FERC last week accepted MISO’s revised cost allocation proposal for the RTO’s relatively new category of smaller interregional transmission projects with PJM.
The new cost allocation affects targeted market efficiency projects (TMEPs) between MISO and PJM and became effective Nov. 28 (ER18-2514). MISO made the allocation revisions as part of a larger update to its cost allocation as the five-year Entergy transition period — which limits cost sharing of transmission projects in MISO South — expires at the end of this month.
2018 TMEPs | MISO
The RTO’s share of TMEP costs is currently allocated to transmission pricing zones based on each zone’s share of the relative positive congestion contribution, measured by the TMEP candidate study. (See FERC OKs MISO TMEP Cost Recovery Schedule.)
MISO made three complex changes to its cost-sharing formula while still preserving the premise that TMEP costs flow to benefiting transmission pricing zones.
The RTO had been calculating TMEP benefits by using a calculation of the nodal congestion contribution for each load node. Now it will include generator nodes in determining congestion benefits, rather than considering only load nodes. The two nodes will be aggregated to calculate the net benefits of the upgrade to each transmission pricing zone.
MISO will also discontinue its practice of applying the formula to all five-minute dispatches in the real-time market. The formula will now apply only to hours in the day-ahead market in which a reciprocal coordinated flowgate will experience congestion.
FERC said MISO’s proposal will simplify the TMEP cost allocation process.
“We find that the proposed revisions will better define the beneficiaries of avoided congestion as well as allocate the costs of TMEP upgrades more accurately, while removing undue complexities from the calculation of benefits,” FERC said.
The calculation will not account for the contract path on SPP’s transmission that connects MISO Midwest with South. Regulators in South had called for a stakeholder process to determine the impacts of the contract path on cost allocation.
But MISO said an analysis showed accounting for the contract path “indicated minimal change to the cost allocation.”
MISO and PJM have so far recommended seven TMEPs, five that received approval in 2017 and two up for approval this month from the RTOs’ respective boards of directors. The combined projects will cost under $25 million and are expected to reap about $132 million in benefits. (See MISO, PJM Endorsing 2 TMEPs for Year-end Approval.)
Roughly a year into the discussion and months past the deadline requested by PJM’s Board of Managers, details of potential changes to the RTO’s energy market remain anyone’s guess.
At Wednesday’s meeting of the Energy Price Formation Senior Task Force (EPFSTF), PJM reintroduced a substantially altered proposal for revising its operating reserve demand curve (ORDC), and both the RTO and its Independent Market Monitor revised their proposals for the allowable synchronized reserve offer margin adder. A new proposal submitted by the D.C. Office of the People’s Counsel would largely maintain the current two-step curve but include some revision details from proposals by both PJM and the Monitor. (See Skepticism Lingers Around PJM Price Formation Goals.)
PJM revised its ORDC proposal to account for the impact of units’ regulation requirements, shifting its proposed curve to the left and more in line with the current two-step ORDC for synchronized reserves. The current curve escalates from $0/MWh to $300/MWh at 1,590 MW, and the new one escalates gradually from $0/MWh at roughly 2,750 MW to $265/MWh at 1,575 MW. PJM’s original proposed revisions began escalating from $0/MWh at roughly 3,500 MW and reached $265/MWh at 2,100 MW. The revised proposal means that the value of synchronized reserve megawatts will be less until the reserve drops to the minimum reserve requirement (MRR), which remains $850/MWh.
PJM also revised its proposed margin adder down substantially. The current adder is $7.50/MWh, but PJM said the calculation should instead be based on the expected value of the penalty resources pay if they receive a synchronized reserve obligation and fail to perform during an event. For 2017, that value was 1 cent/MWh, and so far in 2018 it’s been 2 cents/MWh. Rather than setting it at $0, PJM argued that it should be allowed to change as clearing prices change.
The Monitor’s revised ORDC proposal includes a temporal concept meant to factor in the expected cost of a unit commitment to maintain the reserve requirement in the future. Instead of happening over 30 minutes to provide reserves necessary for 10 minutes in the future, as PJM has proposed, the Monitor’s proposal would look forward until the next expected demand peak based on historical load patterns.
The resulting curves have seasonal variations but rarely extend past $60/MWh before hitting the MRR.
