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April 12, 2025

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MISO Stakeholders: New Blueprint Needed for Tx Planning

By Amanda Durish Cook

CARMEL, Ind. — MISO stakeholders debating whether the RTO should embark on another regional transmission package said impact to customers and solid business cases should factor prominently.

MISO is asking whether it needs another long-term regional transmission plan like 2011’s multi-value project (MVP) portfolio as it experiences a changing fleet and an increasing need to access new resources. The topic was the focus of the Dec. 5 Advisory Committee’s quarterly hot topic discussion.

Aubrey Johnson | © RTO Insider

Aubrey Johnson, MISO executive director of system planning and competitive transmission, said the approximately 37 GW of wind projects under study in the queue cannot be supported by the RTO’s current system, even considering under-construction projects in the MVP portfolio. The majority of MISO’s 17-project portfolio will be online by the end of 2019.

MISO’s transmission queue contains 483 projects totaling about 80 GW. Executive Director of Resource Planning Patrick Brown said MISO may be reaching an economic “break point” where the costs of network upgrades render projects uneconomic, especially in the wind-heavy western portion of its footprint. “The general cost of network upgrades is going to drive them out,” Brown said.

Historically, 17% of proposed generators that enter MISO’s interconnection enter the generator interconnection agreement phase.

MISO queue as of late 2018 | MISO

‘Stand by Me’

Per tradition, moderator Julia Johnson began the hot topic conversation with a song selection, this time Ben E. King’s “Stand by Me.”

“Blackout!” Johnson jokingly interjected while the lyrics “when the night has come, and the land is dark, and the moon is the only light we’ll see” played in the room. More seriously, she said the takeaway from the song was for industry players to remain unafraid and working together on regional planning.

Alliant Energy’s Mitchell Myhre said he didn’t think MISO would need an entirely new transmission planning playbook but that it should analyze transmission project alternatives and engage in conversations about them. He said more analysis on transmission project alternatives may have lessened the late-stage disagreements over at least two projects in this year’s Transmission Expansion Plan. (See related story, MISO Board OKs Full MTEP 18 Over Stakeholder Complaints.)

“We ask that those conversations [about alternatives] happen at the front end of the process so they don’t come up in the back end of the process,” Myhre said.

Dec. 5 MISO Advisory Committee meeting | © RTO Insider

Multiple stakeholders said another possible crop of MVPs, if any, will need a new business case process, especially considering the fleet change that has occurred in the intervening years and the transmission cost allocation plan MISO will file at the end of the year.

“What if customers have had enough of transmission expansion? What if they’re tired of having transmission lines going across their farms, yards. … They have more options to bypass us completely. You can talk about MISO’s value until you’re blue in the face. What customers see is rising bills,” Madison Gas and Electric’s Megan Wisersky said.

She said customers might be better served by a reinforced distribution system than more transmission projects.

“We have to remember that these transmission lines do impose on communities,” said Coalition of Midwest Transmission Customers attorney Jim Dauphinais, who agreed that overbuilding transmission will result in more expensive bills.

Dauphinais said strong business cases are a must for new regional transmission.

“We think there needs to be a study; we think there needs to be a process” to see if a long-term regional transmission plan makes sense, Missouri Public Service Commissioner Daniel Hall agreed.

However, Kevin Murray, representing the Coalition of Midwest Transmission Customers, said a strong business case can’t be built on a speculative information about where resources might be constructed.

“We need to avoid the ‘build it and they will come’ sentiment. And we’ve seen hints of that in the past,” Murray said. He said some transmission projects might be more appropriately funded by interconnection customers for planned generation.

Clean Grid Alliance’s Beth Soholt said her company will continue to support the Cardinal Hickory Creek line project in Wisconsin, which she said had a “solid as ever” business case. She urged the MISO community no to get too hung up on the infeasibility of the entirety of the projects in the queue.

“We’re always going to have a queue. We’re always going to have projects entering because of economics,” Soholt said.

NRG Energy’s Tia Elliott, a representative of the Independent Power Producers sector, said grid buildout makes sense for a growing base of customers that prefer different resource options.

Soholt suggested that MTEP 15-year future scenarios should account for sustainability goals beyond renewable portfolio standards. Other stakeholders said MISO’s “limited fleet change” future scenario, which doesn’t anticipate widespread renewable use, is outdated and too improbable to be used in transmission planning. Although MISO staff said this year’s four future scenarios were developed for reuse over multiple planning cycles, some stakeholders said all of them should be revised. (See MISO to Recycle Tx Planning Scenarios for 2019.)

Others said accessing diverse resources may require the RTO’s own transmission pathway to connect MISO Midwest and MISO South. Dauphinais said the RTO should make “deeper dives” into chronic transmission constraints that don’t always show up in its annual market congestion planning study.

