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December 19, 2018February 13, 2025

IPPTF Hands off Carbon Pricing Proposal to NYISO

By Michael Kuser

RENSSELAER, N.Y. — The Integrating Public Policy Task Force (IPPTF) met for the last time on Monday before handing its final carbon pricing proposal to NYISO’s stakeholder governance process. The ISO will pick up work on the market design in January through its Market Issues Working Group.

The ISO and the New York Public Service Commission created the task force last October to explore ways to price carbon into the wholesale electricity markets to align them with state decarbonization policies, including the zero-emission credit program for struggling nuclear plants.

NYISO published the IPPTF Carbon Pricing Proposal on Dec. 7 after recommending it no longer include a mechanism that would make emissions-free resources with existing renewable energy credit contracts pay the carbon component of locational-based marginal prices (LBMPc). (See IPPTF Updates Carbon Charge Analysis, Treatment of RECs.)

Social Cost of Carbon

The key metric to be used in calculating a wholesale charge on emissions is the gross social cost of carbon (SCC), which the PSC would set “pursuant to the appropriate regulatory process,” according to the proposal. The state Department of Public Service based its calculations on that of the federal government’s Interagency Working Group on Social Cost of Greenhouse Gases.

The Brattle Group projects that carbon charges will lead to incremental internal emissions reductions of 6% by 2030. Most reductions would come from price-responsive load, renewable shifts and possible nuclear retentions. | The Brattle Group

Couch White attorney Michael Mager, who represents Multiple Intervenors, a coalition of large industrial, commercial and institutional energy customers, asked whether there had been any discussions with state regulators about the timing of the PSC’s process

“I assume that the commission is not going to have any regulatory process on setting the social cost of carbon unless and until there’s a vote at the ISO, but doing it that way creates difficulties for stakeholders because then we’re being forced to vote on a carbon pricing proposal without having any guarantees on how the social cost of carbon will be set, how it will be updated [and] when it will be updated,” Mager said.

“The policy of the state of New York is very obvious, and I clearly stated where we got the social cost of carbon used in this analysis,” said Warren Myers, DPS director of market and regulatory economics. “There are no guarantees in life, but you sure have a heck of a lot of information.” (See NY Looks at Social Cost of Carbon, Modeling.)

“The ISO and DPS staff have had a few conversations on this subject” and continue to have conversations on how to structure the rules to accommodate the PSC’s ruling, said Michael DeSocio, NYISO senior manager for market design.

“At the end of the day, if there’s a public policy that establishes a value for carbon, that would be the value that we need to incorporate into the wholesale market,” DeSocio said. “How that value has been established is public policy. I don’t know that we’d create bookends for what the maximum or minimum should be.”

External Transactions

Under the proposal, suppliers would be expected to embed the carbon charge into their energy offers and would continue to receive the full LBMP and be debited their carbon charges during settlement. NYISO would calculate and publish the LBMPc to provide market transparency, adjust payments for import and export transactions, and allocate carbon residual revenues.

“As we discussed along the way, the ISO put forth a proposal that would allow imports and exports to continue to compete on a status quo basis with internal suppliers,” DeSocio said. “As we get experience with it, if we see there are ways to make it more efficient, let’s do that.”

Several stakeholders questioned how NYISO planned to deal with the possibility that FERC might not accept in full the impact of a state-mandated carbon charge on wholesale electricity rates.

“We’re looking at the potential in the very near future to have gigawatts of offshore wind coming into New England and PJM, so this concern may be on us much sooner than you think,” said Seth Kaplan of EDP Renewables. “I refer you specifically to the work done by the Massachusetts Department of Environmental Protection for implementation of the Global Warming and Solutions Act, where they got into this exact issue in terms of customers in Massachusetts that were buying clean energy and wanting to make sure that it was credited in the emissions mix.”

DeSocio said the ISO will release a forecast LBMPc an hour before real-time dispatch. “What we’re not going to do is guarantee that that forecasted price is what we’re going to charge you, and instead will charge you the actual price,” he said.

The New York Department of Public Service derived the gross SCC from the federal government’s Interagency Working Group on Social Cost of Greenhouse Gases. The expected RGGI price is based on the August 2017 base case forecast for RGGI prices (in dark blue). The light blue values are interpolated. | NY DPS

Update on Analysis Requests

DeSocio gave an update on NYISO’s actions on several stakeholder requests for additional analysis, saying it would not study using buyer-side mitigation as a replacement for carbon pricing.

“Seemingly small adjustments to assumptions have wild differences in what the analysis shows,” he said. “That tells us whatever number we put out, we know [it] will be wrong, and most likely will be wrong in a big way.”

“The reason we wanted to see this study performed is that part of the reason we’re here is because FERC is concerned with the impact state policies are having on the markets, specifically price formation,” said Matt Schwall of the Independent Power Producer of New York. “One of the tools FERC has in its box is mitigation. I don’t know what the likelihood is that FERC could subject state-supported resources to mitigation; I do know that’s an option, and that carbon pricing is one way to protect against that.”

Bob Wyman of Dandelion Energy referred to recent rulings by the PSC that will double New York’s existing 2025 storage goal to 3,000 MW by 2030 and require the state’s utilities to reduce building energy use by an additional 31 trillion British thermal units (TBtu) to meet an energy efficiency target of 185 TBtu by 2025. (See NYPSC Expands Storage, Energy Efficiency Programs.)