The Monitor revised its adder proposal from a “compromise” of $3.80/MWh — which it now finds “unjustified” — to $0/MWh and recommended that penalties should extend back to the last reserve event when the resource performed to its full obligation but no longer than 12 months.
The Monitor also added a new option to the matrix that would include the changes to the synchronized reserve market but reserve the discussion on the ORDC to the second stage of EPFSTF, including discussion of the relationship between the day-ahead reserve products and real-time reserve products.
Stakeholder Reaction
Stakeholders appeared unconvinced by either proposal. Carl Johnson, representing the PJM Public Power Coalition, said the measuring stick for whether the RTO’s proposal is successful should be its impact on uplift payments.
“If uplift doesn’t go away, we’ve got a problem,” he said.
PJM’s Adam Keech agreed, saying, “I think zero uplift is a good target.”
The Monitor disagreed, however. Monitor Joe Bowring noted several market mechanisms that create uplift that aren’t addressed in the proposal.
“We think some uplift is necessary,” Monitor staffer Catherine Tyler said.
PJM and the Monitor also disagreed with some stakeholders over what the overall goal of the changes should be.
“The goal isn’t to have the lowest prices possible,” Keech said. “The goal is to reflect what the system operators are doing. We’re trying to drive to prices that reflect the system operators’ needs.”
Bowring said the “objective of markets is to have the lowest prices possible for the defined product, but no lower.”
Stakeholders and PJM staff questioned whether the Monitor’s ORDC proposal was more about addressing scheduling issues than generation scarcity.
“This is compensating to some extent for the lack of scheduling tools,” Tyler acknowledged. “However, what we do see in the market now is an operator looking ahead and seeing a need for reserves in the future, and we don’t have a market tool to address that.”
Vote Delayed
PJM’s Dave Anders, who is facilitating the task force, summed up the day by quashing any question about whether stakeholders may be ready to decide.
“It’s been a fluid situation with respect to proposals. I don’t know that we’re ready to vote,” he said, noting that PJM staff will update the board at its meeting this week.
Bowring pointed out that if the initial vote had happened when PJM had initially requested the vote, its proposed demand curve would have been substantially higher than with its revised ORDC presented for the first time at this meeting.
While no one questioned the decision, stakeholders differed on whether a vote should come sooner or later. Some expressed concern that further delay risks the board deciding to approve revisions without waiting for stakeholders’ advice.
Stakeholders have already missed the board’s request to receive stakeholder endorsement for some changes by the third quarter, which could have already allowed for FERC approval and implementation for this winter. (See PJM Board Seeks Reserve Pricing Changes for Winter.)
FERC on Thursday approved some of the flexibility PJM has sought to address after the historic GreenHat Energy financial transmission rights portfolio default.
The commission accepted Tariff and Operating Agreement revisions that require defaulted FTR portfolios to go to settlement rather than being liquidated through auction (ER19-19). It was one of four requests PJM filed with FERC to attempt to mitigate the financial risk created by the default, which is expected to cost stakeholders more than $100 million to cover the losing bets. Stakeholders have criticized PJM for what they see as bungled handling of the issue. (See Advocacy Group Seeks CFTC Oversight of PJM FTRs.)
PJM analysis shows the continuing downward trajectory of GreenHat’s FTR portfolio. | PJM
FERC’s approval is conditioned on PJM removing Tariff and OA language related to bilateral FTR transactions that is predicated on the commission accepting a related filing that received a deficiency letter requesting more information (ER19-24). FERC made the ruling effective Dec. 1, rendering moot another related filing that sought to ensure an effective date no later than Feb. 28, 2019 (ER19-25).
On Friday, FERC’s Office of Energy Market Regulation accepted by delegated authority the fourth filing, which clarified that a PJM member’s per capita portion of FTR default allocation assessments will not exceed $10,000 per calendar year, cumulative of all defaults, or more than once per each member’s ongoing default if default allocation assessment charges for a member’s ongoing default span multiple calendar years (ER19-23).
Settlement Order
FERC approved sending defaults to settlement rather than liquidation despite several protests, which argued that the requirement prolongs uncertainty, leaves PJM with no alternate ability to mitigate default losses, could increase the size of the default, inhibits liquidity by preventing the sale of valuable hedges and disrupts the orderly unwinding or reorganization of the defaulting entity.