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RC Transition Fraught with Pitfalls, WECC Hears

By Hudson Sangree

SALT LAKE CITY — The reliability coordinator transition in the West in 2019 led the discussion at the year’s final quarterly meeting of the Western Electricity Coordinating Council’s board of directors on Tuesday and Wednesday.

Western Electricity Coordinating Council
Representatives of electricity entities from across the West and Canada met in Salt Lake City for WECC’s quarterly board meeting on Tuesday and Wednesday. | WECC/Chad Coleman

“This will absolutely be at the top of the priority list for 2019,” WECC CEO Melanie Frye told those gathered at the group’s headquarters, echoing the sentiment she expressed at the board’s previous quarterly meeting. (See Western RC Transition ‘Hot Topic’ at WECC Meeting.)

Peak Reliability’s decision to quit its RC role across WECC’s footprint and hand off duties to CAISO, SPP and BC Hydro by the end of 2019 comes with potential pitfalls, including staff attrition at Peak and the lack of any real backup plan should major problems arise, speakers said.

Peak stunned the Western electricity sector in July when it unexpectedly announced it would wind down operations just months after kicking off a push to create a regional organized market in partnership with PJM. (See Peak Reliability to Wind Down Operations.)

“What happens if things really go bad?” WECC Chair Kristine Hafner asked. “Is there an emergency response team?”

Western Electricity Coordinating Council
Jim Shetler, with the Balancing Area of Northern California, briefed the WECC board on the RC transition in the West. | WECC/Chad Coleman

It fell to Jim Shetler, general manager of the Balancing Authority of Northern California and chair of Peak’s Member Advisory Committee, to brief WECC board members on the RC transition’s shortcomings and the procedures that have been put in place to help head off problems. Though Shetler has no official position with WECC, he’s become a de facto point person for the RC transition.

Peak has been losing staff members who, with their employer’s end in sight, decided to find new jobs, Shetler told the board. Some in Washington and Colorado took positions with electricity entities in those regions, he said.

To stem attrition, Peak detailed the severance packages that each employee will receive if they stay with the company until they’re no longer needed, he said.

With that, Shetler said, “the unplanned departures, I expect, will come down quite a bit.”

Peak and other companies are also exploring the idea of a mutual assistance program, under which employees who leave the organization early and take jobs elsewhere could be loaned back if they’re needed, he said.

Another potential problem is that there are four major transition dates planned through 2019, and something could go wrong each time, Shetler said.

“That is four opportunities for ‘aw shit,’” he said.

CAISO will assume the RC role for its existing territory on July 1, 2019. BC Hydro will become the RC for a large swath of southwestern Canada on Sept. 2. CAISO will then take over RC services for many areas outside of California on Nov. 1, while SPP will take responsibility for other parts of the West on Dec. 3.

Shetler said the latter dates are worrisome because they provide no room for error. Peak essentially will be out of the RC business on Dec. 4 and won’t step back in if things go wrong, he said.

He and others are hoping that some of the transition dates will be moved up. “We just think from a risk standpoint that makes sense,” he said.

Shetler said that in addition to the multiple transition dates, “what keeps me up nights [is worry over] whether Peak is a going concern in the next 12 months.” With the company in the unusual position of planning its own demise, there’s no certainty it will remain a viable business throughout 2019, he said.

Western Electricity Coordinating Council
The entrance to WECC headquarters in downtown Salt Lake City. | © RTO Insider

In comments after the meeting, Linda Jacobson-Quinn, regulatory compliance manager for the Farmington Electric Utility System in New Mexico, said the municipal utility and others were concerned about the transition because of how it could affect their systems if reliability coordination lapses.

Farmington owns fewer than 200 miles of 115-kV transmission lines in the Four Corners area and operates two small gas-fired power plants, she said. The utility is too small to seriously disrupt the grid, “but a lot of times the larger grid can have a significant impact on us,” she said.

Frye said 2019 will be year of challenges for reliability in the West.

“This is a risky year, and I think everyone’s posture is really focused on this,” she told the board and audience. “At the end of the day, it’s the customers that must have an RC.”

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EPA Eases Rules for New Coal Generation

By Rich Heidorn Jr.

EPA on Thursday proposed eliminating the requirement that new coal-fired generation incorporate carbon capture technology — a largely symbolic measure given competition from lower-cost natural gas and renewables that has cut coal’s market share.

| NOAA

The proposal would redefine the best system of emission reduction (BSER) for new, modified and reconstructed coal plants to “the most efficient demonstrated steam cycle in combination with best operating practices,” eliminating the Obama administration’s 2015 BSER requiring partial carbon capture and storage (CCS).