“It’s important to note that in that order [Case 18-M-0084], they called for 5 [trillion] Btus in savings from heat pumps,” Wyman said. “Increasing the price of electricity relative to gas and oil is going to discourage people from accomplishing that goal, as with any of the beneficial electrification stuff, if we have a single-sector carbon price. And that really should be taken into consideration.”

“Climate change is occurring, it’s clearly related to carbon dioxide emissions and it’s not tip-toeing in on little cat’s feet anymore; that time is past. It’s coming like a freight train,” Myers said. “As an economist, I am convinced that the most economical way to address this problem starts with — it may not be sufficient — but starts with a universal, economy-wide price on carbon.”

Myers said, however, that, “unfortunately, we do not currently have a federal government willing to work on such a universal, economy-wide carbon price. And the proposal we have here put forth by the NYISO is not that. Context matters, and the context here is that we are evaluating a single-state, single wholesale market carbon price.”

DeSocio said he expects stakeholders will be meeting on the carbon pricing proposal several times a month in the first half of the year and that the ISO will soon release a schedule for those meetings.

December 19, 2018

FERC OKs PJM Plan to Prevent Shortchanging of DR Value

By Rory D. Sweeney

PJM Market Implementation Committee Briefs: Sept. 13, 2017.)

East Kentucky Power Cooperative headquarters | *EKPC*

PJM calculates an end-use customer’s DR capability by taking the lesser of its total peak load contribution, which measures summer capability, or its WPL.

The WPL, which is usually lower, is calculated by averaging the customer’s peak hourly loads during traditional daytime hours on the five days with the highest daily unrestricted peak loads from December through February, known as the five coincident peaks (5CPs).

However, one or more of the 5CPs can have little or no load because of load-management actions, offline factories or meter malfunctions. Such reductions reduce the WPL, which will likely reduce the calculation for the resource’s potential load reduction.

To avoid this, PJM will allow customers to exclude up to two CP days when the peak hourly loads for each of those days are individually below 35% of the average peak hourly load for all the location’s winter 5CP day. The 35% threshold represents 1% of all submitted peak load days.

The commission’s Dec. 17 order said the new rules “should more accurately reflect end-use customers’ actual loads during peak winter periods.” It rejected the Independent Market Monitor’s argument that the proposal would arbitrarily increase the calculated WPL.

“Similarly, we are unpersuaded by the Market Monitor’s argument that failure to also eliminate high-load days renders the winter peak load calculation arbitrary. There is no evidence in the record that identifies any particular circumstances or events that may cause abnormally high-load days that are not representative of actual peak loads and, when used to calculate winter peak load, lead to an inaccurate representation of a demand resource’s capability to reduce its winter load.”

December 18, 2018

NERC Releases ‘Stress Test’ Analysis of Gen Retirements

By Michael Brooks

NERC on Tuesday warned that faster-than-expected coal and nuclear plant retirements could jeopardize reliability if grid operators are not prepared.

“If these retirements happen faster than the system can respond with replacement generation, including any necessary transmission facilities or replacement fuel infrastructure, significant reliability problems could occur,” NERC said in a special reliability assessment report. “Therefore, resource planners at the state and provincial level, as well as wholesale electricity market operators, should use their full suite of tools to manage the pace of retirements and ensure replacement infrastructure can be developed and placed in service.”

Calling it a “stress test” of the bulk power system, the organization used data from the U.S. Energy Information Administration to identify generators set to retire through 2025 in 10 areas where coal-fired and nuclear generation make up a significant portion of the resource mix. It then analyzed the impacts of those generators retiring earlier, in 2022.

The analysis found four areas — SPP, SERC-East, WECC-RMRG and WECC-SRSG — in which currently planned generation resources would not be sufficient to make up for the accelerated retirements. NERC determined this by comparing projected planning reserve margins for 2022 under the scenario to projected peak load levels for the year. The organization used data from its 2017 Long-Term Reliability Assessment to determine projected reserve margins under currently confirmed retirements through 2022, to which it factored in the accelerated retirements. It also used the LTRA to determine the projected peak loads.

‘Unlikely’ Scenario

Both the report and John Moura, NERC director of reliability assessment and system analysis, repeatedly emphasized that the analysis was not a prediction.

“I think it’s really important that stakeholders understand that this is a stress-case scenario,” Moura said in a conference call with reporters Tuesday morning. “We’re not necessarily making any recommendations or calls for any additional financial support beyond that which market operators think are required. We completely acknowledge that the scenario as tested is unlikely.”

He noted the organization also analyzes the impacts of geomagnetic disturbances and simultaneous, highly coordinated physical and cyberattacks on the grid. “These are things that we don’t believe will happen, but we think it’s instructive, when we break a system, to understand what are the potential mitigations and see how to get it working.”

“NERC’s stress-test scenario is not a prediction of future generation retirements nor does it evaluate how states, provinces or market operators are managing this transition,” the report says. “Instead, the scenario constitutes an extreme stress-test to allow for the analysis and understanding of potential future reliability risks that could arise from an unmanaged or poorly managed transition.”

Moura also noted that the report doesn’t criticize capacity markets or out-of-market subsidies. “We’re simply saying that these tools need to be monitored and tested in planning,” he said.

Fears of Politicization

NERC was criticized by some stakeholders in early November, when it briefed its Members Representatives Committee on the report. They feared it would be politicized, and that the press and public would misunderstand it as a warning of things to come. (See LaFleur, Stakeholders Anxious over NERC Retirement Study.)