“We acknowledge that inherent in these revisions, PJM stakeholders are exchanging one set of risks for another,” the commission said. “The commission recognizes that PJM, on behalf of the stakeholders who ultimately bear the cost of default, assessed such tradeoffs, including the risk tolerance of its stakeholders, and this proposal is the result of such an assessment. While we acknowledge that there are potential downsides to not liquidating defaulted portfolios through the FTR auctions, we cannot find that PJM’s choice to allow FTR positions to go to settlement is unjust and unreasonable.”
The commission said that while the GreenHat default may be an exceptional event that may never happen again, that doesn’t determine whether the rule changes stemming from it are unjust or unreasonable, nor does how other regions would handle such a situation.
CARMEL, Ind. — Storage is glaringly absent from MISO’s potential plans to manage a possible 40% renewable penetration on the grid, stakeholders told the RTO this week.
During a Nov. 28 workshop to discuss its ongoing findings on the impact of increased renewable integration, MISO suggested using computer-optimized transmission buildout and more pronounced ramping from remaining conventional generation to respond to a 40% renewable resource mix.
MISO last month said it would need to take significant steps to reinforce its grid to handle a 40% penetration comprising 75% wind and 25% solar. The RTO said it found a possible “inflection point” at 40% and that it would be difficult to operate within system limits at that point. (See Study: MISO Grid Needs Work at 40% Renewables.) Its multiyear study seeks to determine what the grid needs to maintain the planning reserve margin, operate within the physical limits of the system and support voltage and frequency.
MISO’s renewable penetration currently stands at about 10%. Findings issued last month indicate the RTO could reliably absorb a 20% renewable penetration without damaging frequency response. (See MISO: 20% Renewable Limit for Adequate Frequency Response.)
But at 40% renewables, MISO has found that renewable curtailment becomes more pronounced during shoulder months, though wind curtailment would occur in every hour during an average day, except in summer. It would also confront significant stability issues.
Possible transmission siting at 40% renewables | MISO
During the Nov. 28 workshop, MISO policy studies engineer Maire Boese said the RTO will likely need to rely on transmission solutions to keep the majority of the renewable energy deliverable to load at the 40% level.
“We want to make sure energy reaches load instead of seeing it be curtailed or not dispatched,” Boese said.
Transmission planning can also become more influenced by computing power and mathematic modeling, MISO concluded.
Yifan Li, of MISO’s policy studies group, said that even with the modeling process, “engineering judgment and human experience” are still the driving factors behind selecting transmission project candidates, although that is changing.
“We’re getting to a point where we can seek some help from computers … to find transmission solutions,” Li said.
Such an automated process led MISO to identify about 80 potential new transmission candidates, down from a pool of about 11,300, he said. The additional transmission would cut down on curtailments and make renewables more deliverable to load, MISO said last month.
The expansion includes 266 miles of circuit at 200 kV or less, 763 miles of 230-kV circuit, 1,373 miles of 345-kV circuit, 316 miles of 500-kV circuit, 267 miles of 765-kV circuit and 408 miles of HVDC line. The transmission solutions do not include a new line linking MISO Midwest with MISO South.
With new transmission, 38.4% of the 40% renewable penetration would be deliverable, as opposed to 34.7% without the solutions, MISO determined. Curtailment of a 40% renewable mix would fall from 18.2% to 9.6% on average.
A 40% renewable mix would also place more ramping responsibility on thermal units, the RTO found.
Wind curtailment at 40% renewables | MISO
Where’s the Storage?
At the workshop, LS Power’s Pat Hayes asked if MISO has studied what levels of storage would be helpful at different points of renewable penetration.
“So far, we haven’t found a strict need for storage,” Policy Studies Manager Jordan Bakke said. “Storage really hasn’t been found to be needed in the areas we’ve studied so far. … When we looked at the issues and we looked at the solutions, the solutions were pretty straightforward.”
Bakke said MISO so far recommends “extracting more flexibility from the current fleet, rather than building something else.”
MISO said as renewable penetration increases, the number of thermal units online increases during off-peak hours despite a decrease in average output. The RTO would especially rely on online coal and combined cycle gas units for ramping in the morning and evening.
Not an Economic Analysis
Veriquest Group’s Dave Harlan said MISO might consider developing incentives to keep remaining thermal units online if they’re needed for ramp capability.
But Bakke said the study is exclusively focusing on the physical needs of the system rather than monetary outcomes. MISO’s study does not contemplate whether conventional generation could economically survive in a landscape with 40% renewable penetration.