Acting EPA Administrator Andrew Wheeler announces proposed coal emission rule changes at agency headquarters Thursday. | U.S. Environmental Protection Agency

Acting EPA Administrator Andrew Wheeler, a former coal industry lobbyist, said the change replaces “onerous regulations with high, yet achievable, standards” in furtherance of President Trump’s executive order promoting energy independence.

The revised BSER would limit large, newly constructed steam units to 1,900 pounds of CO2 per megawatt-hour and new small units to 2,000 pounds/MWh. Newly constructed coal refuse-fired units would be limited to 2,200 pounds/MWh regardless of size (Docket # EPA-HQ-OAR-2013-0495).

EPA’s announcement said revising the New Source Performance Standards (NSPS) will “provide room for American energy production to continue to grow and diversify,” and Senate Majority Leader Mitch McConnell (R-Ky.) tweeted that the change will “bring relief to hardworking Kentucky families.”

But those predictions were undermined by a footnote in EPA’s Federal Register notice: “Power sector modeling does not predict the construction of any new coal-fired EGUs [electric generating units]. Therefore, based on modeled impacts, any [greenhouse gas] requirements for new coal-fired EGUs would have no significant costs or benefits.”

The Republicans’ spin on the announcement mirrored the Obama administration’s lack of candor when it proposed limiting emissions from new coal-fired units to 1,100 pounds/MWh, far below the levels of the most efficient coal plants without CCS, which range from 1,700 to 1,900 pounds/MWh.

Although critics said neither of the two CCS demonstration projects cited by EPA — Plant Ratcliffe in Kemper County, Miss., and the SaskPower plant in Canada — had demonstrated the commercially viability of the technology, then-EPA Administrator Gina McCarthy insisted that the rule was “clearly not” an effective ban on new coal plants. (See EPA GHG Rule May Turn on Viability of Carbon Capture.)

The Kemper County plant suspended the coal-gasification project in June 2017. SaskPower in July announced it would not expand its CCS project and instead would shut down two aging coal-fired plants.

U.S. coal consumption in 2018 is expected to be the lowest in 39 years. | EIA

Reaction

Pro-coal groups applauded the proposed rule change.

“Since the U.S will continue to rely on coal, it makes sense to invest in new high-efficiency, low-emissions coal-fired power plants to replace at least some of the plants that are retiring,” said Michelle Bloodworth, CEO of the American Coalition for Clean Coal Electricity. “EPA’s NSPS proposal can help achieve that goal by removing an unnecessary regulatory barrier.”

Environmentalists were outraged by EPA’s reversal, noting that the news came on the heels of increasingly dire climate change warnings in reports from the U.N. and the federal government. On Wednesday, scientists reported that after leveling off between 2014 and 2016, global CO2 emissions rose 1.6% in 2017 and 2.7% in 2018 to the highest levels on record.

“The Trump administration’s proposal to ease carbon capture requirements for new coal plants is an affront on the science of climate change and the very real economic harms associated with ignoring its reality,” said Lila Holzman, energy program manager of As You Sow.

But Mary Anne Hitt, director of the Sierra Club’s Beyond Coal campaign, insisted EPA’s announcement would not change the nation’s move from coal, noting the growth of renewable energy and Xcel Energy’s announcement this week that it is committing to 100% carbon-free generation by 2050. The Sierra Club campaign says 281 coal plants have retired or planned to do since 2010 while 249 generators remain on its target list.

Just two days ago, the Energy Information Administration reported that U.S. coal consumption in 2018 would be the lowest since 1979, reflecting a 4% drop from 2017. Retirements for the year are expected to near 14 GW, the second-highest on record. Another 4 GW of capacity are planning to retire by the end of 2019.

Coal plant retirements are expected to near 14 GW in 2018, the second-highest on record. Another 4 GW of capacity are planning to retire by the end of 2019, according to EIA. | EIA

“Only one, relatively small, new coal-fired generator with a capacity of 17 MW is expected to come online by the end of 2019,” EIA said. It predicted power sector coal consumption will fall another 4% in 2018 and 8% in 2019.

Coal remains the top electric generation fuel for 18 states, EIA says.

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PJM SHs Seek End to Frequency Response Debate

By Rory D. Sweeney

VALLEY FORGE, Pa. — PJM will have to determine whether it wants to move forward without stakeholder endorsement on its plan to enforce primary frequency response (PFR) requirements beyond the standards of FERC Order 842 after members roundly rejected three proposals to revise the requirement.

RTO staff announced the results of a recent poll on the proposals at the Dec. 5 meeting of the Primary Frequency Response Senior Task Force (PFRSTF). None received more than 0.34 support; 0.5 was required to be advanced for consideration at the Markets and Reliability Committee. A question on whether PJM should make any change showed 0.73 in support of maintaining the status quo.

