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December 18, 2025

Overheard at gridCONNEXT 2019

WASHINGTON — This year’s gridCONNEXT — GridWise Alliance and Clean Edge’s third annual conference focusing on visions of the grid of the future — delivered the usual goods last week when it came to discussions of the advanced technologies and policies necessary to modernize how the U.S. produces and consumes electricity.

But a grim sense of urgency permeated much of the discussions, as speakers, panelists and audience members repeatedly reminded each other that the world is way behind on its decarbonization goals to limit the rise in the average global temperature to under 2 degrees Celsius, as documented by a U.N. report released last month. (See U.N.: Decarbonization ‘Key’ to Cutting Global Emissions.)

gridCONNEXT
GridWise Alliance and Clean Edge’s third annual gridCONNEXT conference was held Dec. 11-12 at the Liaison Capitol Hill hotel. | © RTO Insider

There was also much discussion about what is occurring around the world, and what the U.S. can do to help lead decarbonization efforts.

Here’s some of what we heard Wednesday and Thursday at the Liaison Capitol Hill hotel, just down the street from the U.S. Capitol.

Climate Crisis

The conference occurred during the final days of the 25th U.N. Climate Change Conference of Parties (COP25) in Madrid, which was widely seen as a disappointment. The talks ended with a partial agreement to put forward more aggressive emission targets than those of the 2015 Paris Agreement at next year’s conference in Glasgow, Scotland.

Multiple news reports described how poorer, developing countries grew frustrated with the talks over the lack of U.S. leadership and left early. Many countries, however, are waiting to see if a new U.S. president will lead to a stronger agreement than Paris, which the U.S. will exit on Nov. 4, 2020 — ironically the day after Election Day.

gridCONNEXT
U.S. Sen. Jeff Merkley (D-Ore.) | © RTO Insider

Attendees made clear how they felt about the climate issue when U.S. Sen. Jeff Merkley (D-Ore.) in a keynote speech Thursday mentioned the young Swedish activist Greta Thunberg being named Time’s Person of the Year and the room erupted in applause.

But most of the talk about the state of Earth’s climate was more dire.

A report by the U.N.’s Intergovernmental Panel on Climate Change last year found that even limiting global warming to 1.5 C — predicted to occur by 2040 if current trends continue — would still result in catastrophic effects in certain parts of the world, especially affecting developing countries, which are rapidly purchasing coal power technology from China to continue industrializing. (See IPCC: Urgent Action Needed to Avoid Climate Trigger.)

“I think people need to understand the huge difference in just half a degree” Celsius, Melanie Kenderdine, principal for the Energy Futures Initiative (EFI), said Wednesday. “Urgency becomes very important when every 10th of a degree matters. … I approach our pathways to decarbonization from the position of what we can do now, what can we do consistently, [and] what should we be investing in for the future, because we cannot get there from where we are now. But we need to start now and stop fighting over it.”

“Is this the part where I’m supposed to disagree?” joked Rich Powell, executive director of ClearPath, a nonprofit that focuses on conservative policies to address climate change.

Kenderdine — who worked at the Department of Energy in the Obama administration under Secretary Ernest Moniz, the founder and CEO of EFI — and Powell were speaking on a “point-counterpoint” panel on the best policies to decarbonize the grid. But there was little disagreement or debate among them.

From left to right: Exelon Utilities CEO Calvin Butler; Melanie Kenderdine, principal for the Energy Futures Initiative; and Rich Powell, executive director of ClearPath | © RTO Insider

Powell said that for most of the world, “priority 1 is to staunch the bleeding.” Through China’s Belt and Road Initiative, for example, Pakistan is building subcritical coal plants. “To get yourself out of a hole, first you need to stop digging, and in many parts of the world, we’re still digging.”

He said the U.S. needs to focus on researching and developing “higher performing, more affordable, flexible clean energy technologies” for not just domestic use but to export to compete with China. Rather than subsidies for specific resources, such as wind and solar, the U.S. should put in place a “technology-neutral” subsidy for any new decarbonizing tech that phases down over time. “If something needs to be permanently subsidized, we can’t expect a Nigeria or Indonesia or Bangladesh to permanently subsidize clean energy in their markets,” Powell said. “We need technologies that are so good, you could actually imagine them being like-for-like substitutes for subcritical coal in the developing world.”

DOE already does “invest a huge amount in basic research,” Kenderdine said. “But I’m not sure that basic research is not all that the federal government needs to be doing right now. It needs to … move into different spaces.”

Around the World in Two Days

There was also much discussion on what the U.S. could learn from E.U. countries’ actions.

Angelina Galiteva, CAISO | © RTO Insider

On Wednesday morning, Angelina Galiteva, founder of the Renewables 100 Policy Institute and a member of the CAISO Board of Governors, talked about how Europe is investing not in battery storage but “using their excess capacity from wind [to] make hydrogen,” which can be used to generate electricity — a practice virtually unheard of in the U.S. The next step, she said, is to create renewable natural gas by synthesizing the hydrogen with carbon dioxide in the air.

“Very ambitious, but certainly something that is doable,” she said. The Los Angeles Department of Water and Power, she added, is working to convert the coal-fired Intermountain Power Plant in Utah to a natural gas-fired generator by 2025, and then to hydrogen power by 2045, using a salt mine to store excess fuel. The comment prompted a grunt of laughter from a member of the audience.

“What? Hey! Science fiction, but the future is coming!” Galiteva said.

While Kenderdine and Powell’s discussion was cordial, some of their comments provoked Galiteva’s ire as she listened in the audience.

“I think we are mercifully moving away from the juvenile discussions of 100% renewables,” Powell said. “In an incredibly rich place like California that appears to have a truly unusual appetite for spending more and more money on their power sector … it’s potentially possible there.”

“I think that the deniers on the one hand of the climate debate and the magical thinkers on the other hand of the climate debate, who say it’s all going to be wind and solar in 10 years …are actually delaying action when action is urgently needed,” Kenderdine said.

Galiteva told them that while she agreed with the general premise that California needs a diverse set of technologies besides wind and solar, such as geothermal and hydro, “we don’t need nuclear. Nuclear is being shut down. Our biggest failure was investing several hundred million into upgrading San Onofre only for it to leak.” All the nuclear plants in development in the U.S. have been overbudget and there are risks involved, she noted.

While China and India lead the world in gross carbon emissions, Galiteva noted that the U.S. is the largest emitter per capita. “We don’t need to be jumping on [Pakistan]; we need to be helping them stay clean.” She said she grew up in Tanzania, where “the easiest solution was microgrids, solar panels, local resources [and] biofuels. … Let’s do that, and let’s not go back into the dangerous technologies that caused Chernobyl, Fukushima [and] Three Mile Island. … We don’t need to, it’s expensive and we have good alternatives, so let’s make it happen.”