“The purpose is not to talk about the money issues,” he said.
Boese said coal asset owners may have to investigate whether their units can handle the more frequent ramping MISO has forecasted. “Less megawatts of coal are available with more ramping,” she said. “That’s something to keep in mind if you’re a generation owner.”
“There’s something like a feedback loop here,” said consultant Roberto Paliza, adding that MISO was failing to answer a key question by not investigating whether conventional generation could economically withstand being needed for more pronounced ramping but less run-time overall. He said the RTO was neglecting to find out if the assistance would be there when needed to facilitate renewable penetration.
But other stakeholders said MISO’s conventional generation solution to combat increasing curtailment conspicuously leaves storage out of the conversation.
Clean Grid Alliance’s Natalie McIntire said it seemed that MISO was looking only to existing conventional generation to manage renewable variability and that storage could also cover ramping flexibility.
Bakke said MISO forecasts very little curtailment from overgeneration, and that curtailment largely correlates to wind delivery issues at night.
Stakeholders responded that storage could hold the wind energy until morning. For that to be useful, Bakke said the storage would have to be locally sited and not general system storage.
Multiple stakeholders asked MISO for another analysis that includes assistance from storage and at what point an influx of storage produces diminishing returns.
Bakke said going forward, MISO would gauge storage solutions in the final phase of the study. He said MISO staff hear “loud and clear” that stakeholders would like to see how both renewables and storage interact on the grid.
Harlan also criticized MISO’s report for only showing averages of system conditions with renewable penetration. He said to properly plan resources, stakeholders need to see the most extreme scenarios that can occur.
MISO staff asked for more written stakeholder feedback on the analysis so far. They said stakeholder suggestions will shape the scope of the study’s third and final phase, which will begin in early 2019.
Bakke said the third phase of the study will either examine renewable penetrations beyond 50% or investigate penetrations up to the 50% benchmark more thoroughly.
FERC on Tuesday approved cost allocations for 60 new transmission projects added to PJM’s Regional Transmission Expansion Plan (RTEP), including three high-voltage projects allocated entirely to Dominion Energy’s zone despite protests that cost sharing of such regionally beneficial projects is under judicial review (ER18-2350).
The projects were filed on Aug. 30 and approved by PJM’s Board of Managers in July. The RTEP amendments include cost responsibility assignments for:
27 transmission enhancements and expansions that operate as lower-voltage facilities whose costs were allocated pursuant to the solution-based distribution factor method;
15 transmission enhancements costing less than $5 million whose costs were allocated to the zones where the enhancements are located;
Four transmission enhancements that were included in the RTEP solely to address individual transmission owner Form 715 local planning criteria, and whose costs were allocated to the zones of the individual TOs whose Form 715 local planning criteria underlie each enhancement;
Nine transmission enhancements that operate at or below 200 kV whose costs were allocated to the zones in which the enhancements are located; and
Five transmission enhancements needed to address spare parts, replacement equipment and circuit breakers whose costs were allocated to the zones in which the enhancement are located.
Dominion and Old Dominion Electric Cooperative argued that three of Dominion’s Form 715 projects address end-of-life planning criteria for high-voltage facilities, and that the D.C. Circuit Court of Appeals in August rejected FERC’s approval of a PJM Tariff revision that resulted in the RTO assigning all the costs to Dominion’s zone for two high-voltage projects the company initiated through its Form 715 criteria.
The court agreed with Commissioner Cheryl LaFleur, who dissented on the revision approval on the grounds that the commission should preserve regional cost allocation “for certain high-voltage projects, even if those projects are selected solely to address local planning criteria.” (See DC Circuit Court Rejects PJM Tx Cost Allocation Rule.)
However, in the current RTEP allocations, LaFleur, Commissioner Richard Glick and Chairman Neil Chatterjee determined that ODEC and Dominion were not alleging that PJM incorrectly applied its Tariff but were instead challenging the cost-assignment provisions of the Tariff itself, and therefore approved the allocations. The order also set Nov. 28 as the refund date for any Tariff revisions that occur when the court’s remand of FERC’s approval is addressed.
Commissioner Kevin McIntyre did not participate in the decision.
FERC on Tuesday granted FirstEnergy Services’ request to recover “prudently incurred abandonment costs” if Transource Energy’s embattled Independence Energy Connection is canceled (ER18-2510).