PJM stakeholders roundly rejected proposals to revise the RTO’s primary frequency response requirements beyond FERC Order 842 in a recent poll. | PJM

New units that enter the interconnection queue after Oct. 1 and existing units that request an uprate — including facilities that add units — will have to provide PFR, but there would be no new requirements for existing units that don’t make any changes. Generators have opposed proposals to require existing units to provide PFR. (See Primary Frequency Proposals Set for Vote in PJM.)

Stakeholders’ comments at the meeting reiterated the view that the proposals were, as FirstEnergy’s Jim Benchek put it, “a solution looking for a problem.”

“The thing about this is … it’s really an Eastern Interconnection thing … because each balancing authority has the obligation. Things are working,” Benchek said. “I would suggest that PJM … continue to monitor the situation, and if primary frequency response continues to degrade and needs to be addressed, then we restart this task force.”

American Electric Power’s Brock Ondayko agreed that the RTO should give Order 842 time to see if it corrects a trend PJM has noticed of reduced fleetwide PFR performance.

“In the meantime, I think PJM should probably explore the impacts of their own dispatch on the capabilities of units to provide [PFR],” he said. “The capability is so dependent on how PJM loads the assets, whether or not they have them moving prior to the [PFR event].”

Old Dominion Electric Cooperative’s Adrien Ford echoed the remarks, saying the poll results are “clear guidance” that the status quo is preferable.

“At this point, I think our work here is done,” she said.

Wider Concern

“Based on the latest webinar NERC held, I think there is indication that frequency response is declining in general. Is there someone jumping up and down saying, ‘The sky is falling’? I don’t think so. However, I think all the trends show we’re heading in that direction,” PJM’s Vince Stefanowicz said, noting that further delay risks NERC promulgating additional standards.

PJM’s Danielle Croop said that the overall trend is reflected within the PJM footprint.

“We have seen trending down in our frequency response … year over year for the past few years,” she said. “I definitely don’t think it’s PJM in a bubble that’s concerned about frequency response.”

Benchek assured that FirstEnergy’s units will continue to provide PFR and saw the potential for NERC to revise its standards as beneficial rather than a risk.

“We’re not going to take the governor controls off our units or anything,” he said. “We want to comply. We want to have a reliable system. It’s just not clear what we should do, so it’s maybe prudent to wait for better guidance.”

Other stakeholders asked PJM to continue to provide reports on unit performance and overall fleet response.

PJM’s Glen Boyle agreed to doing so.

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SPP Board of Directors/Members Committee Briefs: Dec. 4, 2018

By Tom Kleckner

Board Approves Reduced Admin Fee for 2019

DFW AIRPORT, Texas — SPP’s Board of Directors on Tuesday approved a more than 8% reduction in the RTO’s administrative fee for 2019, although the fee is projected to rise again in 2020.

December’s Board of Directors/Members Committee meeting | © RTO Insider

The RTO’s Finance Committee based its recommendation for a 39.4 cents/MWh fee on a net revenue requirement (NRR) of $157.5 million next year, a $21.3 million reduction from prior estimates for 2019 and just $3.2 million more than 2018’s forecast. SPP is projecting a 4.4% increase next year in the billing determinants used to calculate the administrative fee and is also benefiting from a recent $10.7 million over-recovery.

The administrative fee, which is collected under Schedule 1A of SPP’s Tariff on transmission contracts between transmission providers and customers, was 42.9 cents/MWh for 2018.

“There’s no promise that the fee can stay [low],” said Director Bruce Scherr, the committee’s chair.

SPP Board Chair Larry Altenbaumer discusses the 2019 schedule as CEO Nick Brown listens. | © RTO Insider

Scherr said future affordability will be addressed as SPP moves into its next budgeting cycle. Board Chair Larry Altenbaumer said several times he would like to see an affordability task force created during the RTO’s January meeting.

There was little discussion as the Finance Committee presented its recommendations for both the fee and SPP’s 2019 budget. The budget, also approved without opposition, includes $196.3 million in expenses, a 5.2% increase over 2018’s forecast but 2.9% below 2019’s prior estimates.

SPP allocates the NRR to transmission customers based on their purchase of point-to-point (PtP) transmission service and/or network integrated transmission service (NITS). NITS customers are billed based on the prior year’s average monthly peak demand and represent approximately 90% of total annual billing determinants. PtP service is billed based on reserved hourly transmission capacity and represents about 8% of annual billing determinants.

Monthly true-up assessments cover any unreported load not covered by NITS or PtP service.

The NRR is expected to climb into the $180 million range by 2021, when a major computer system upgrade is planned. That would require an administrative fee of 45.2 cents/MWh.