“Policymakers and regulators should not interpret this study as justifying interventions to artificially retain unprofitable power plants, as these actions deter the economic transition in the power generation fleet, undermine innovation and raise costs to America’s businesses and families,” Devin Hartman, CEO of the Electricity Consumers Resource Council, said in a statement Tuesday.

“As NERC itself states, the report looks at unlikely scenarios that go far beyond either announced or projected power plant retirements to determine at what point there might be some risk for reliability,” said Jeff Dennis, general counsel for regulatory affairs at Advanced Energy Economy. “The report does not provide evidence of any imminent threat to the reliability of the bulk power system. Nor does it suggest that competitive wholesale energy markets aren’t up to the job of ensuring reliability as the resource mix changes.”

The report “relies on too many extremes to be enlightening about real-world grid reliability,” the Natural Gas Supply Association said.

Tuesday’s report did not include a detailed analysis of natural gas infrastructure; however, NERC said “additional midstream natural gas infrastructure could be required” to respond to early retirements.

In a November 2017 assessment, NERC had recommended industry consider the loss of key natural gas infrastructure in their planning studies under NERC reliability standard TPL-001-4. (See NERC: Natural Gas Dependence Alters Reliability Planning.)

Although NERC sees risks to increasing dependence on renewables and gas-fired generation, Tuesday’s report said that “successfully managed, the changing resource mix can provide … potential benefits to reliability and security of the BPS. Less reliance on large, centralized generation stations and greater use of dispersed networks comprised of smaller diversified generation resources can provide operating and planning flexibility. Additionally, some fuel assurance risks diminish with the changing resource mix. The effects of adverse weather on coal stockpiles or fossil fuel resupply infrastructure may be reduced when natural gas pipelines supply a greater proportion of the generating fleet. Attaining reliability enhancements associated with the changing resource mix is possible when the different challenges to fuel assurance and [essential reliability services] are addressed.”

Recommendations

NERC included several suggestions to stakeholders, regulators and policymakers in the report, among them a recommendation to incorporate fuel assurance analyses in generator retirement assessments. This would mean factoring in fuel supply infrastructure, new infrastructure requirements for replacement resources, and firm vs. non-firm fuel delivery contracts.

It also recommended that regulators and policymakers consider ways to speed up approvals of infrastructure. “When a generator’s planned retirement is delayed to allow for completion of transmission system upgrades, expedited regulatory proceedings can help minimize the delay,” the report says. “Where more natural gas generation is needed, more natural gas pipeline capacity will likely also be needed.”

But Moura also noted that the report doesn’t make any specific recommendations for the four areas identified by the report as being at risk under the scenario. “We have a lot of confidence in how these areas plan their systems,” he said.

December 17, 2018

OMS Names New Executive Director

By Amanda Durish Cook

The Organization of MISO States announced Monday that its board of directors has promoted Marcus Hawkins to head the organization, replacing outgoing Executive Director Tanya Paslawski next year.

Hawkins, formerly an engineer with the Wisconsin Public Service Commission, joined the organization in 2016 as its director of member services and advocacy. (See Former Wisconsin PSC Engineer Marcus Hawkins Joins OMS Staff.)

Paslawski, who has headed OMS since 2015, will leave effective Dec. 31 to become president of the Michigan Gas and Electric Association. (See OMS Executive Director to Exit.)

“OMS commissioners know and have great respect for Marcus Hawkins’ work as director of member services and advocacy. We look forward to working with him in his new role,” said OMS board President Ted Thomas, chairman of the Arkansas Public Service Commission.

Hawkins said he is excited to lead the organization during “rapid change in the electric industry.”

In addition to his role at the Wisconsin PSC, Hawkins has also worked at Wisconsin Energy Conservation Corp. and PA Consulting Group. Hawkins has a master’s in mechanical engineering and a bachelor’s in nuclear engineering, both from the University of Wisconsin-Madison.

December 17, 2018

PJM PC/TEAC Briefs: Dec. 13, 2018

By Rory D. Sweeney

FSA Unit Plan

VALLEY FORGE, Pa. — PJM is reformatting and drafting clarifications to Manual 14B: PJM Region Transmission Planning Process that may impact the RTO’s planning modeling, staff told attendees at last week’s Planning Committee meeting.

PJM Planning Committee | © *RTO Insider*

The proposed revisions would clarify that units with facility service agreements (FSAs) will only be added to the base case if there are not enough existing units and units with interconnection service agreements (ISAs). Units with FSAs that are not included in the base case will be subject to a sensitivity study to determine if long-lead-time upgrades are required to support them. The long-term base case will only be studied if the need for a long-lead-time upgrade is identified during the near-term base case analysis extrapolation over Years 6 through 15.

Additional clarifications include:

Higher-than-normal capacity interconnection rights (CIRs) may be granted to wind units when justified by meteorological data.
Flowgates near PJM’s borders will continue to be examined to understand deliverability concerns that may exist due to loop flows.
Merchant transmission facilities (MTFs) with long-term firm transmission service will be modeled the same as MTFs with firm transmission withdrawal rights.
Operational contingencies are single contingencies examined under the common-mode outage procedure to determine whether system operators would allow the common-mode dispatch to occur.
Constraints identified in the PJM capacity import limit (CIL) analysis are studied in the same manner as other internal PJM constraints.
The distribution of the capacity benefit margin from each of the five external supply zones is determined during the annual PJM CIL study.