The request was made on behalf of FirstEnergy affiliates Potomac Edison and Mid-Atlantic Interstate Transmission (MAIT). The authorization allows the companies to recover 100% of any costs incurred for the project after Nov. 27 and 50% of any costs incurred prior to that date, which is the same structure that the project’s other developers — Transource, Baltimore Gas and Electric and PECO Energy — have already received.
The companies told FERC the project must be permitted by both Maryland and Pennsylvania — where it needs easements across roughly 300 private properties — and that, as a market-efficiency project, it faces heightened risk of cancellation because it is subject to annual PJM re-evaluation until it is permitted. The request also noted “local opposition” to sections of the project.
“This local opposition, coupled with the need for … the companies responsible for the other elements to obtain permits from multiple municipal and state authorities, heightens the permitting risk,” the companies argued.
Once referred to as the AP South Congestion Improvement Project, Transource’s Independence Energy Connection project would consist of two lines. The western portion would run from the Ringgold substation in Maryland to the Rice substation in Pennsylvania. The eastern line would run from the Conastone station in Maryland to the Furnace Run station in Pennsylvania. | Transource
Residents in the area of the project have been fighting against the project for years. Half a dozen opponents took the rare step of attending the September meeting of PJM’s Transmission Expansion Advisory Committee to voice their displeasure with the project and request that the RTO withdraw its approval. PJM explained its role is simply to evaluate the benefit of the project, and that the residents need to lodge their complaints with the state regulatory commissions that oversee permitting. (See PJM Redirects Residents’ Protests of Tx Project to States.)
The $366.17 million proposal is the largest congestion-reducing project PJM has ever approved. It would consist of two separate 230-kV double-circuit lines, totaling about 42 miles, across the Maryland-Pennsylvania border. One line would run between the Ringgold substation in Washington County, Md., and a new Rice substation in Franklin County, Pa.; the other would run between the Conastone substation in Harford County, Md., and a new Furnace Run substation in York County, Pa.
PJM estimated that Potomac Edison will be assigned $62.06 million in costs for its part of the project’s construction, while MAIT will pick up $6.42 million. Despite criticism, the RTO has maintained that the project stands to provide more benefits than it will cost. (See PJM Reiterates Support for Embattled Transource Project.)
LIVERPOOL, N.Y. — While offshore wind has dominated the energy agenda in the Northeast this year, New York officials are taking care to nurture the economic potential of onshore wind as well.
“In New York, new turbine technologies and cost reduction mean that land-based wind opportunities for the state are growing,” Alicia Barton, head of the New York State Energy Research and Development Authority, said Tuesday at a summit hosted by the New York State Laborers’ Organizing Fund (NYSLOF).
Barton cited a recent NYSERDA clean energy report showing “the sector growing at a rapid rate, last year at 4%, about double the overall employment growth rate in the state,” with wind farms accounting for an average of 32 workers per project.
“We see the success of land-based wind projects really paving the way for future wind development,” Barton said. “This is exciting not only for our ability to attract that type of investment, but it is making a significant contribution to our ability to deliver a cleaner future for New York communities.”
One summit participant asked how NYSERDA enforced local content and labor provisions in the state’s renewable energy contracts, such as requiring developers to pay the prevailing wage to workers.
Barton said that NYSERDA is not involved in some projects built by out-of-state developers, but compliance on state contracts so far has been very good.
“There are probably 20 proposed windmill projects in our area,” said New York Upstate Laborers’ District Council leader Sam Capitano. “Some of the developers here we have relationships with, some we do not … these jobs are important to our area, and … our labor market is challenged right now.”
Harrison Watkins of NYSLOF noted the importance for labor to participate in the planning process for renewable energy projects.
Barton said her agency also is “very excited about the new frontier in wind, which is offshore wind energy.”
NYSERDA will soon issue the state’s first offshore wind solicitation in consultation with the New York Power Authority and the Long Island Power Authority. The agency will announce the award in the second quarter of 2019 and, if needed, issue a second solicitation next year to meet the 800-MW goal.
“Ideally it would take two years from project proposal to final permitting,” Anne Reynolds, executive director of the Alliance for Clean Energy New York, said regarding onshore projects. “Remember, only one project so far has passed all the way through the Article 10 process, and that’s the Cassadaga wind project, so it’s hard to say what the average time is.” (See Overheard at ACE NY 2018 Fall Conference.)