Board Approves Group Chairs, Reliability Project

New Director Susan Certoma attends her first full board meeting. | © RTO Insider

The board’s consent agenda reaffirmed chairs for nine stakeholder groups; approved an $8.9 million short-term reliability project; accepted the Oversight Committee’s recommended 2019 Industry Expert Pool (IEP) that will evaluate any competitive upgrade projects; and passed scope changes for various working groups, primarily removing references to the dissolved SPP Regional Entity and ensuring equal representation among transmission owners and transmission users.

SPP said the following chairs were nominated with the unanimous support of their respective groups and will begin their two-year terms on Jan. 1:

The reliability project includes a 5.6-mile, 161-kV line in the Kansas City, Mo., area that will address thermal overloads following several Kansas City Power & Light generation retirements.

The 2019 IEP pool will include 13 holdovers from last year and adds two new members: SPP retiree John Mills and consultant Tip Goodwin. Mills is the first former SPP employee to serve on the panel. The panel did not consider any competitive projects in 2018.

The consent agenda also included a board policy statement that will allow Markets and Operations Policy Committee-endorsed actions destined for FERC filings and not appealed by members to go through the regulatory process without further board approval.

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PJM Stakeholders Seek More Flexible Fuel Cost Rules

By Rory D. Sweeney

VALLEY FORGE, Pa. — After a year under new fuel-cost policy (FCP) rules, PJM stakeholders want to make some tweaks.

Discussions on the revisions commenced Tuesday at a special session of the Market Implementation Committee. The special sessions are the result of a problem statement and issue charge approved by the MIC in September. (See “Review of Fuel Cost Policy Rules,” PJM Market Implementation Committee Briefs: Sept. 12, 2018.)

Attendees at last week’s special session of the Market Implementation Committee discuss potential changes to fuel-cost policy rules. | © RTO Insider

PJM staff and stakeholders alike agreed the process could use some revisions to reduce its administrative burden. The rules went into effect in May 2017 after months of debate. In June 2017, the Independent Market Monitor announced that it had rejected fewer than 5% of FCPs during its annual review, but that those rejections accounted for roughly 11% of the units requiring FCPs. (See PJM Monitor Rejects Fuel-Cost Policies for 11% of Units.)

John Rohrbach of ACES highlighted a specific concern that “innocuous” operator errors representing less than half a penny can create tens of thousands of dollars in penalties.

“It seems reasonable to ask whether that is a reasonable system to have” such potential for penalties, he said.

The Monitor’s Joel Romero Luna clarified that PJM’s online information-submission portal rounds to the penny and that no penalty would be assessed if the error does not make it to the portal.

Rohrbach, however, pointed out that the Tariff and Operating Agreement give staff no leeway in assessing penalties for such FCP violations.

PJM attorney Chenchao Lu agreed that the current OA language doesn’t provide the RTO any discretion in assigning penalties for violations, though it does have some discretion in determining whether the FCP was violated in the first place.

Calpine’s David “Scarp” Scarpignato said the lenience should be expanded to include additional types of errors, including those “not intentional.”

“It’s very difficult to be able to determine intent just by looking at the data,” PJM’s Glen Boyle said. “If I move a decimal place on a number, is it intentional? How do I prove that?”

Additional Changes

PJM staff provided education on how the current FCP procedures work for developing cost-based offers. Stakeholders then listed a dozen areas of interest for revising the rules, including removing the administrative burdens for both the RTO and unit owners and adjusting potential penalties to be proportional to violations.

PJM’s Bhavana Keshavamurthy, secretary of the MIC, said she would add the topic to the agenda for the MIC’s Dec. 12 meeting for further discussion.

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PJM Board Demands Action on Energy Price Formation

By Rory D. Sweeney

WILMINGTON, Del. — PJM’s Board of Managers has signaled that it is done waiting for stakeholders to make progress on a nearly yearlong initiative to improve energy price formation.

In a letter dated Dec. 5, the board gave stakeholders until Jan. 31 to reach any consensus they can on six energy price formation issues. After that, the board threatened, it will direct PJM to seek FERC approval for the changes without member endorsement under Section 206 of the Federal Power Act.