PJM’s Jonathan Kern said the clarifications were intended to be pre-emptive measures to avoid confusion in the future.

Inverter-based Model

Staff plan to update Manual 14G: Generation Interconnection Requests to identify which user-defined models (UDMs) it has already approved for wind turbines and other inverter-based resources. Developers planning to build affected generators would need to use the tables to determine whether they would need to submit additional information about modeling their units to receive PJM approval.

PJM’s Tao Yang said the list would likely be updated annually.

PJM’s Ken Seiler, who chairs the PC, said standardizing the stability modeling is important so generation interconnection requests can be processed “much faster.”

ELCC Analysis of Intermittent Resources

PJM’s Tom Falin said the RTO is targeting an endorsement vote at the March meeting of the PC for a package of four changes for how capacity credits are calculated for intermittent resources.

One of the prospective changes, resources’ effective load carrying capability (ELCC), has received “a lot of discussion lately,” Falin noted. PJM scheduled a special session of the PC on Dec. 21 so the RTO can get “a read” on stakeholders’ interests. (See “Renewables’ Capacity Analysis Extended,” PJM PC/TEAC Briefs: Nov. 8, 2018.)

The question to answer, he said, is “do we think moving to an ELCC methodology is the right thing to do?”

PJM’s Jerry Bell will return to the PC in January to reintroduce the proposed changes with whatever consensus on the ELCC is gleaned from the special session.

Cost Containment

PJM’s Mark Sims said staff have gathered all of the pieces necessary to develop the comparative framework for cost containment and return on equity that stakeholders endorsed earlier this year. (See “Update on Integrating Cost-containment Guarantees,” PJM PC/TEAC Briefs: Sept. 13, 2018.)

“The moving parts we’re dealing with … include not only the uniqueness of the proposals that we might receive but … the complexity of the cost-containment proposals we might receive … [so] there’s a couple of big moving parts,” Sims said. “We have all the building blocks we need to pull the process together in 2019. … We can see where all the pinch points are.”

As part of the process, PJM and its Independent Market Monitor met with an independent consultant on Nov. 15 to better understand cost estimating, revenue requirements and other components for developing cost proposals. PJM continues to work with the contractor, and stakeholders questioned how the RTO would handle a situation if the contractor eventually took a contract that created a conflict of interest. PJM’s Sue Glatz said it “would be a given” to re-evaluate the relationship if staff “saw anything” that affected the contractor’s independence, but that “right now we don’t see any conflicts.”

Sims said he plans to return to the committee in January with more detail on the process.

MEPETF

Work in the Market Efficiency Process Enhancement Task Force (MEPETF) has progressed to polling on how to proceed with revising the market-efficiency process, PJM’s Fran Barrett said. At the task force’s Dec. 7 meeting, stakeholders developed a list of nine questions for the poll, including the preferred method for re-evaluating already-approved market efficiency projects and the preferred cycle for PJM to conduct the market-efficiency process.

“That means we’ve got a lot of work in January and February. It’s going to be pretty swift and a lot of hard work,” Barrett said.

Staff are targeting the March PC meeting for a first read of the most popular options so the package proposal can be implemented on Nov. 1.

Offshore Wind Zones

With many coastal states announcing offshore wind solicitations, PJM is now developing concepts for alternative ways to interconnect all of the coming megawatts, Glatz said. She explained that developers have approached staff with challenges and said they’d like to have multiple interconnection points, along with the ability to create offshore transmission networks. Staff are considering how to handle those desires and are seeking input from the PC on a variety of questions, including what studies might be required, what interconnection rights might be offered and whether the rights could be transferrable.

Glatz said staff are targeting the January or February meetings of the PC to introduce proposed concepts and related Tariff revisions. Stakeholders said they had no foundation on which to base their input and called on staff to create a problem statement and issue charge on the topic. But staff voiced concerns about the initiative getting bogged down in debates.

“We have real projects today, so the challenge is how can we be responsive to our customers?” Glatz said, adding that states want to limit impacts to communities while also providing the necessary resources.

The plan is potentially a move toward creating open-access offshore networks as an extension of the onshore grid that has been advocated by stakeholders like Markian Melnyk, president of Atlantic Grid Development. (See Offshore Wind Industry ‘Really Moving;’ Coordination Key.)

However, PJM is currently considering only plans that are “strictly for injecting into PJM,” not connecting to other RTO/ISOs, Glatz said.

2019 Load Forecast

The RTO’s preliminary 2019 load forecast is down compared to last year, PJM’s John Reynolds explained. Both the summer and winter forecasts are down at least 0.4% from last year’s forecasts.

The analysis uses the summer forecasts for 2022 and 2024 and the winter forecasts for 2021/22 and 2023/24 to make year-over-year comparisons. The summer 2024 comparison is down 0.5%, slightly more than the other three. Staff are adding a zone summary page for 2019 that details zonal impacts.

The report remains preliminary for now because there were issues with forecasts in the Dayton Power and Light and East Kentucky Power Cooperative zones that are still being revised. The final version, expected by the end of December, will be used for all Regional Transmission Expansion Plan studies.

Because the Base Residual Auction is delayed this year to attempt to implement revisions to the capacity auction construct, PJM staff will develop a second load forecast just for the BRA that would include peak-shaving adjustments.