Other speakers also talked about the need to address “energy poverty” around the world, and not just because of climate change.

gridCONNEXT
Power For All CEO Kristina Skierka | © RTO Insider

Kristina Skierka, who gave the morning keynote address Thursday, is CEO of Power For All, which works to deploy decentralized electrification solutions in the fastest, most cost-effective ways in energy-poor communities, mostly in Africa and Southeast Asia. These solutions largely involve microgrids, with rooftop solar.

“It’s been really exciting to be here for the last 24 hours and hear Africa or India or developing countries mentioned so consistently,” Skierka said. “I certainly wasn’t expecting that.”

She described how people living in villages in Uganda and Nigeria need to walk hours to charge their phones and use hazardous fuels to power their stoves and lamps. “There’s almost a billion people without any access to energy, in this day and age where we run businesses from cell phones. And we have all the technology we need. So, this is actually a complete injustice in my view.”

Powell and Kenderdine were critical of California’s recent SB 100 excluding new natural gas plants that incorporate carbon capture and sequestration from being considered a clean energy resource. Kenderdine said the state can’t possibly meet its goals without CCS.

She brought up a study by EFI that found that Nigeria would become the third most populous country by 2050, and that the world will add 10 cities of 10 million or more people by 2030, with four in Africa. “You’re not going to power [these cities] with rooftop solar,” she told Galiteva. “It will make a huge difference in rural Africa, where four hours of electricity means something very different for people’s lives.” But these growing cities will still need centralized power plants, and they will need CCS to stay clean, she said.

The Fourth Risk

John MacWilliams, senior fellow at Columbia University’s Center on Global Energy Policy, gave a pre-lunch keynote speech Wednesday in which he detailed the top five risks facing the electric grid.

gridCONNEXT
John MacWilliams, Center for Global Energy Policy | © RTO Insider

The theme of the speech stemmed from Michael Lewis’ 2018 book, “The Fifth Risk,” which recounts President Trump’s transition into office in the early months of 2017 and its effect on the work and ongoing projects of several federal departments and their career employees. MacWilliams, DOE’s first chief risk officer, featured heavily in the first section of the book, which is about DOE and its many responsibilities, and he gave the book its title and theme. When he told Lewis about the top five risks the U.S. faces, he said the fifth was “project management.”

MacWilliams told Lewis the fourth risk to the U.S. was an attack, either physical or cyber, on the country’s electric grid (following a nuclear weapons accident, an attack by North Korea and conflict with Iran). Speaking on Wednesday, he said anthropogenic climate change was the fourth risk to the grid itself, coming after cyberattacks, physical attacks and aging infrastructure.

“Unfortunately, the recent scientific reports … [are] suggesting that we’ve actually underestimated the velocity and the magnitude of climate change’s negative impacts,” MacWilliams said. He tallied off the more well known impacts in general — including increased storm intensity, rising sea levels and more frequent wildfires. But he said the risks to the electric industry are more frequent and longer droughts causing reduced hydropower capacity, warmer air reducing solar power efficiency, and increased temperatures reducing air density and, thus, wind production.

“Massive investment needs to be made and needs to be made now,” he said.

MacWilliams’ fifth risk to the grid? Like project management, it was more mundane, but no less dangerous. “It’s the common squirrel. Yes, squirrels.” He said that in 2016, “these furry suicide bombers” were estimated to have caused 3,456 outages in the U.S.

– Michael Brooks

PJM PC/TEAC Briefs: Dec. 12, 2019

VALLEY FORGE, Pa. — PJM’s Planning Committee will consider whether the RTO must develop governing document language to deal with the mitigation of existing and future critical infrastructure on NERC’s CIP-014 list.

Some 54% of stakeholders endorsed the issue charge from the D.C. Office of the People’s Counsel after two deferrals and a late-stage challenge from Exelon that many on the committee considered out of order. (See “Critical Infrastructure Vote Delayed Again,” PJM PC/TEAC Briefs: Nov. 14, 2019.)

At the heart of the debate was Exelon’s preference to exclude mitigation of existing projects from the scope of the issue charge, as described in their alternative motion. Transmission owners, including Exelon, are currently working on a Tariff attachment that would handle those specific facilities. (See PJM TO Tariff Filing Stirs up Transparency Concerns.)

PJM
PJM’s Planning Committee convened Dec. 12 at the Conference and Training Center in Valley Forge, Pa. | © RTO Insider

The issue came to a head at the Markets and Reliability Committee meeting in August when incumbent TOs asked for feedback on their proposal that would establish a process for vetting transmission system enhancements designed solely to reduce the number of critical assets identified under NERC’s critical infrastructure protection standard CIP-014, of which fewer than 20 exist within the PJM footprint. NERC deems these assets “highly critical … that, if rendered inoperable or damaged due to physical attack, could result in significant grid concerns: widespread instability, uncontrolled separation or cascading.”

Other sectors expressed concerns about the opaqueness surrounding the proposal, encouraging the D.C. OPC to bring its problem statement forward the following month. After successfully lobbying for a deferral on the vote for two months in a row, the TOs in November held a webinar to address concerns about their proposal to no avail.

At the PC meeting Thursday, Exelon presented for a vote its slightly modified issue charge that excluded existing CIP-014 projects. Some stakeholders pressed PJM on the appropriateness of voting on an alternative issue charge that’s not been moved properly through the stakeholder process or even attached to its own problem statement. After more than an hour of debate — and a failed motion to overturn the decision of the committee chair — stakeholders chose the D.C. OPC’s issue charge over Exelon’s alternative.

The PC will take on the scope of the issue charge and formulate recommendations within six months.

DER Ride Through Task Force Sunset

Stakeholders agreed to sunset the Distributed Energy Resources Ride Through Task Force now that its work considering a default standard is done.

PJM 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 benefits, 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. The committee also endorsed revisions to Manual 14G: Generator Operational Requirements that include this guidance from the task force.

PJM Defends Transource Tx Project Analysis

PJM said Thursday a recent analysis of multiple projects designed to relieve congestion in central Pennsylvania and northern Maryland — including Transource Energy’s reconfigured Independence Energy Connection project — still exceed the RTO’s 1.25 cost-benefit ratio threshold. (See Transource Files Reconfigured Tx Project.)

LS Power disputed the RTO’s analysis of the newly proposed path for the eastern segment of the project, telling the Transmission Expansion Advisory Committee in November that it only carries a benefit-cost ratio of 1. (See PJM Analysis of Transource Alternative Challenged.) The TO said PJM’s base case used to calculate its 1.6 ratio doesn’t consider the impact of a nearby project that would alleviate congestion on the Hunterstown-Lincoln 115-kV line.

PJM’s additional calculations performed after the November TEAC meeting concluded that the aggregate benefit-cost ratio for the alternative Transource project, the Hunterstown-Lincoln 115-kV line and a third project that upgrades the Gracetone-Bagley 230-kV line falls between 2.25 and 2.33. If state regulators in Maryland and Pennsylvania opt for the original configuration for the Transource project, that ratio jumps to 2.87.