The New York Public Service Commission on Nov. 15 granted a certificate of public convenience and necessity for the 126-MW Cassadaga wind project in Chautauqua County, southwest of Buffalo on the shores of Lake Erie (Case 18-E-0399).
New York in 2011 revised Public Service Law Article 10 to unify siting reviews of new or modified electric generating facilities under one state agency, the Board on Electric Generation Siting and the Environment.
“It’s going to come down to if, and under what circumstances, the siting board will override local law,” Reynolds said. “Remember, this is the third generation of this law, and when it was originally passed there was no wind or solar on the horizon; it was about fossil fuel power plants.”
The intent of the law was to enable the state to prevent communities from blocking a needed power plant, she said.
“The world has changed, and now a law that was primarily designed for fossil fuel is being applied to renewable energy plants,” Reynolds said. “It’s a legal and philosophical question as to whether the state should, could and under what circumstance override local law … the original intent of the law was, in the public good, the state should be able to override local laws so that we all could have safe, and now clean, electricity.”
“Permitting is a process that involves basically anyone who wants to be involved, which is a good thing, but a challenge for the state,” said Sarah Osgood, director of policy implementation at the Department of Public Service.
“Having a one-stop shop for siting these large projects is a fantastic concept for a process but makes delivering on it challenging,” Osgood said.
“By having the state agencies review these projects, review multiple projects, there is so much potential for having some predictability and standardization built in as we go forward and get some precedent-setting information,” said Valessa Souter-Kline, project developer on Invenergy’s proposed 380-MW Alle-Catt wind project in western New York. The other positive attribute of state-controlled siting is the ability to work across jurisdictions, she said.
“At Invenergy, we’re seeing the opportunity to have larger projects, which mean more jobs and more community benefits than we were able to do under individual seekers,” Souter-Kline said.
Good, successful wind projects are engaged in the local communities, so a state-level process under Article 10 does not mean that developers stop working with municipalities, she said.
“Built into that is a little bit of confusion around who’s making decisions,” Souter-Kline said. “A lot of town supervisors or town leaders who are getting pressure from opposition will sometimes toy with this idea of ‘Do we actually need to update our local laws, or is the state going to override it?’ There’s an interesting tension there as to who’s taking responsibility for this project.”
Barton said that NYSERDA for years has been developing toolkits for municipalities “and have upped our staffing, so we’re not just putting them on our website, but going to those communities.”
“There are a lot of myths about wind power,” Reynolds said. “If a project was proposed in your town, where would you go to get the facts? The American Wind Energy Association to me is a reputable source, but other people would say, ‘Oh, that’s just the industry,’ so the struggle is to give the information from a source people trust.”
Osgood said the state is trying to put reliable information out there, but that some people question the state’s motives because of its ambitious renewable energy goals.
Reynolds said that opposition to renewable energy projects is probably inevitable and possibly based on very simple reasons: “I personally think the arguments against wind energy are because people don’t want to see the turbines.”
ISO-NE on Wednesday said it expects to have sufficient capacity on hand this winter to meet load, which it forecasts will peak at 20,357 MW in normal weather conditions or 21,057 MW in extreme cold.
The region contains 4,500 MW of natural gas-fired generating capacity at risk of not being able to get fuel when needed, the RTO estimates.
“Last winter demonstrated just how much the weather can impact power system operations, not just in terms of consumer demand for electricity, but in the ability of generators to access fuel,” Peter Brandien, ISO-NE vice president for system operations, said in a statement.
Satellite image of a blizzard rapidly deepening off the Northeastern U.S. at 8:45 a.m ET on Jan. 4, 2018. | National Oceanic and Atmospheric Administration
During a two-week cold snap that started the day after Christmas in 2017, the region burned 2 million barrels of oil, more than it would in an entire year of more temperate weather. Shortages of natural gas continue to be a major concern for the grid operator.
Extreme cold weather constrains natural gas pipelines’ ability to deliver fuel for gas-fired plants and can also impact oil and LNG deliveries and generation from renewable resources, ISO-NE said. (See Familiar Winter Story: ISO-NE Braces for Gas Shortages.)
New initiatives by the RTO include forecasting the region’s available energy supplies for the next 21 days and providing a market mechanism to ensure that limited fuel supplies are used when they are most valuable for system reliability and cost-effectiveness.