Reynolds confirmed that the forecast only includes load that PJM system planning staff are working on and nothing speculative.

Planning Resilience

PJM’s Aaron Berner presented analysis from staff’s recent initiative on developing “cascading trees” on load-loss probabilities that shows one facility has a high probability of losing at least 1,000 MW of load.

“This gives us an idea about potential weaknesses based on initiating events,” Berner said, but he cautioned that more work will be necessary to make sure staff are not “looking at things we shouldn’t be.”

Deactivation and Acceleration

PJM’s Nick Dumitriu discusses planned transmission projects during last week’s meeting of the RTO’s Transmission Expansion Advisory Committee as meeting administrators Ken Seiler and Lisa Krizenoskas look on. | © *RTO Insider*

PJM’s Nick Dumitriu said the 2018 reliability project acceleration analysis found no projects to accelerate to reduce congestion. Project B2766 would ease congestion, but it was already accelerated last year to 2020 and the developer said it can’t be accelerated further.

PJM is performing reliability analyses for deactivation of 30 units, all of which have requested to deactivate no later than June 1, 2020.

Dominion

Dominion Energy’s Ronnie Bailey presented three new need assessments and three planned solutions as part of the transmission owners’ new FERC-ordered process for developing supplemental projects. Dominion has presented 19 needs assessments since the process was implemented in September. Dominion has been presenting such needs and planned solutions for several months. (See “Dominion Supplementals,” PJM PC/TEAC Briefs: Oct. 11, 2018.)

December 17, 2018

PJM Operating Committee Briefs: Dec. 11, 2018

By Rory D. Sweeney

Low Frequency Update

VALLEY FORGE, Pa. — NERC is still analyzing the causes of the July 10 low-frequency event in the Eastern Interconnection, PJM’s Chris Pilong told attendees at last week’s Operating Committee meeting.

PJM Operating Committee | © *RTO Insider*

In working with 12 balancing authorities, NERC doesn’t believe it’s an error in the reported data. It appears to have been a “drift” in the frequency that was “significant” but happens every couple of years and was never near underfrequency relay tripping or system collapse, Pilong assured.

At the September OC meeting, PJM outlined recommendations to address the situation. (See “Recommendations from Frequency Drop,” PJM Operating Committee Briefs: Sept. 11, 2018.)

Quiet Month Operationally

Pilong said November was a very quiet month operationally aside from an emergency procedures drill. There was one reserve-sharing event with the Northeast Power Coordinating Council and 22 post-contingency local load relief warnings.

Both the on-peak and off-peak load-forecasting errors dropped from October, though they were slightly above the metric’s score for November 2017. The overall RTO error was 1.78%.

Staff presented a graph showing that load forecasting is often worse in many zones in the third quarter of the year during warm summer months. Staff used an example from July 20, 2017, when a storm in Commonwealth Edison’s zone reduced actual temperatures and load below day-ahead forecasts.

The balancing authority area control error (ACE) limit performance was 99.9% for the second straight month, above PJM’s 99% target. There were 15 excursions outside limits, which were down from October, and 30 minutes total outside of limits, also down from the prior month.

DER Subcommittee

PJM’s Scott Baker confirmed during his update on the Distributed Energy Resources Subcommittee that it is considering primary frequency response requirements for resources with non-FERC jurisdictional wholesale market participation agreements. But stakeholders “actually feel it’s a bigger issue” to hammer out frequency and voltage ride-through characteristics, Baker said.

In November, Planning Committee members endorsed a problem statement and issue charge to implement a new Institute of Electrical and Electronics Engineers standard on ride-through. (See “DER Ride-through,” PJM PC/TEAC Briefs: Nov. 8, 2018.)

PMUs to Planning

Load interests are keeping a close watch on a proposal from PJM to include installing or retrofitting phasor measurement units (PMU) as part of projects in the Regional Transmission Expansion Plan. The units would be used to back up monitoring of interconnection reliability operating limits (IROLs). PMUs are already used to detect oscillations in the system, along with improving post-event analysis and generator model validation. PJM also plans to use them in the future for system island and event detection, automated model validation and backup ACE monitoring.

PJM’s Shaun Murphy said the current IROL monitoring proposal is estimated to require 14 PMU installations and four modifications. The issue will be moved to the PC — which Murphy also addressed at its meeting last week — to develop a standard for new substations and major construction projects to include PMU installation for bus-voltage and line-flow monitoring.

Dave Mabry, representing the PJM Industrial Customer Coalition, asked who would own the PMUs. He said he wanted to ensure PJM is “spending wisely” rather than going on a “lark” with new technology that staff “want to play with.”

PJM’s Paul McGlynn said the incremental cost of adding the “thousands of dollars” that a PMU costs is “relatively inexpensive in the grand scheme of [the millions of dollars that building] a substation costs.” The intent would be to add them as part of baseline projects in the RTEP related to high-voltage lines.

“We’re not necessarily going after every low-voltage station,” he said.

Mabry said he was looking for validation of the need.

“I’m trying to make sure we’ve got a solid business case to justify the expansion of the PMUs,” he said.

OATF Base Case Parameters

PJM’s Robert Dropkin said the Operating Assessment Task Force (OATF) is building the base case for its study of the upcoming summer to identify thermal overloads and voltage-limit exceedances in N-1 analyses. The studies, which happen annually for the summer and winter peaks, also focuses on switching and off-cost requirements and looks to develop operating procedures for any issues discovered during the study.