LS Power objected to the aggregate ratio presented to the committee Thursday, arguing that market efficiency projects should be re-evaluated on a standalone basis.

RTEP Upgrades

PJM will recommend that the Board of Managers approve system enhancements totaling $134 million for inclusion in the Regional Transmission Expansion Plan in 2020. Two projects, from American Electric Power and Old Dominion Electric Cooperative, are Form 715 criteria-driven enhancements; two others, in MetEd and NIPSCO, are PJM-selected market efficiency projects; and the last project, from Penelec, is being considered for its baseline load growth deliverability and reliability-driven enhancements.

The projects include:

  • In AEP’s zone, rebuild 3.11 miles of the 69-kV LaPorte Junction-New Buffalo line with 795 aluminum conductor steel reinforced wire: $12.3 million.
  • In ODEC’s zone, create a line terminal at Belle Haven Delivery Point (three-breaker ring bus) and install a new single-circuit 69-kV line rated at 55N/55E from Kellam substation to new Bayview substation (21 miles): $22 million.
  • In Penelec’s zone, rebuild 20 miles of the 115-kV East Towanda-North Meshoppen line and adjust relay settings at the 115-kV East Towanda and North Meshoppen substations: $58.6 million.
  • In NIPSCO’s zone, rebuild the 138-kV Michigan City-Trail Creek-Bosserman line: $24.69 million ($22 million is PJM’s portion).
  • In MetEd’s zone, rebuild the 115-kV Hunterstown-Lincoln line and upgrade substation equipment: $7.21 million.

Projects costing less than $5 million — which often include transformer replacements, line reconductoring, breaker replacements and upgrades to terminal equipment, including relay and wave trap replacements — are not broken out individually in PJM’s white paper.

Dominion, FirstEnergy Supplementals

FirstEnergy would like to replace the 230-kV static VAR compensator at its Atlantic substation in central New Jersey with a 300-MVAR, 230-kV STATCOM for $55.7 million. The enhancement will address the increasing trend of outages and failures on the line.

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FirstEnergy would like to replace the 230-kV Static VAR compensator at its Atlantic substation in central New Jersey. | FirstEnergy

Dominion Energy revised an earlier solution it identified for a customer-requested data center in Loudoun County, Va. The TO said with projected load likely to exceed 100 MW, two transmission sources will be required to comply with its facility interconnection requirements and avoid a violation of mandatory NERC reliability criteria.

Its latest solution would cut and extend the Brambleton-Yardley Ridge line into and out of a new Evergreen Mills switching station, which will be constructed with four 230-kV breakers in a ring bus arrangement. The customer has also requested two additional 230-kV breakers to be installed for additional redundancy and will be responsible for excess facilities charges, Dominion said. The entire project will cost an estimated $21.2 million.

– Christen Smith

PJM MIC Briefs: Dec. 11, 2019

VALLEY FORGE, Pa. — The PJM Market Implementation Committee endorsed two fuel-cost policy (FCP) packages — including one authored mid-meeting — that would consider the market impacts of breaking the rules and adjust penalties accordingly.

The first package, compiled by a group of stakeholders, won 87% support and will advance to the Markets and Reliability Committee as the main motion next month. The plan reduces penalties when a market seller self-identifies violations of its FCP and provides safe harbor for situations of noncompliance that weren’t contemplated by the policy. The plan would also expand the use of temporary FCPs. (See PJM MIC Briefs: Nov. 13, 2019.)

PJM’s Glen Boyle, however, questioned how the plan would apply penalties, noting that existing language could allow for duplicate benefits. The plan would fully penalize units that clear the day-ahead market or run in real time on a cost-based offer and are either paid day-ahead/balancing operating reserves or have cost-based offers above $1,000/MWh. If a market seller self-identifies noncompliance to PJM and the Independent Market Monitor, the penalty is reduced 75%.

“There could be a scenario under this proposal where a cost-based unit running on its cost-based schedule is the marginal unit setting price and still getting a discount on the penalty,” he said. “I think that position is a little tough to justify.”

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PJM’s Ray Fernandez presents Manual 27 revisions to the Market Implementation Committee on Dec. 11. | © RTO Insider

Adrien Ford of Old Dominion Electric Cooperative acknowledged that the scenario could occur but said it wasn’t a big enough risk for stakeholders to consider modifying their plan.

“Knowing whether or not there was an impact is tough, so we are coming up with something to indicate that there might have been an impact,” she said. “I think what you’re pointing out is a thin risk that there could be an impact and it wouldn’t be assigned. It is likely that a marginal unit would be paid DA/balancing operating reserves and caught by the impact test. There’s no perfect test, but we think this is a pretty good one.”

The PJM Industrial Customer Coalition and Calpine offered revisions to the first package that they said would address Boyle’s concerns. When it wasn’t accepted as a friendly amendment, the two stakeholders proposed the alternate language as a second package on which the MIC would vote. The revisions clarify that the full penalty would be imposed if a unit is marginal in the day-ahead or real time on its cost-based offer. A unit committed on its price-based schedule that later fails the three-pivotal-supplier test during its minimum run time or hours of its day-ahead commitment would also not incur the full impact factor unless the other conditions for market impact were met. About 81% of the committee endorsed these small language tweaks too.

The Monitor withdrew its package in support of PJM’s own set of revisions, which only won 29% support from the MIC. The RTO also rescinded an alternative package that offered its own version of an impact factor.

Parameter-limited Schedules

PJM and the Monitor presented their divergent views to the MIC on the implementation of parameter-limited schedules (PLS) and whether governing document revisions are needed.

According to PJM, Tariff and Operating Agreement language errors introduced with the implementation of Capacity Performance means that the RTO’s practice regarding PLS contradicts its own rules and conflicts with other governing documents. The Monitor said, however, that PJM should simply follow the language set out in the Tariff instead of revising the document to fit its current practice.

“What we want to do is make sure the Tariff reflects what’s in that manual,” PJM’s Adam Keech said. “The Tariff conflicts with what’s in the manual, and the manual is the correct implementation.”

According to the Monitor, however, the compliance issue rests solely with PJM’s misinterpretation of the Tariff. The RTO’s current implementation of PLS does not mitigate the exercise of market power, as it was intended to do, the Monitor said.

Both the Monitor and PJM discussed their viewpoints with the MIC at the request of the MRC on Dec. 5. The conversation will continue Dec. 19 when the MRC considers Tariff changes authored by PJM to align PLS with the manuals.

Border Rate Manual Revisions

The MIC endorsed revisions to Manual 27: Open Access Transmission Tariff Accounting that would 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.

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.

– Christen Smith

NEPOOL Markets Committee Briefs: Dec. 10-11, 2019

The New England Power Pool Markets Committee continued its crammed schedule to complete the Energy Security Improvements (ESI) proposal at its expanded two-day meeting last week and entertained the possibility of adding a third day to its monthly meetings through March 2020.