Earlier in November, Mark Karl, ISO-NE vice president for market development, said the RTO is looking to create a new “energy inventory reserve constraint” to optimize the use of limited energy over more extended periods compared with how markets are currently designed to optimize energy over the course of an operating day. (See New England Talks Energy Security, Public Policy.)
The grid operator on June 1 integrated price-responsive demand into its markets and its new Pay-for-Performance rules, which provide for enhanced incentives in the form of bonus payments and institute financial penalties, ensuring resources are ready to meet their obligations to provide energy and reserves or reduce demand if needed. (See ISO-NE Begins Real-time Dispatch of Demand Response.)
The 2018/2019 winter outlook forecasts availability of 32,300 MW of resources with capacity supply obligations from the Forward Capacity Market, and total resources of 34,415 MW. The winter 2017/2018 peak demand of 20,631 MW occurred on Jan. 5, 2018, during the 5 to 6 p.m. hour.
The all-time winter peak in New England of 22,818 MW occurred on Jan. 15, 2004, while the all-time peak demand of 28,130 MW occurred on Aug. 2, 2006.
VALLEY FORGE — PJM is nearing the finish line in determining how it handles the primary frequency response (PFR) requirements put in place by FERC Order 842.
Stakeholders and staff put the final touches on the three remaining proposals at Tuesday’s meeting of the Primary Frequency Response Senior Task Force. (See “Primary Frequency Response Moving Forward,” PJM Operating Committee Briefs: Nov. 6, 2018.)
The proposals differ on thresholds for inclusion in the requirement, and on whether and how units that provide the service should receive separate compensation. A fourth proposal, offered by American Electric Power, has been removed.
Still under contention within PJM’s proposal is whether units can claim exemptions from the PFR requirements if installing the necessary technology would be prohibitively expensive. The RTO had added language that exemptions could not be justified “solely” on economic grounds, but Howard Haas of Monitoring Analytics, the Independent Market Monitor, said that a technical exemption should only be allowed if there is a “physical restriction that cannot be rectified using available commercial alternatives.”
He said the market should determine whether a commercial solution is economically feasible, and the requirement would remain either way.
PJM’s Vince Stefanowicz agreed that the rule should be that economics cannot be used as an exemption criteria.
“It sounds like we muddied the water” with the revisions, he said. “I’m actually inclined to go back to the original wording.”
PJM staff joked that removing the revision would leave the proposal “sole-less,” and Haas agreed.
“It would be ‘sole-less,’ just as economics should be,” he said.
But Bob O’Connell of Panda Power Funds and FirstEnergy’s Jim Benchek criticized the removal, arguing that prohibitive cost should be a consideration in approving exemptions.
PJM’s Glen Boyle said that equipment manufacturers provided feedback to staff that the necessary solutions are commercially available and low-cost. O’Connell asked for that understanding to be documented in the revisions.
Additional Discussions
David “Scarp” Scarpignato asked PJM to analyze whether units at 100% maximum output can receive an exemption from evaluation of PFR performance during a frequency event in the same way that units aren’t evaluated when at minimum output during an event. Staff agreed to review wording.
Staff also agreed to work with the Monitor on agreeing to a single megawatt threshold for aggregated resources under which they would be exempt from providing PFR. Currently, the Monitor’s proposal has a 10-MW threshold while PJM’s is 20 MW.
They also said they would provide a PFR market solution “if one becomes viable.” Calpine’s proposal calls for allowing units that produce more PFR than required to sell it. PJM is concerned how that would work for system restoration.
“The short answer is I’m not sure how you’d do that,” Stefanowicz said.
While PJM and the Monitor are attempting to avoid FERC-approved cost recovery similar to how reactive service is paid, stakeholders complained that the proposed process — in which PJM and its Monitor agree on a fair rate — doesn’t allow for due process for the unit seeking the rate while commission approval does. They asked PJM and the Monitor to develop language to determine standards and how the process will occur.
Next Steps
Reconciliation of the revisions should happen soon, staff confirmed.
“I think it can be resolved pretty quickly,” Boyle said.
Staff plan to open a one-week poll on the proposals that will close on Dec. 3 and have the results ready to review for the task force’s next meeting on Dec. 5. Packages that receive at least 50% support will receive a first read at the Dec. 20 meeting of the Markets and Reliability Committee. The proposal with the most support will be the main motion, and any others that meet the threshold will be considered as alternates.