The six areas for changes include:

  • Consolidation of Tier 1 and Tier 2 synchronized reserve products;
  • Improved utilization of existing capability for locational reserve needs;
  • Alignment of market-based reserve products in day-ahead and real-time energy markets;
  • Operating reserve demand curves (ORDCs) for all reserve products;
  • Increased penalty factors to ORDCs to ensure utilization of all supply prior to a reserve shortage; and
  • A transitional mechanism for the Reliability Pricing Model energy and ancillary services revenue offset to reflect expected changes in revenues in the determination of the net cost of new entry.
PJM Board of Managers Chair Ake Almgren

“The board has reviewed evidence that demonstrates that when the system is experiencing stressed conditions, energy and reserve prices do not accurately reflect PJM operator reliability actions and, as a result, out-of-market payments increase substantially during those periods,” the letter, signed by Board Chair Ake Almgren said. “Further, PJM’s current reserve market rules do not accurately align the procurement of reserves with their reliability value or incentivize consistent response when deployed. The lack of alignment in the reserve markets mutes price transparency, shifts costs unfairly to consumers who have prudently hedged and limits competition to secure reserves at the least cost to consumers.”

The board said stakeholder discussions have shown “widespread agreement that improvements to reserve markets are necessary” and that PJM has proposed to stakeholders elements from other regions that have “successfully implemented … more robust designs [that] more effectively value reserves and price operator actions.”

The Energy Price Formation Senior Task Force last month delayed a vote on competing proposals from PJM and its Independent Market Monitor for revising the RTO’s ORDC. Stakeholders had expressed reservations about both plans. (See PJM, Monitor Remain at Odds over Energy Market Proposals.)

MRC Response

PJM CEO Andy Ott opened Thursday’s meeting of the Markets and Reliability Committee by saying the changes are “critical to the ongoing evolution of our market” and that, “frankly, we think [the market rules] fall short today.” He noted price spikes during extreme weather, first highlighted by the polar vortex in 2016, and thought some of the proposals, such as locational reserves, were “low-hanging fruit” that stakeholders would endorse “in the time period that’s necessary.”

“We really believe a comprehensive solution to this is necessary. I wish that stakeholders would have come to consensus,” he said.

The forced deadline irritated some stakeholders and found support from others.

“We think that stakeholders have been working assiduously on this, and we’re disappointed that PJM and the board think differently,” said Carl Johnson, who represents the PJM Public Power Coalition. He noted that newly proposed ORDCs were introduced last week and said setting up an Enhanced Liaison Committee, used once before to implement the Capacity Performance construct, is the tool available to the board for expediting the stakeholder process, not making threats.

Susan Bruce, who represents the PJM Industrial Customer Coalition, said stakeholders have not addressed some of the topics the board has asked for agreement on, such as alignment between day-ahead and real-time markets and aligning penalty factors.

“Those are issues that we haven’t really tackled and we don’t really have any information about,” she said, asking PJM staff to provide information for stakeholders to analyze because “the calendar is creeping” up to the deadline.

“That will happen. Where’s [PJM Senior Vice President of Operations and Markets Stu] Bresler? Make that happen,” Ott said, assuring stakeholders that the board wants member input “so when we do present a package to FERC, it is as vetted as possible.”

NRG Energy’s Neal Fitch said many of the topics are “evergreen,” and “we could as stakeholders talk about this for a very long time.” He said the Enhanced Liaison Committee might not be the right plan.

“Perhaps calling the question in the very near future is the right thing to do,” he said. “We’ve been working on this for a very long time. … I think it’s time for us to move on.”

“From my perspective, the stakeholder group is actually moving in a negative direction,” Calpine’s David “Scarp” Scarpignato said. He questioned whether stakeholders should have Section 205 rights in the FPA over market rules in PJM’s Operating Agreement because of how the stakeholder process gets bogged down. He said he doesn’t agree with everything in PJM’s proposal, like the transition plan, “but eventually you have to make a decision.”

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PJM Board Expands Avenues for Feedback on Market Monitor

By Rory D. Sweeney

Joe Bowring, PJM’s Independent Market Monitor | © RTO Insider

WILMINGTON, Del. — PJM members will have two new avenues for feedback on the RTO’s Independent Market Monitor starting in January, the Board of Managers announced in a Dec. 5 letter.

The board will circulate an annual questionnaire, starting in January, for members to voice opinions on the Monitor. The letter didn’t suggest what questions are likely to be included.

Additionally, the board has asked the RTO to retain Michael Bardee to serve as a year-round external liaison “to receive direct member feedback” that will be reported to the board’s Competitive Markets Committee. Bardee has served as FERC’s general counsel and the director of the commission’s Office of Electric Reliability. Members can contact him at Bardee.pjm@gmail.com or 1-833-705-8428.

“The board is confident that this two-tiered approach will provide a broad and unbiased perspective, a committed level of accountability, and a means to a more complete understanding of strengths and potential areas of improvement,” the board said.

The decision “to broaden and formalize the way [the board] collects and assesses information about market monitoring in PJM and to provide an opportunity for all stakeholders to give feedback” came as a recent suggestion through the RTO’s Liaison Committee, according to the letter.