ISO-NE has four 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, and the Participants Committee likely will vote on the new market construct at its April 2 meeting. Stakeholders will learn of any schedule additions by the first week of January.

ISO-NE economist Chris Geissler and Todd Schatzki of Analysis Group presented new central case results.

“To date, we have been successful at implementing all the enhancements we had planned, and the good news is that we plan no further enhancements,” Schatzki said. “There may be some small changes to considering how resources on the margins participate, but no major changes.” [Although NEPOOL rules prohibit quoting speakers at meetings, those quoted in this article approved their remarks afterward to amplify their presentations.]

Planners are depending on new revenue streams, such as day-ahead options and forecast energy requirement (FER) payments to motivate generators to stock up on fuel oil or LNG for the winter or arrange for barge or truck delivery of fuel during pipeline constraints.

NEPOOL

Load costs will increase under ESI versus current market rules under all three winter scenarios evaluated, according to Analysis Group. | Analysis Group

The analysis found that load costs will increase under ESI versus current market rules under all three winter scenarios evaluated because of FER payments and the net cost of day-ahead energy options.

In the “frequent” stressed conditions scenario — based on the winter of 2013/14, with its multiple, short cold snaps — total payments by load would increase 10.7% to $4.58 billion, with $480 million in FER payments and $267 million in day-ahead option payments partially offset by a $144 million reduction in payments for energy and real-time operating reserves.

Under the “extended” stressed conditions case, based on 2017/18, with its one, long cold snap, load costs would increase $183 million (6.3%) to $3.075 billion.

The “infrequent” stressed conditions case, based on 2016/17, showed $1.83 billion in load costs, a $73 million (4.1%) increase.

“There’s just more dollars in the market under ESI to maintain fuel inventory than there are under current market rules,” Schatzki said.

Schatzki said he will brief the committee in January on how the incentives will work to encourage increased fuel procurements.

“If our meteorologists and the weather services we subscribe to tell us we’re in for a really cold February, then we’re probably going to take extra steps,” said Brett Kruse, vice president of market design at Calpine, describing how his company thinks about winter fuel supplies under the current market design. “Conversely, there are some times — it happened here not too long ago — where you get enough freezing on the rivers and the icebreaker breaks down, and then you could have a problem getting oil.”

“The more you stock up, the more acorns you have left over at the end of winter,” Schatzki said.

Market Design

ISO-NE principal analyst Andrew Gillespie presented a memo on how ESI will improve the markets’ ability to reflect scarcity and provide an alternative to out-of-market contracts such as the retention of the Mystic generating plant. He followed that with a summary of the market design and a discussion of what officials call the “misaligned incentives problem.”

Gillespie also continued the discussion on setting the strike price for day-ahead energy call options and whether it can be “shaped” across the day to minimize the number of hours in which it is less than the day-ahead energy price. The alternative would be two prices, one for all peak hours and a second for off-peak hours. He also discussed applying a “bias” to adjust the strike price reduce the number of hours with a close-out charges to be applied during settlements.

The RTO is asking the Analysis Group to quantify the impact of applying a bias would have on the incentives to the marginal unit for options.

“This presentation is not an ISO proposal,” Gillespie said. “The ISO is evaluating these issues, and today we are sharing our current thinking and looking for feedback.”

FirstLight Proposal

Tom Kaslow of FirstLight Power Resources presented his company’s position that the strike price — intended to estimate the marginal price of energy to meet the next day’s forecasted load plus operating reserves — needs to vary by hour, just as marginal energy prices do.

Estimating the strike price too low could be inefficient and result in higher-than-needed day-ahead reserve costs, he said, while setting the price too high could mean little connection between the resources providing energy and those acting as reserves in real time.

Because the region lacks an hourly futures market, Kaslow said, the hourly day-ahead LMPs for two days prior (day T-2) could be used to set strike prices.

Part of the day-ahead energy price would be reflected in the FER payment (FERP); thus, the hourly day-ahead reserve strike price would be the day-ahead LMP plus the FERP rate for day T-2 in that hour.

Energy Options vs. DA Reserves

One of ISO-NE’s lead analysts, Hanhan Hammer, presented on why the RTO is proposing to settle day-ahead reserve awards as options on real-time energy, rather than as a forward sale of real-time reserves. “Unlike the day-ahead energy market designs, the reserve market designs of the nine ISOs/RTOs are not standardized,” Hammer noted.

NEPOOL

Seven of the nine ISOs and RTOs in North America have reserve awards in their day-ahead markets, the exceptions being ISO-NE and Ontario’s IESO. | ISO-NE

The RTO’s proposal will mean stronger incentives to arrange fuel than the alternative, Hammer said, because the day-ahead energy options tie financial consequences to the price of energy in real time, addressing the “misaligned incentives.”

“Seven out of the nine ISOs and RTOs [in North America] have reserve awards in their day-ahead markets,” Hammer said, the exceptions being ISO-NE and Ontario’s Independent Electricity System Operator. Some ISOs and RTOs co-optimize energy and reserves in the day-ahead market, and some procure reserves separately from energy.

Geissler looked at how total consumer costs and producer revenues would change with a day-ahead forward reserves design.

The analysis studied day-ahead and real-time reserve prices from NYISO and MISO to assess potential market impacts. The data showed NYISO has higher reserve prices in the day-ahead than in real time, as its design allows participants to submit priced offers for reserves in the day-ahead market but does not allow priced real-time offers. Average prices for 30-minute reserves in West New York were $4.16/MWh in the day-ahead and 41 cents/MWh in real time in 2018.

NEPOOL

NYISO’s design allows participants to submit priced offers for reserves in the day-ahead market but does not allow priced real-time offers. | NYISO

Applying NYISO’s day-ahead premiums to New England reserve needs pencils out to an annual increase in reserve costs of $61.6 million.

“This is meant to be illustrative rather than in any way definitive,” Geissler said. “I would urge caution about taking any specific number like $62 million and saying this is what it’s going to cost, because that’s a ballpark figure.”

Geissler also presented on how ESI motivates resource owners to make cost-effective fuel arrangements before the day-ahead market is cleared, and does so without a forward market component.

FCA 15 Bid Submittal Processes

The RTO’s assistant general counsel for markets, Chris Hamlen, presented a memo outlining potential changes to the Forward Capacity Auction 15 delist bid submittal process to accommodate the timing of NEPOOL votes on ESI and the possible early sunset of the inventoried energy program.

Internal Market Monitor Jeff McDonald and Mark Karl, vice president of market development and settlements, wrote the memo, which notes that FCA 15 retirement and permanent delist bids are due March 13, 2020, a month before the ESI filing deadline. ISO-NE will request FERC approval to waive the FCA 15 deadline if the ESI market design is revised afterward.