The OATF, which consists of the transmission owners within PJM’s footprint, uses the most recent modeling from the Multi-regional Modeling Working Group (MMWG) and adds updates from individual TOs. Generator outages are calculated from the previous year and averaged with the two years previous to that. OATF members also select specific units to be put on outage based on historical or planned outages, or generators are simply reduced across the zone.

The base case will be developed in mid-February with analysis starting later that month. The final report is approved by the System Operations Subcommittee — Transmission in early May.

December 17, 2018

PJM Market Implementation Committee Briefs: Dec. 12, 2018

By Rory D. Sweeney

Attendees discuss issues at last week’s meeting of PJM’s Market Implementation Committee. | © *RTO Insider*

Indemnification Conversation

VALLEY FORGE, Pa. — The PJM Market Implementation Committee will host a discussion on indemnification for financial transmission rights bilateral contracts at its Jan. 9 meeting.

The discussion, which was promised at the Dec. 5 meeting of the Markets and Reliability Committee, is intended to determine how PJM will respond to a deficiency letter FERC issued in response to one of the RTO’s proposed revisions to its FTR credit policies following the historic GreenHat Energy portfolio default.

PJM plans to request that FERC dismiss its filing, making the deficiency notice moot. But Shell Energy told the MRC on Dec. 5 that it wants to see the commission rule on the underlying indemnification issues that Shell pointed out in protesting the filing. (See “Bilateral FTR Retraction,” PJM MRC/MC Briefs: Dec. 6, 2018.)

FTR Collateral

PJM’s Bhavana Keshavamurthy and Diane Antonelli administrate a special session of the MIC last week on revising the RTO’s fuel-cost policy rules. The session was held as part of the regularly scheduled MIC meeting. | © *RTO Insider*

Stakeholders voted overwhelmingly in favor of PJM’s original proposal on revising its FTR credit requirements to include a “mark-to-auction” (MTA) provision. The proposal, known in the stakeholder process as G1, received 0.93 in favor in a contemporaneous vote with several alternatives and 0.93 in favor compared to maintaining the status quo.

The proposal has the potential to delay clearing of auctions and posting of results because of intra-auction collateral calls for undercollateralized portfolios. Delayed results have happened twice in the history of PJM’s FTR markets. Both times were in March 2017, caused by “super overlapping” clearings from multiple FTR auctions ending at the same time. PJM has since implemented rule changes to avoid that situation. (See “FTR Revisions Approved over Financial Dismay,” PJM MRC/MC Briefs: Jan. 25, 2018.)

An alternative proposal that only applied the collateral call for portfolios undercollateralized by at least $100,000 failed to receive stakeholder endorsement, with 0.14 in favor. Another that used the same analysis and requirements but removed bids from undercollateralized portfolios rather than making intra-auction collateral calls also failed with 0.3 in favor.

Suffolk Fund’s James Ramsey campaigned for two other alternatives that would have applied a credit requirement that is the higher of either the existing requirements or the MTA plus an adder. One included the $100,000 threshold while the other did not. He said the endorsed proposal would be “challenging to do” because it requires forecasting many variables and might require very small collateral calls that could exacerbate delays.

FTI Consulting’s Scott Harvey, retained by PJM to analyze the issue and compare the proposals, said all of the alternatives are sound, but that Ramsey’s proposals have “ad hoc parameters” that risk running down a portfolio’s initial credit margin at the wrong time because the margin declines as losses occur in the portfolio. His analysis found that two situations in the history of PJM’s FTR market wouldn’t have been covered by Ramsey’s proposals, but both were from the GreenHat default and would have been undercollateralized by more than $20 million.

“If they have a big loss when the margin’s reduced, you have the opportunity for a big default,” Harvey said.

Ramsey’s proposals failed to receive stakeholder endorsement, with votes of 0.23 and 0.08 in favor.

A third set of alternatives would have combined both to make the credit requirement the higher of the current credit requirement plus the MTA or the MTA and Ramsey’s MTA adders. That set differed on the option for the $100,000 threshold. However, they were removed from consideration before the vote.

PJM said it is targeting January to file the endorsed proposal with the intention of implementing it in April.

Fuel Cost Policy Special Session

Since the MIC’s agenda was short, staff decided to include a special session on considering tweaks to several parts of the fuel-cost policy (FCP) rules and cost-based offer procedures hashed out last year. The sessions started after the MIC approved a problem statement and issue charge in September. (See PJM Stakeholders Seek More Flexible Fuel Cost Rules.)

Joe Bowring, PJM’s Independent Market Monitor, questioned whether the process could be used to completely eliminate FCPs.

John Rohrbach of ACES, who initially proposed the re-evaluation, assured Bowring “our goal is not to vitiate” the FCP process.

“Or eviscerate? … Just checking that you don’t want to do either,” Bowring responded.

The session identified 14 factors to consider changing or adding.

December 17, 2018

Full PJM Study Makes Case for Fuel Security Payments

By Rory D. Sweeney

The full report on fuel security in PJM’s footprint that CEO Andy Ott teased during a D.C. press conference on Nov. 1 shows that the grid is reliable in all but extreme scenarios and will remain so — as long as resources are compensated for being fuel-secure.