“We welcome transparent feedback,” Monitor Joe Bowring said in an email response. “We are always interested in market participants’ opinions. We look forward to continuing dialogue with market participants about all aspects of markets and the market monitoring function. As part of that, we are having a regular meeting of the [Market Monitoring Unit Advisory Committee] this Friday and all PJM members and others are welcome to participate.”

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ISO-NE Fuel Security Measures Approved

By Michael Kuser

Distrigas LNG Plant in Everett, Mass., at sunset | Distrigas

FERC on Monday approved ISO-NE’s interim proposal to use an out-of-market mechanism to address concerns about fuel security (ER18-2364).

ISO-NE filed the Tariff revisions after FERC on July 2 denied a Tariff waiver to allow the RTO to enter a cost-of-service agreement to keep Exelon’s 2,274-MW Mystic plant running after its capacity obligations expire in May 2022. The commission instead directed the RTO to revise its rules to allow such agreements in order to address fuel security.

FERC tentatively accepted the Mystic cost-of-service agreement on July 13 while ordering an expedited hearing on unresolved issues. (See FERC Advances Mystic Cost-of-Service Agreement.)

Commissioners Cheryl LaFleur and Richard Glick approved the Dec. 3 order, with Chairman Neil Chatterjee dissenting in part. Commissioner Kevin McIntyre did not participate in the decision.

“We find here that the proposed study process, including the model assumptions and proposed trigger criteria as modified by ISO-NE from the OFSA [Operational Fuel-Security Analysis] and Mystic retirements studies, is just and reasonable,” the commission said. “Nevertheless, we encourage ISO-NE to work with all interested parties, including [the New England Power Pool], to continue to address their areas of disagreement while developing the long-term market solution.”

The commission also directed the RTO to submit “an annual informational filing regarding the applicability of its study triggers, study assumptions and study scenarios compared to actual experiences, starting with the winter of 2022/23, for the duration of this interim mechanism.”

Cost Allocation

In accepting ISO-NE’s proposal to allocate to load the out-of-market costs for retaining fuel-secure resources, the commission agreed “that the goal of the proposed revisions is similar to that of [ISO-NE’s] Winter Reliability Program and therefore should have a similar cost allocation method.”

The commission agreed with the RTO that it is inappropriate to allocate fuel security costs to transmission customers because fuel security concerns are distinct from traditional transmission-related reliability needs.

“Specifically, the reliability need that triggers the proposed revisions is a depletion of 10-minute reserves to a particular level or load shedding, as opposed to the violation of local transmission reliability criteria,” the commission said. “Additionally, unlike reliability-must-run resources, the need for a fuel-secure resource is unlikely to be met by local or pool transmission upgrades.”

Under the revisions, ISO-NE will now enter fuel security resources into the Forward Capacity Market as price-takers, ensuring that their resource adequacy contributions are counted.

With respect to capacity market offers, “there is no meaningful distinction between resources retained for reliability and resources retained for fuel security,” the commission wrote.

In his partial dissent, Chatterjee argued that the RTO’s price-taker provision undermines the fundamental premise for implementing a process to support fuel security, and that lower capacity auction prices will encourage marginal units to retire.

“If these same units also are fuel-secure resources, then this price suppression could lead to a further decline in fuel security,” Chatterjee said. “The result could be a vicious cycle of additional out-of-market interventions for these retiring resources, further price suppression and even more retirements, which, in turn, will only further diminish the region’s fuel security.”

Input Assumptions

Gaz Metro delivers LNG from its Montreal plant to customers in Vermont. | Gaz Métro

The Tariff revisions include a formal fuel security reliability review process for resources submitting retirement delist bids for Forward Capacity Auctions 13, 14 and 15, which correspond to capacity commitment periods 2022/23, 2023/24 and 2024/25, respectively.

The RTO will now apply a uniform set of 18 modeling scenarios to establish whether a resource submitting a retirement de-list bid is needed to maintain regional fuel security.

To measure the operational impact of a specific generator retirement, the RTO will model its system under each scenario, absent the generator that has submitted a delist bid, and model generators in descending order of their bids.

Under the RTO’s proposal, a generator will be retained for fuel security purposes if one of two triggers occur after full utilization of Operating Procedure No. 4 (OP-4), actions taken during a capacity deficiency when available resources are insufficient to meet anticipated electricity demand plus required operating reserves:

Reduction of 10-minute reserves below 700 MW in any hour in the absence of a contingency in more than one LNG-gas supply scenario case; or

The use of load shedding in any hour under OP-7, when the RTO requests that generators and demand response resources not subject to a capacity supply obligation voluntarily provide energy for reliability purposes.

The RTO will use the same model developed for OFSA to assess the need to retain a resource for fuel security. To evaluate the operational impacts of generator retirement delist bids, predefined scenarios will test system performance under a range of scenarios and sensitivities, absent a retiring generator.