If the waiver is granted, and a “non-clerical” revision is made to the ESI market rules after the delist bid deadline, participants that have submitted retirement or permanent delist bids will be given the option to update their bids or withdraw them.

Either option will need to be exercised within a week following the Participants Committee’s April 2020 vote on the market rules, in order to afford the Monitor time to complete its review within the Tariff-prescribed deadlines. The RTO intends to file this waiver request in early January 2020 and will request an order prior to the March 13 deadline.

NESCOE Intent on EER Revisions

The New England States Committee on Electricity’s director of analysis, Jeff Bentz, refined his presentation and answered stakeholder questions from last month’s MC meeting on NESCOE’s proposal for Tariff revisions regarding energy efficiency resources and related capacity obligations during scarcity conditions.

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).

Bentz said that NESCOE still intends to propose a Tariff change that would implement Shaping Option A from the Demand Resources Working Group’s final report issued in July.

“We really do think that Shaping Option A better aligns with the implementation of ISO New England’s original [Pay-for-Performance] design, which is a no-excuses concept,” Bentz said.

Order 841 Compliance

Day Pitney attorneys Sebastian Lombardi and Rosendo Garza briefed the MC on FERC’s ruling conditionally accepting ISO-NE’s Order 841 compliance filing (ER19-470). The commission required additional changes, saying the RTO’s Tariff revisions hadn’t adequately dealt with the application of transmission charges to electric storage resources. (See Storage Plans Clear FERC with Conditions.)

The RTO’s next compliance filing is due Jan. 21, with requests for rehearing on the FERC order due Dec. 23. NEPOOL plans to request an extension on the filing; absent an extension, the proposed market rule changes would be voted on by the MC at its Jan. 14-15 meeting.

Forward Certificate Transfers in GIS

The MC agreed to a request from NEPOOL Counsel Lynn M. Fountain to instruct the Generation Information System Operating Rules Working Group to consider changes to the GIS operating rules. Fountain said the changes are a “way of making a manual system right now a little less so.”

Among other things, the changes would allow batch uploading for forward certificate transfers and improve data sorting.

Officer Changes

The committee re-elected Vice Chair Bill Fowler, president of Sigma Consultants, to continue in his role in 2020. No other members of the committee expressed an interest to be considered as a candidate.

— Michael Kuser

Texas Reliability Entity Briefs: Dec. 11, 2019

AUSTIN, Texas — Bedecked in his best Lone Star-themed tie over the objections of his wife — “But this is about Texas!” he protested — former FERC and Texas Public Utility Commission Chairman Pat Wood III reunited last week with friends, college classmates (Texas A&M, Class of ’84) and others who helped him deregulate Texas’ electricity market and pave the way for strengthening NERC’s compliance function.

Wood, who delivered a keynote address during Texas Reliability Entity’s annual meeting on Dec. 11, was greeted with “whoops” from fellow Aggies and hugs from everyone else. Hopping from one subject to another, he reminded his audience that the “R” in ERCOT stands for “reliability,” and he recalled a bygone ERCOT slogan: “Reliability through markets.”

“That’s the point. Markets are not just to serve customers with better service, better outcomes and less money. We want a system that does what we’ve taken for granted, that stays on at 60 MHz,” Wood said, pointing at the ceiling lights overheard. “Reliability has a real deep component to it. The reliability of our market has been the story for the last quarter-century of our state.”

Texas Reliability Entity
The Texas RE Board of Directors meets. | © ERO Insider

As chair of FERC from 2001 to 2005, Wood played a leading role in the commission’s response to the California energy crisis, Enron’s bankruptcy and the 2003 Northeastern power blackout. The latter event led to mandatory reliability standards and the Electric Reliability Organization, now NERC and its six regional entities.

“Now we have a much bigger and broader approach to reliability,” he said. “You’re the six cops on the beat who oversee that, for the whole United States.”

As the principal for Wood3 Resources, Wood’s focus is now on competitive generation, independent transmission, energy storage and other new power technologies. As he did in the 1990s in Texas, he still emphasizes the importance of competition.

“We’ve got to eliminate the barriers to entry, similar to the big things we did on wind,” Wood said, referring to the buildout of transmission lines that have fostered ERCOT’s 22 GW of wind capacity. “We’ve got to integrate this clean, carbon-neutral attribute. … I’m a big fan of letting markets solve that problem, but we’ve got to coordinate that with the market we have.”

Texas Reliability Entity
Pat Wood III addresses Texas RE’s annual meeting. | © ERO Insider

Wood is still proud of the energy-only market he helped create. He said sending price signals through scarcity pricing “on hot days is the right place to be long term,” predicting that ERCOT’s “9-ish percent [reserve margin] is probably the new normal.” (See ERCOT Sees 10.6% Reserve Margin for 2020.)

“One big reason is we’re not paying for that extra slug of 20% more power,” Wood said, alluding to RTO reserve margins of 20 to 25%. “That model worked in the 20th century. This model is enabled by the market. It’s demand responsive. Real-time pricing signals are going on all the time. That’s a pretty big tool, something I didn’t have when I was a regulator.”

He lamented that he couldn’t rely on storage as a market tool either.

“We do now. The cost of batteries has come down to where it’s feasible to store power,” Wood said. He said the prices still need to drop, but in the meantime, he has a battery on his Houston house that he gets to “geek out on.”

In the end, it’s all about the people, the affable Wood said.

“The thing that makes this so magical is the people,” he said. “I’m blessed to be part of this ERCOT power family for my career.”

Walker Raises Concerns with NERC Representation

During the Member Representatives Committee meeting, Public Utility Commission Chair DeAnn Walker raised what she said was her “continued concern” that a NERC committee is doing away with its regional delegates and potentially denying ERCOT a vote.

The Compliance and Certification Committee, which advises the NERC Board of Trustees on all facets of the ERO’s compliance monitoring and enforcement program, is revising its charter to eliminate its six regionally allocated seats and replace them with six at-large seats.

“I’m not sure why that’s occurring, though I’m sure there’s a good reason I’m not aware of,” Walker said. “While I understand ERCOT is a very small region, it is ultimately a very important region, to not only Texas, but the United States. I can’t fathom there’s not someone qualified from this region.

“The elephant in the room, it’s clear at least to me, is that the Eastern region drives a lot of decisions, especially with standards,” she said.

Texas Reliability Entity
Texas PUC Chair DeAnn Walker, Texas RE CEO Lane Lanford and NERC Trustee Ken DeFontes discuss NERC representation issues. | © ERO Insider

Oncor’s Martha Henson does represent Texas RE on the CCC. Texas RE CEO Lane Lanford theorized that one of the reasons NERC has moved away from regional representation is because of a lack of qualified candidates from the regions.

“Unfortunately, in some regions, they didn’t send [the most] qualified people,” he said. “One thing the MRC needs to think about is that when we send people [to NERC], we need to send people who add to the conversation.”