On Nov. 1, PJM CEO Andy Ott announced the initial findings of the RTO’s fuel security study at the National Press Club in D.C. | © *RTO Insider*

“This analysis demonstrates that the PJM system is reliable today and will remain reliable in the future,” says the report, which was released Monday. “Key elements such as on-site fuel inventory, oil deliverability, availability of non-firm natural gas service, location of a pipeline disruption and pipeline configuration become increasingly important as the system comes under more stress. … While there is no imminent threat, fuel security is an important component of reliability and resilience — especially if multiple risks come to fruition. The findings underscore the importance of PJM exploring proactive measures to value fuel security attributes, and PJM believes this is best done through competitive wholesale markets.”

Ott went to D.C. last month to begin the drumbeat for compensating generators on their “fuel security,” outlining proposals including valuing it in the capacity market or developing a winter reserve product in the energy market. (See PJM Begins Campaign for ‘Fuel Security’ Payments.)

The study picks up where Ott left off, noting that the proposals have been submitted in the resilience docket FERC opened in January (AD18-7). (See Don’t Rush on Resilience, Commenters Urge.)

It says the results will be used to define and value “fuel security attributes” and describes the “key variables” to maintaining reliability during extreme events as:

Availability of non-firm gas transportation service;
Ability of the fuel oil delivery system to replenish oil supplies during an extended period of extreme cold weather;
Physical breaks at key locations on the pipeline system;
Customer demand;
Generator retirements, replacements and the resulting installed reserve margin (IRM);
Use of operating procedures to conserve fuel during peak-winter conditions; and
Pipeline configuration.

Study Details

The study focuses on natural gas- and oil-fired units that make up 84,823 MW of PJM’s capacity — about half of the total — but maintain less than five days of fuel on-site. It encompasses 324 “different scenarios that could occur during an extended period of cold weather” during the 2023/24 winter, including variables such as customer demand, fuel availability, oil refueling frequency, generator forced outage rates, retirements announced as of Oct. 1, new generation planned to be operational by 2023, level of reserves and natural gas pipeline disruptions.

Duration of pipeline disruptions | *PJM*

The report provides extensive discussion to validate its assumptions, which it says are based on more than 45 years of weather data, previous studies, surveys of PJM generation owners and meetings with regulators, operators and stakeholders throughout the supply chain.

“Even in a scenario such as extreme winter load combined with a pipeline disruption at a critical location on the pipeline system from which a significant number of generators are served, PJM’s system would remain reliable and fuel-secure. While there could be reserve shortages in the extreme winter load scenarios, the grid continues to deliver electricity reliably under these extreme conditions,” the report says.

However, when combined with “escalated” assumptions that generation reserves are reduced to the 15.8% IRM, “the system may be at risk for emergency procedures and operator-directed load shed.” The retirements announced so far would create a 25.8% IRM.

Non-firm Gas

The analysis found that 16,000 MW of gas units in PJM haven’t contracted for firm service that is only interruptible by force majeure, such as a pipeline disruption. The analysis determined that a typical winter day would have 10,000 MW, or 62.5%, of those units available while an extreme winter day of high gas demand would have 0% availability from those units.

The study’s assumptions for pipeline disruptions account for up to five days of 100% reduction and at most 20% reduction for the ensuing nine days. PJM has experienced interstate pipeline outages, or “line hits,” over the past two years as the result of both pipeline corrosion and accidental third-party damage. Outages with easily identifiable sources are “typically” back in service within five days. However, non-point source issues may “require a longer outage and potential derating of the pipeline capacity.”

The scenarios studied only consider individual pipeline disruptions and don’t contemplate multiple simultaneous disruptions.

Results

Without escalated retirements, even an extreme weather event with 0% availability from non-firm units and a single high-impact pipeline disruption with limited refueling availability results in no worse than reserve shortages, according to the study.

However, of the 144 scenarios in which extreme winter load is combined with escalated retirements, 73 scenarios, or 51%, required manual load shed, which would mostly be localized to one of three areas in PJM: East, West or South. The worst scenario would result in 83 hours and 204 GWh of load shed.

December 17, 2018

PJM Moving Quickly to Make Board’s Price Formation Deadline

By Rory D. Sweeney

VALLEY FORGE, Pa. — PJM staff moved briskly through a dense agenda during Friday’s meeting of the Energy Price Formation Senior Task Force (EPFSTF) in hopes of wrapping up the wide-ranging, yearlong initiative by a Jan. 31 deadline set last week by the Board of Managers.

Energy Price Formation Senior Task Force | © *RTO Insider*

The dramatic debates that often attend PJM stakeholder meetings were largely kept in check, although several stakeholders shared their reactions to the deadline at the meeting, the task force’s first since the board published a letter issuing it.

The board said it saw need for six revisions to how the RTO sets prices in its energy market and that if stakeholders haven’t endorsed plans to address the six needs by Jan. 31, it will direct PJM staff to unilaterally file a plan for FERC approval. (See PJM Board Demands Action on Energy Price Formation.)

Susan Bruce, who represents the PJM Industrial Customer Coalition, said the board appeared to feel stakeholders weren’t making progress on the issues, even though the RTO had recently made large-scale revisions to its proposal and stakeholders made it clear a vote was coming soon.

“I was left with the impression [from the letter] that stakeholders couldn’t get their act together to get a vote,” she said. “I’m concerned about the perception of the board about what was happening, which has been good work at the EPFSTF. … I think it doesn’t fully appreciate the work that been done.”