The proposals will then be offered for consideration at the Jan. 24 meeting of the MRC and Members Committee. Endorsement on that timeline would lead to a filing at FERC in early February, PJM’s Jim Burlew said, and the RTO likely would seek an effective date of 60 days after approval. That would trigger the beginning of PJM tracking units’ performance during PFR events. However, as part of PJM’s implementation timeline, repercussions of the scoring, including referral to FERC enforcement, wouldn’t take effect for two years following FERC approval.
The poll will also include a question about whether stakeholders prefer a change to the status quo. If no proposal receives at least 50% or if the vote shows a preference for the status quo, staff will provide the results as part of the task force’s update and ask the MRC for further direction. Boyle indicated that, in that case, the RTO might decide to file a proposal for FERC approval without stakeholder endorsement under Section 206 of the Federal Power Act.
“I don’t think PJM would consider status quo an acceptable outcome,” Boyle said.
HOUSTON — ERCOT CEO Bill Magness says utility-scale solar “is the next big thing coming at us from the supply side,” giving the ISO just one more challenge to consider.
Noting that solar and wind generation generally complement each other, Magness told a recent Gulf Coast Power Association luncheon that solar “tends to fill the gap during the [late-morning, low-wind hours as load ramps up] … before coastal wind picks up later in the afternoon.”
“[Solar] will continue to accentuate the challenge other types of resources find in having to run economically,” Magness said. “It’s an interesting challenge as we go forward.”
Solar was expected to provide nearly 2 GW of capacity to meet ERCOT demand this winter, but the ISO’s interconnection queue tells a different story for the future. There, 32.2 GW of solar projects are in various stages of the study process, nearly equal to the 40.2 GW of wind projects under study. Together, solar and wind account for 86.8% of the 83.4 GW of the proposed projects in the queue (wind is providing almost 22 GW of capacity this winter).
“It’s all gas, wind and solar. There are no other resources coming along,” Magness said. None of the 1.8 GW of battery storage resources in the queue have a signed interconnection agreement.
“Our solar is very different from [that of] California. California has a lot of solar, but it’s primarily rooftop,” he said. “We’ve seen the real growth in utility-scale. Rooftop is coming, but the big chunks are coming on the utility side.”
ERCOT projects it could have as much as 5 GW of solar energy on the system by 2021, as developers continue to take advantage of the expiring tax credits. Most of those projects have been sited in West Texas, where the irradiance is best.
“As wide an expanse as Texas is, east to west, it’s a different picture in how solar will react than in California,” Magness said. “We’re having to do a lot of work figuring these things out, just as we did with wind.”
He said staff will have to start forecasting solar energy, as they did with wind.
“It was something we didn’t really need to do,” Magness said. “There was never a need to forecast generation. You turned it on, you turned it off. We’re getting better and better with the use of those tools.”
Also of concern to ERCOT is the growth of distributed energy resources (DERs), which can include gas or diesel technologies and storage assets, all connected to the distribution system. The ISO has seen a growth rate of 62% in DERs over the last three years, although the current grand total is only about 1.3 GW of capacity.
“For ERCOT, it’s a question of visibility,” Magness said. “If we don’t know it’s out there, we can’t get it in the system model.”
Staff has spent considerable time recently working with transmission and distribution providers to map some of the 93 existing registered DERs and to map all registered DERs to the system load. The goal is to capture the DERs’ capabilities and capacity “to where they make sense in the models.”
“If you have generation that runs on the system and wants be in the market, you want it to run in the right time and at the right place,” Magness said. “We welcome megawatts of all kinds. We’re just being sure we’re able to see [DERs] and they send the right price signals to make the most effective market.”
Pattern of Load, Wind and Solar on Peak Days | ERCOT
He pointed to ERCOT’s performance in the face of slim reserve margins this summer, when it met record demand multiple times without having to take emergency measures or call on additional resources, as an example of the energy-only market’s effectiveness. (See ERCOT SHs Debate Need for Changes Following Summer.)
“Most of the capacity we saw was self-committed. We didn’t need to intervene that many days,” Magness said. “The incentives in the energy-only market are aligned when you keep running in the peak season. We saw the energy-only market work as designed.”