NERC Trustee Ken DeFontes, who attended the meeting, said it was not the board’s intention “to diminish ERCOT’s influence.” He noted that the newly formed Reliability and Security Technical Committee is drafting a charter to ensure NERC has good representation in the at-large seats. That committee will number 34 members, including 10 at-large seats.(See Elections Underway for New NERC Panel.)

The MRC’s Brad Cox, with Tenaska Power Services, and Venona, with Occidental Power Services, will represent Texas RE on NERC’s Member Representatives Committee.

“I think it’s important there’s good representation from all the regions, not just Texas,” DeFontes said.

DeFontes: Texas ‘Closer to the Edge’

DeFontes reflected on the industry’s rate of change and NERC’s focus on anticipating the future “so we have further time to prepare for it.” However, he is still getting acclimated to ERCOT’s single-digit reserve margin.

“You do live closer to the edge than what I’m used to, but you do a fantastic job of managing it,” he said. “This is an example of how the grid is changing and how we have to adapt.”

Board Re-elects Chair, Vice Chair

The RE’s Board of Directors approved the re-election of Fred Day as chair and Milton Lee’s nomination as vice chair for 2020, Day’s last year as chairman. The directors also approved Delores Etter’s re-nomination and former BP America senior executive Crystal Ashby’s nomination to three-year board terms. Ashby will replace Vice Chair John Coughlin, a board member since 2012.

The board also approved the MRC’s recommended BAL-001-TRE-2 standard, which sets interconnection steady-state frequency within defined limits.

Texas Reliability Monitor Director Joseph Younger told the directors that the PUC is expected to approve Texas RE for another four-year contract as the ERCOT region’s reliability monitor. The RE was the only entity to submit a bid (49246).

“I would say our chances are favorable,” Younger said.

The Monitor worked with the PUC to assess 11 settlement penalties through the first three quarters of the year, Younger said.

Texas RE also plans to renew its regional delegation agreement, which expires at the end of 2020. It hopes to receive NERC approval by September, and then file with FERC.

— Tom Kleckner

Batteries Will Have Their Day in MISO, Experts Say

By Amanda Durish Cook

INDIANAPOLIS — Energy storage systems will inevitably take hold in MISO as costs decline, but the outlook for technologies outside lithium-ion batteries is less certain, storage experts told stakeholders Wednesday.

The experts were speaking on a panel convened by MISO’s Advisory Committee in lieu of the usual “hot topic” discussion where members sound off on current issues during committee meetings. The AC was unusually quiet during the event, instead electing to hear the panel of outsiders talk battery storage.

“Today we’re focusing on batteries. What are they going to look like in 10 years? What are the limits? When do they become commercially viable at scale?” moderator and MISO Vice President of Strategy and Business Development Wayne Schug said in opening the panel.

MISO batteries
Judy Chang, Brattle Group | © RTO Insider

“Storage becomes very valuable when incremental capacity is scarce and expensive,” Brattle Group Principal Judy Chang said. She said she expected batteries to become cost-competitive when they serve capacity at peak times.

“I would say that utilities are beginning to explore storage with pilot programs,” Chang said of MISO’s situation, predicting that more storage will be constructed “when capacity is needed.”

MISO’s interconnection queue currently contains more than 2.5 GW of battery storage.

Consultant Mathew Roling said the rollout of battery storage in MISO would probably occur on a state-by-state basis, and battery solutions would be packaged with other technology or generation and not simply be standalone batteries.

National Renewable Energy Laboratory analyst Paul Denholm said four-hour batteries are close to becoming cost-competitive with peaking combustion turbines. Batteries’ ability to provide peaking capacity is especially heightened when they are paired with solar generation, he said.

Paul Mitchell, CEO of Indianapolis-based Energy Systems Network, said that while MISO hasn’t experienced much growth in battery storage systems, that will soon change.

“I think it’s finally going to come in full force,” he said, adding that “the biggest barrier remains the cost.”

Mitchell said battery storage costs aren’t quite as low as traditional generation, and current, 20-year storage contracts that promise to deliver energy at $300/kWh on average are essentially bets on the future value of storage systems — and they might be too optimistic.

“That’s putting a lot of trust in the future costs of energy storage systems. … That might be controversial to say,” he added.

MISO stakeholders in attendance participated in live polling during the panel, predicting that solid-state and vanadium redox flow batteries might emerge as the next dominant technologies.

MISO batteries
ESN CEO Paul Mitchell | © RTO Insider

Mitchell said he’s often privy to the innovations taking place at the Battery Innovation Center on Naval Support Activity Crane in southern Indiana. He cautioned that solid-state batteries right now are “teeny tiny” and nowhere near ready for factory manufacture. He said lithium-ion would continue to be the reigning battery option for at least the next five years.

“I think it’s going to take these technologies a long time to scale up … for the mass market of vehicles or in the grid,” he said.

Roling said the industry might be overlooking the benefits of pumped hydro storage in the rush to embrace battery storage.

“It’s water. It’s good for 100 years. It’s so natural it hurts,” he quipped.

Chang also pointed out that the environmental benefits of storage are system-dependent and only beneficial when batteries absorb and discharge energy from lower-emitting resources, displacing higher-emitting resources.

Roling said that unless MISO states become “anti-carbon,” battery storage in the footprint would never become cost-competitive. He said batteries would need “that social aspect” to be commercially viable.

To that, Chang pointed out that customers are increasingly calling for zero-carbon generation sources.

In another live poll, a majority of attendees predicted utility-scale batteries would become cost-competitive in MISO in about five to 10 years.

Stakeholders asked if storage might be able to flatten a potential duck curve before it even occurs.

Chang said the question was probably premature, as she believed wind would continue to dominate over solar generation in the footprint.

“I do think it’s unique here. I don’t think it’s the same as the West,” Chang said. “I don’t think we’re going to see the duck curve as quickly as in Texas or California. I think we have to be careful about taking one region and applying it to another.”

PJM MRC Preview: Dec. 19, 2019

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

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

Consent Agenda (9:10-9:15)

PJM will ask for endorsement of revisions to:

B. PJM Manual 13: Emergency Operations, incorporating event analysis updates.

C. PJM Manual 14D: Generator Operational Requirements, adding guidance associated with distributed energy resource ride through.

E. Manual 27: Open Access Transmission Tariff Accounting, addressing the implementation of the annual calculation of the border rate and the impact on firm point-to-point transmission service charges.

1. FTR Product Range and Auction Process (9:15-9:35)

The MRC will consider the first round of financial transmission rights credit-related policy changes after a two-week deferral. (See “FTR Vote Deferred,” PJM MRC/MC Briefs: Dec. 5, 2019.)

PJM said the recommendations, initially presented at the committee’s October meeting, will improve its credit risk policies after the Financial Risk Mitigation Senior Task Force delegated a more holistic FTR market review and possible design changes to a separate Market Implementation Committee task force. (See “FTR Market Rule Changes,” PJM MRC Briefs: Oct. 31, 2019.)

