set to have a big surge in solar,” he said in opening the Market Subcommittee meeting Thursday. “Now we expect the same challenge we saw 10 years ago,” referring to the wind generation boom that took hold about a decade ago.

Zhu said MISO’s plan is to require future commercial solar generation to register as dispatchable intermittent resources (DIRs), as it does for wind resources. Currently, solar generators can choose to be DIRs or simply remain intermittent resources, which are price-takers in the market and ineligible for dispatch. DIRs can submit price-sensitive offers and be dispatched by the market.

While MISO currently has just 243 MW of solar under the DIR registration, it reports that more than 9 GW worth of solar projects have executed generation interconnection agreements or are close to doing so. Beyond that, about 52 GW of solar are in the early stages of the interconnection study process.

“The time is now to expect the challenge and mitigate it,” Zhu said, adding that MISO can avert the growing pains it experienced in 2008 and 2009 when operators had to initially manually curtail wind generation over the phone. “It was cumbersome and not optimal and not ideal, and it caused big challenges in the control room.”

MISO won FERC approval in 2011 to create the DIR category for wind.

“We’re bringing solar to the same playground as wind,” Zhu said, pointing out that FERC recently accepted a similar change to solar treatment in SPP.

Just as in the original DIR filing for wind, MISO is proposing a two-year transition period to register solar resources. Solar projects with interconnection agreements before the time of the filing have two years to convert from intermittent resources to DIRs. Solar projects with no interconnection agreement in place before the effective date of the new tariff rule must register as DIRs immediately with no grace period.

Solar projects in the MISO interconnection queue
MISO

Customized Energy Solutions’ David Sapper asked how the proposal would treat hybrid solar and storage projects.

Zhu said the hybrid angle is outside the scope of the proposal — for now. MISO is holding a special workshop in early October to discuss the rules and implications around hybrid projects. (See MISO to Host Hybrid Projects Workshop.)

“Hybrid is a new topic. What we’re discussing now is 100% pure solar generation, limited by the weather,” Zhu said.

MISO hopes to make a Tariff filing sometime in December.

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FERC Orders Expanded Mitigation for LGE-KU

By Rich Heidorn Jr.

FERC last week rejected Louisville Gas & Electric and Kentucky Utilities’ proposed transition for exiting from market power mitigation measures the commission had imposed to address the companies’ 1998 merger and withdrawal from MISO in 2006 (ER19-2396, ER19-2397).

The rate de-pancaking mitigation provisions were imposed to resolve horizontal market power concerns. In March, the commission agreed the provisions could be removed because loads located in the LG&E/KU market would have access to enough competitive suppliers after the mitigation is removed. It conditioned the removal on a transition mechanism to protect customers that had relied on transmission service on the MISO system.

FERC said that “although it determined that there would continue to be a sufficient number of competitive suppliers in the LG&E/KU market if the de-pancaking mitigation was terminated, termination will affect the relative economics of competing suppliers in different markets by making the cost of purchases from resources located in MISO more expensive.”

Eligible for the transition were contracts by the Kentucky Municipal Power Agency to supply KU requirements customers that went into effect on May 1; a requirements contract between the city of Benham and American Municipal Power; a requirements contract between the city of Berea and AMP that went into effect on May 1; and a contract between the city of Owensboro and Big Rivers Electric Cooperative.

The commission said the proposed transition mechanism filed by the companies in July was overly narrow and spelled out changes the companies must make regarding which customers and power purchase agreements should be covered and the definition of “covered” transmission service requests. It also ordered changes regarding which MISO schedules are eligible for reimbursement, reimbursement adjustments and the handling of exports.

In an accompanying ruling rejecting rehearing of its March order, the commission also identified three additional customers as eligible for the transition: KYMEA and member cities Paducah and Princeton (EC98-2-002, ER18-2162-001).

LG&E serves 411,000 electric customers in Louisville and 16 surrounding counties. KU serves 553,000 customers in 77 Kentucky counties and five counties in Virginia. The two companies, which are now PJM members, are owned by Allentown, Pa.-based PPL.