PJM’s Dave Anders assured attendees that the board was apprised of all of the task force’s activity.

Other stakeholders expressed skepticism that the task force can comprehensively address the six revisions demanded, particularly because two of them have yet to receive any discussion.

Carl Johnson, who represents the PJM Public Power Coalition, said aligning market-based reserve products in day-ahead and real-time energy markets was “the one thing I said at the beginning that I wanted to come out of this process … so that’s great.”

But a “piecemeal” approach of endorsing solutions for any of the six that stakeholders can agree on — which the board indicated it would accept — “doesn’t work,” he added. “I do not see how we can pull all of this together. I think the time frame is pretty unrealistic.”

However, staff were confident that the timing is achievable. PJM’s Adam Keech said the other as-yet-unaddressed revision — increasing operating reserve demand curve (ORDC) penalty factors to ensure utilization of all supply prior to a reserve shortage — is a relatively “straightforward” extension of what’s already been discussed.

Catherine Tyler with PJM’s Independent Market Monitor questioned whether there is evidence for what the grid needs to respond to stress events like the polar vortex and bomb cyclone cold snaps.

Keech pointed to reports staff produced on the RTO’s performance during both of those events.

“I don’t agree with the statement that there’s been no analysis on stressed system events,” he said, adding that the board saw all the documentation it needed to see “to come to the conclusion they’ve come to.”

Anders added that he’s “absolutely sure” the board has reviewed those documents.

Gabel Associates’ Mike Borgatti and Erik Heinle with the D.C. Office of the People’s Counsel struck more upbeat tones with their comments. Heinle was optimistic that the differing sides were not too far apart. Borgatti called the deadline “a healthy step in the process” as the sides may never get to agreement.

Any FERC filing would come after the board’s next meeting, scheduled for Feb. 11.

PJM Proposal

Keech and PJM’s Lisa Morelli described staff’s proposal for the six revisions. Though stakeholders indicated concerns, staff continued to move through a presentation in an attempt to fully describe the plan, which was published on Dec. 11, six days after the board’s letter and three days before the task force meeting.

PJM’s Anthony Giacomoni also presented the results of an analysis that stakeholders requested at the task force’s previous meeting. The study simulated energy, reserve and uplift impacts of including the regulation requirement in the ORDC, first using the current two-step curve and then the proposed reserve-market revisions. The study, which covered June 1, 2017, through May 31, 2018, found that, at its most extreme, net costs would be reduced by $350 million, with a $1.92 billion increase in energy and reserve market revenues offset by a $1.5 billion cut in capacity market revenue and a $770 million drop in retail rate costs to load.

December 17, 2018

PJM MRC Preview: Dec. 20, 2018

By Rory D. Sweeney

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

RTO Insider will be in Valley Forge, Pa., covering the discussions and votes. See our December 26 newsletter for a full report. (NOTE: The meeting will be held at PJM’s Conference and Training Center instead of the Chase Center.)

Markets and Reliability Committee

Informational Update (9:10-9:25)

PJM Board of Managers member Susan Riley will provide an update via phone on the progress of the Special Board Committee investigating PJM’s handling of the GreenHat Energy financial transmission rights portfolio default.

1. PJM Manuals (9:25-9:40)

Members will be asked to endorse the following manual changes:

A. Manual 14D: Generator Operational Requirements. Revisions developed to revise information input deadlines for the Resource Tracker application. (See “Resource Tracker,” PJM Operating Committee Briefs: Nov. 6, 2018.)

B. Manual 14E: Upgrade and Transmission Interconnection Requests. Revisions developed as part of a triennial cover-to-cover review. The revisions include changing the manual name to align it with the structure of Manuals 14A and 14G and explaining how to apply to the interconnection queue via Queue Point.

2. FTR Mark-to-auction Credit Requirements (9:40-10:05)

Members will be asked to approve a proposal endorsed by the Market Implementation Committee to increase FTR credit requirements with the addition of a “mark-to-auction” provision. (See “FTR Collateral,” PJM Market Implementation Committee Briefs: Dec. 12, 2018.)

3. Must-offer Exception Process (10:05-10:30)

Members will be asked to endorse a proposal endorsed by the Market Implementation Committee to revise the capacity market must-offer exception process. The changes would allow participants to specify multiple auctions when making exception requests. Resources that cannot be made Capacity Performance-capable by the start of the delivery year will be permitted to seek an exception. (See “Must-offer Exception Changes,” PJM Market Implementation Committee Briefs: Nov. 7, 2018.)

4. FTR Forfeiture Rule (10:30-10:55)

Members will be asked to endorse a proposal endorsed by the MIC to revise the FTR forfeiture rule. It would specify that a binding constraint shall be considered if the difference between the shift factors at the FTR delivery and receipt buses across the constraint exceeds 10% and is in the direction that increases the value of the FTR. (See “FTR Forfeiture Proposal Endorsed,” PJM Market Implementation Committee Briefs: Nov. 7, 2018.)

5. Primary Frequency Response Senior Task Force (10:55-11:15)

Members will be asked to consider putting the task force on hiatus for one year to gather data and subsequently determine whether to reconvene. (See PJM SHs Seek End to Frequency Response Debate.)

6. Distributed Energy Resources (11:15-11:40)

Members will be asked to endorse proposed clarifications of market participation rules for distributed energy resources. Among the changes are a consistent definition of on-site generators.