But some stakeholders expressed concerns earlier this month about the ripple effect the revisions may have on market design. The MRC agreed to delay a vote in hopes of finding compromise and moving the changes ahead.

2. Competitive Transmission Proposal Fee (9:35-9:45)

Stakeholders could endorse a new fee structure for competitive transmission proposals developed by PJM to better reflect the costs of its new comparative framework. (See “PJM Unveils Flat Fee Cost-containment Plan” in PJM PC/TEAC Briefs: Aug. 8, 2019.)

3. Comparative Cost Framework (9:45-10:05)

Along with the new fee structure, the MRC must sign off on corresponding Manual 14F language that memorializes the process, including the Independent Market Monitor’s role in reviewing proposals.

The language has been mired in wordsmithing after transmission owners objected to revisions that they said inappropriately capped certain costs. (See PJM TOs Wary of Cost Containment Rules.) There’s also been an ongoing debate over language codifying a collaborative role between PJM and the IMM in evaluating competitive proposals.

PJM deferred voting on both the fee structure and manual language at the Dec. 5 MRC meeting in order to further fine-tune language regarding these issues. (See “Comparative Cost Framework, Opportunity Cost Calculator in Flux,” PJM MRC/MC Briefs: Dec. 5, 2019.)

4. Real-time Values Problem Statement and Issue Charge (10:05-10:25)

Stakeholders will consider endorsing an issue charge that would address PJM-identified issues with the misuse of real-time values in parameter limited scheduling. (See “Real-time Values, Parameter-limited Schedules,” PJM MRC Briefs: Dec. 5, 2019.)

5. Governing Document Revisions for Parameter-limited Schedules (10:25-10:55)

PJM will seek endorsement of Tariff and Operating Agreement revisions that will correct language surrounding parameter-limited schedules (PLS) accidentally introduced with PJM’s Capacity Performance construct filing.

The RTO said the primary issue is that current language suggests that PJM can commit resources on their price PLS offer or cost-based offer during times that are in conflict with other sections of the Tariff and the OA.

The Monitor, however, says the PJM should modify the way it implements PLS to conform with the governing documents.

6. Modeling Generation Senior Task Force (MGSTF) (10:55-11:10)

The MRC will consider implementing near-term solutions of hourly differentiated segmented ramp rates at the recommendation of the Modeling Generation Senior Task Force.

The MGSTF developed the solutions to improve resource modeling for “complex resources” in PJM’s market clearing engines, including combined cycle units, coal units with multiple mills and pumped hydro.

7. Fuel Security Senior Task Force (FSSTF) (11:10-11:40)

The MRC will be asked to endorse recommendations from the Fuel Security Senior Task Force on next steps for potential governing document changes.

The task force, assembled in March, has been investigating what market responses to conditions could lead to fuel insecurity and assessing whether the current market construct is sufficient to cure the problem. (See PJM Stakeholders Reluctantly OK Fuel Security Initiative.)

– Christen Smith

NYPSC Reins in ESCOs, Expands Community DG

By Michael Kuser

The New York Public Service Commission on Thursday placed new restrictions and requirements on energy service companies (ESCOs) that they must honor and fulfill in order to sell to the state’s residential customers and small business owners (15-M-0127, 12-M-0476, 98-M-1343).

“This order to me is a reset,” PSC Chair John B. Rhodes said. “It clearly delineates what is no longer permitted on the foundational principle of protecting customers, and it acts against companies that have acted badly.”

The PSC said that “little has changed in New York’s retail energy market since 2014, when the commission observed that complaint rates related to ESCOs were high.”

In the past few years, the commission has waged a continual struggle to balance the idea of free markets and free choice with accountability for unscrupulous business practices. (See “PSC Continues Crackdown on ESCOs,” NYPSC Approves Higher Rates for Bitcoin Miners.)

NYPSC ESCO
DPS staff testify on the proposed ESCO regulations before the commission.

The commission and Department of Public Service staff recently concluded hearings before two administrative law judges, the transcripts of which total 4,233 pages.

The PSC’s order said that the non-ESCO parties, including the state’s Utility Intervention Unit, the attorney general, the Public Utility Law Project of NY (PULP), New York City and AARP, “all agree that the current retail access market does not benefit customers. Some argue the commission should shut down the market entirely, while others argue that the commission should implement systematic and substantial reforms to limit ESCO products and/or ESCO prices.”

DPS staff said that ESCO customers paid $1.2 billion more than utility customers would have paid for commodity service during the 36-month period ending Dec. 31, 2016.

“In general, the ESCO parties believe that little or nothing is wrong with the retail access market and argue that commission interference with ESCOs’ current access to customers is unwarranted,” the commission said. It added that last year saw ESCO customer numbers drop 12% compared to the previous year, to 2 million.

The ESCO parties included the National Energy Marketers Association, the Retail Energy Supply Association, Direct Energy, Agway, Constellation, Great Eastern Energy, Impacted ESCO Coalition and Infinite Energy.

The new regulations include enhanced eligibility criteria and increased scrutiny of business practices, more clear ESCO product and pricing information, and prohibitions on marketing gimmicks that lack energy-service-based value, such as sporting event tickets and gift cards.

The PSC also revoked the eligibility of Atlantic Power and Gas to participate in the state’s retail energy market after finding the company guilty of “a pattern of persistent disregard” for the commission’s consumer protections and “either unwilling or unable to observe the required business practices, even after having its eligibility to market to and enroll residential and nonresidential customers revoked in 2017” (16-M-0618).

Yes to Consolidated Billing for CDG

The commission also approved consolidating the utility bills of community distributed generation (CDG) customers, relieving project sponsors of the need to bill separately for the subscription charge and making it easier for consumers to see their energy benefits in one statement (19-M-0463).

The PSC has been developing the value of distributed energy resources (VDER) mechanism and promoting the growth of CDG for several years. (See NYPSC Refines Value Stack, Boosts Community DG.) CDGs allow customers not positioned to take advantage of rooftop solar installations to directly participate in renewable energy programs.

Thursday’s order directs utilities to automatically deduct the subscription charges a customer pays its CDG providers from the net renewable energy credits applied to the customer’s bill and send the money to the CDG project sponsor based on a percentage set by the sponsor.

“As this percentage must be below 95%, CDG members participating in consolidated billing will receive a guaranteed bill reduction, and therefore guaranteed monthly savings, of at least 5%,” the commission said.

NYPSC ESCO
The PSC held its regular monthly session in New York City on Dec. 12.

Several state utilities — Central Hudson Gas & Electric, Consolidated Edison, New York State Electric and Gas, Niagara Mohawk Power, Orange and Rockland Utilities, and Rochester Gas & Electric — submitted comments urging the commission to “consider whether such changes are warranted given the cost and time to implement and determine the proper mechanism for funding the transition to different billing mechanisms.”