Static input assumptions will model a number of system parameters, including winter peak load, winter load profile and local distribution company natural gas demand.

In addition, the RTO will use three variable inputs in the model: LNG injections, electricity imports and the dual-fuel oil tank fill rate, which represents the number of oil refills at dual-fuel generating units per 90-day winter season.

The commission noted that many commenters argued for modifications to the two proposed triggering criteria.

“Some commenters argue that the triggering criteria are too conservative, meaning the criteria are easily violated and will result in unnecessary out-of-market interventions,” the commission said. “Still others argue that the triggering criteria are not conservative enough, meaning that the criteria are not easily violated and will result in an elevated risk to reliability in cold weather months.”

The 700-MW trigger is intended to account for improvements in system performance between the forecast year and the operating year, which are not fully accounted for in the modeling, the RTO said in its filing.

The allowance for reduction of 10-minute reserves in the analysis does not indicate allowance of any violation of NERC operations criteria, the RTO said, adding that it will continue to maintain needed generation reserves to meet mandatory reliability criteria during operation.

Connecticut regulators supported the revised modeling methodology because “it incorporates more recent data that would be updated annually and accounts for resources under state contracts, [and] balances conservative and optimistic approaches to avoid both over-procurement and reliability problems.”

Market Failure

In a concurring opinion, Glick advised that “ISO-NE’s apparent need to retain units for fuel security is the result of a market failure” and that the RTO’s “ultimate approach to fuel security will need to be more sophisticated than the interim approach we approve today.”

Glick added that the favorable ruling for ISO-NE “does not necessarily indicate that even the exact same proposal would be just and reasonable in other regions of the country,” Glick said.

Units needed for fuel security would be economic if compensated for the services they provide, which should be procured through the competitive markets, he said.

“Individual, ad hoc contracts with particular resources whose retirement might, under the most conservative assumptions, create a fuel security concern is no way to address a region’s long-term fuel security,” Glick said.

The Tariff changes became effective Oct. 30.

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Mixed Ruling for Trader over PJM Repricing Events

By Rory D. Sweeney

FERC on Monday agreed with a financial trader that PJM failed to provide “all available supporting documentation” for two real-time repricing events that cost the company more than $500,000, but the commission rejected the company’s effort to obtain refunds from the RTO.

The commission said it denied Monterey MA’s request for PJM to the return to the original incorrect pricing to avoid an “absurd” result (EL18-150).

Monterey complained that it lost money on day-ahead financial positions it took after PJM revised nodal prices following events from April 1 to April 30 and June 22 to July 10 in 2016. While Monterey’s complaint was specific to those events, the company argued that PJM “frequently” revises real-time prices after the fact and “while the occurrence of these adjustments decreased in 2017, following an all-time high in 2016, the frequency of adjustments is again trending upwards, with 2018 numbers already matching or surpassing 2017 numbers.”

A financial trader in PJM’s virtual markets claims a recalculation of a real-time price at a dead bus cost it nearly half a million dollars. | Pexels

Bagley Event

In the April event, three of the four transmission lines to the BC Bagley 230-kV substation near Baltimore were out of service, according to the complaint. PJM said the fourth line was also out, creating a “dead bus replacement” situation in which the RTO calculates the nodal LMP using active nodes nearby. That recalculation switched the marginal congestion cost at the bus from negative to positive, costing Monterey $480,000.

However, Monterey argues that MISO’s state estimator shows the fourth line was still in service and that PJM’s outage reports didn’t include the line during that time. PJM failed to provide sufficient information when announcing the price reposting to explain why its data didn’t match up with data elsewhere, Monterey said.

LaSalle-Plano Event

In the second event, the LaSalle-Plano 345-kV line in Illinois was out because of forced outages on two 765-kV lines. Monterey took financial positions based on five-minute pricing signals over the previous few days, but the real-time LMPs were subsequently recalculated, costing the company $31,000.

PJM told Monterey the prices were changed because the model didn’t match how RTO staff actually operated the system.

Monterey said it sought arbitration with PJM over the event, but the RTO denied the request.

XO Energy, another financial trader, told FERC that it also lost money during the LaSalle-Plano event and supported Monterey’s request for Tariff and Manual 11 changes. XO agreed that PJM needs to be timelier in its customer response.

“Reasonable guidelines and Tariff obligations must be incorporated into these provisions to increase transparency and reduce abuse,” XO said.

FERC agreed that PJM failed to provide the amount of information required by its Tariff in connection with the Bagley event, but it also agreed with the RTO’s response that it complied with its Tariff in recalculating the LMPs. The commission therefore denied Monterey’s requests for changes, as well as its complaint about the LaSalle-Plano event.