The utilities argued that “a reasonable approach would provide for full recovery of all upfront and ongoing costs associated with implementing a new billing approach while also requiring the CDG host to pay for utility billing services.”

The commission also rejected National Grid’s proposal to compete for and acquire CDG customers and reduced the company’s proposed fee for consolidated billing by 90%, allowing the same 1% fee provided to other utilities.

The Alliance for a Green Economy, the Green Education and Legal Fund, and Joule Assets submitted comments in favor of consolidated billing, as did New York City and many smaller municipalities.

MISO Board OKs $4 Billion MTEP 19

By Amanda Durish Cook

INDIANAPOLIS — MISO’s Board of Directors on Thursday unanimously approved a $4 billion transmission portfolio consisting of 480 projects.

The 2019 MISO Transmission Expansion Plan (MTEP) was passed to the board by the Planning Advisory Committee without any suggested edits. (See MTEP 19 Advances to MISO Board Committee.)

“This is the largest MTEP cycle to-date, excluding MISO’s 2011 [multi-value project] portfolio,” Executive Director of System Planning Aubrey Johnson said during a Dec. 10 meeting of the board’s System Planning Committee.

MISO Board MTEP
Top 10 most expensive MTEP projects | MISO

MTEP 19 Highlights

Six of MTEP 19’s top 10 most expensive projects are clustered near the Detroit and St. Louis areas.

Johnson said the Detroit area is experiencing enough load growth to warrant MTEP 19’s most expensive project, which includes several miles of aboveground 230-kV and underground 120-kV circuits and a pair of substations at $139 million.

ITC Transmission said several Detroit-area 120-kV underground cables are projected to overload in the future and the project will allow connection with DTE Electric loads in the city.

Other than the Detroit projects, nearly all the priciest projects are needed for reliability purposes.

MTEP 19 contains MISO and MISO, PJM Poised for 1st Major Interregional Project.)

However, formal approval of the interregional project must wait until at least March, along with MISO’s first-ever storage-as-transmission asset (SATA) project. The RTO has yet to finalize rules to govern either project.

In the case of the MEP, MISO is still working on a cost allocation ruleset that can win Despite Pushback, MISO Pursuing TO-only SATA.)

MISO Board MTEP
MTEP 19 spending by planning region | MISO

MISO on Thursday filed a plan with FERC to permit storage facilities to provide transmission services (ER20-588). The RTO characterized the proposal as a “fundamental first step forward for the use of storage resources to maximize the reliability and efficiency of the electric system.”

The SATA plan would require that the assets be used only for transmission purposes, barring them from simultaneous participation in energy markets, but the 800-page filing contains a promise that MISO and its stakeholder community would soon begin exploring how storage devices could serve both transmission and market functions.

“Accepting these proposed revisions will allow for the immediate adoption of storage facilities to serve a transmission function in MISO. And in early 2020, MISO and its stakeholders intend to begin the process of addressing the issues related to using storage as both transmission assets and to provide market services,” the RTO told the commission.

Disagreement on Michigan Interconnection Project

Like last year, a stakeholder is once again disputing a small Michigan interconnection project for resembling distribution.

DTE Energy has said the $8.6 million, 120-kV city of Croswell interconnection project in eastern Michigan is more distribution than transmission in nature and should not be included in this year’s transmission buildout package. The company’s Nick Griffin said the line is “clearly radial” in nature.

Johnson said MISO analysis indicated the project should be classified as a transmission line.

“Our recommendation is to leave the project in inclusion in Appendix A,” Johnson told board members in November.

Johnson said the situation is similar to MTEP 18’s Morenci project, which Consumers Energy disputed. (See Michigan Regulators Intercede in MTEP Complaint.) The Michigan Public Service Commission has since reviewed the characteristics of the $21 million, 138-kV line near the Michigan-Ohio border and last month classified it as distribution, dropping it from MTEP eligibility.

“However, that determination is open to rehearing,” Johnson said.

Griffin said it would be “prudent” for MISO to delay approval of the Croswell line until FERC weighs in on the Morenci project. The project was nevertheless included in MTEP 19 approval.

Helena-to-Hampton Corners Heartburn

Johnson said MISO still stands firm that the Helena-to-Hampton Corners project cannot pass necessary robustness testing to be included as a MEP in this year’s package.

Renewable generation proponents had urged MISO to include the $36.1 million, 345-kV project, originally identified in this year’s Market Congestion Planning Study. The project was set to solve congestion in southern Minnesota at a 4.22:1 benefit-to-cost ratio, but MISO said the project quickly lost value once forecasted wind generation was removed from the equation.

No-go for MISO Board Election Changes

By Amanda Durish Cook

INDIANAPOLIS — MISO’s Advisory Committee has decided not to pursue changes to how the RTO vets and selects its Board of Directors after more than a year of discussion and the creation of a special task team to explore the issue.

The AC said Wednesday it would not recommend changes to expand the stakeholder voice on MISO’s Nominating Committee, declining all possible options laid out by the Board Qualification Task Team (BQTT). (See Task Team: Boost Member Role in MISO Board Selection.)

MISO board changes
Advisory Committee Chair Audrey Penner | © RTO Insider

“The result was to maintain the status quo,” AC Chair Audrey Penner told members at a committee meeting Wednesday.

Penner said that while some stakeholders might have wanted to see change, she hoped members saw the value of what she called a high-functioning board.

Board Chair Phyllis Currie said she expected the AC would continue to periodically examine the board’s makeup.

“In this kind of organization, that conversation will come up time and time again,” she told Penner at the board’s meeting Thursday.

The BQTT in September released a list of options that included requiring state and federal regulators to observe a yearlong “cooling-off” period before becoming eligible for nomination to the board, possibly reserving one of the nine director seats for those with experience representing utility customer interests, and doubling the number of stakeholder representatives from two to four on the Nominating Committee that selects board candidates.

Another option would have rotated the sectors from which stakeholder participants are drawn for the Nominating Committee or reserved a designated seat for a member of the Organization of MISO States. A final option would have set aside one of the nine director seats for someone with recent experience representing electric utility customer interests.

Had the AC recommended any changes, they would have gone before the board’s Corporate Governance and Strategic Planning committees as suggestions only.

The BQTT was created in response to last year’s election of Minnesota Public Utilities Commission Chair Nancy Lange to the board while she was still serving on the commission. Some stakeholders questioned the independence of sitting regulators appointed to the RTO’s oversight body. (See MISO Members Uneasy over Board Nomination.)

OMS has also sent a short letter to the board conveying its “strong interest to be a regular and active participant in the Nominating Committee,” according to organization President Matt Schuerger. One of the Nominating Committee’s two stakeholder seats is typically reserved for an OMS representative. Schuerger said he expected regulator participation to continue shaping the board’s makeup.