LITTLE ROCK, Ark. — SPP stakeholders last week directed the Seams Steering Committee to stop work on proposed Tariff changes that would have granted a waiver from charges for unreserved transmission use across the seams.
The Market and Operations Policy Committee’s action during its Oct. 16-17 meeting means SPP’s current practices for unreserved use will continue. They have resulted in about $23,000 in service charges since 2016, but only when that unreserved use is reported to the RTO.
The revision request (RR308) would have granted transmission customers a four-hour grace period for unreserved service during an unplanned transmission outage. SPP’s Tariff and its business practices do not allow exemptions for transmission customers using the RTO’s system to take transmission service because of outages, whether planned or unplanned.
The SSC was unable to reach a consensus during its monthslong discussions, with some members saying temporary use of interconnected systems should be a benefit and others calling for transmission owners to be compensated. The four-hour grace period was a compromise position.
“Several members thought the four-hour grace period was at least some justification to take this to FERC and stakeholders,” American Electric Power’s Jim Jacoby, chair of the SSC, told the MOPC. “It seemed to have at least some backing. From an AEP perspective, that’s a benefit of interconnected systems. We ought to give customers some time [to arrange service during an unplanned outage].”
RR308 received little support from SPP’s legal department. Associate General Counsel Mike Riley pointed to excerpts from FERC Orders 890 and 890-A, which address situations where a customer is unaware of changing conditions that result in additional service requirements. Riley said FERC’s language does not exempt “any class of transmission customer from the potential assessment of unreserved use penalties” and refers to entities “serving native load in multiple control areas.”
“Not being a FERC commissioner, it’s hard to say what the [language] is intended to cover, but when I read words like ‘multiple control areas,’ that seems applicable to us,” said SPP’s David Kelley, director of seams and market design.
“If SPP and the stakeholders have a basis for filing and justifying this four-hour window, or grace period, we’ll absolutely file it,” Riley said. “But based on 890’s provisions, where FERC appears not to make a distinction between reserved use and unreserved use, we’ve got an uphill battle.”
Riley agreed with the concept of a grace period before assessing penalties, saying it should be a business practice in the Tariff.
“We just haven’t seen or found a justification that would get us over the 890/890-A hurdle, but it’s up to FERC,” he said.
Several members suggested SPP could conform its practices with those of MISO — which Southwestern Public Service’s Bill Grant said MISO does not apply unreserved charges in similar situations — through their joint operating agreement. But Kelley pointed out, “Even if we address this issue through the JOA, we’ll still have to make a filing at the commission. We still have to get around the hurdles of what we’re arguing.”
“This is not being applied consistently,” Grant said. “Only when SPP knows about it.”
“What we’re trying to do is address the unfortunate bystander that doesn’t know what’s going on, and only finds out about it when they get a bill,” AEP’s Richard Ross said.
On the sidelines, some members referred to the TOs who reported unreserved use as “tattletales.”
The MOPC’s motion passed over 10 opposing votes and five abstentions.
LITTLE ROCK, Ark. — SPP members last week approved one of two Generator Interconnection Improvement Task Force recommendations but took no action on the second and agreed to disband the group.
The task force was formed last year to identify improvements in the RTO’s transmission study process, which is backlogged with more than 62 GW of interconnection requests. Its work will be carried on by various working groups.
The Market and Operations Policy Committee approved the GIITF’s suggestion to address generator interconnection studies in regions where the amounts of new generation being requested exceed load during spring and other light load periods.
SPP currently divides its footprint into cluster groups for individual study. In the high variable energy resource case, all VERs inside the cluster are set to 100% of capacity while external VERs are set to 20% to simulate counterflow to the internal generation.
With the increase in VERs, the amount of counterflow contained in the Integrated Transmission Planning models is high enough that the simulation is no longer needed, and the 20% setting has resulted in situations with insufficient load to absorb all the generation being requested. Under the new rules, the external VERs remain at the base reliability dispatch setting used in the ITP process.
“The changes here allow the energy to flow a further distance to a neighboring zone, which should identify [needed] transmission upgrades,” said Tradewind Energy’s Derek Sunderman.
Task force Chair Al Tamimi, of Sunflower Electric Power, said the change “might help us move forward with [definitive system impact studies].” Staff is working on study requests that date back to 2015.
“That should tell us something,” Oklahoma Gas & Electric’s Greg McAuley said. “We’re dancing around the problem. We have too much generation coming in, and we have no place to put it.”
McAuley pointed out that the Holistic Integrated Tariff Team is also working on the problem. “We don’t know where they’re going to land,” he said.
The measure passed with six opposing votes, mostly from transmission owners, and 14 abstentions.
Members declined to take a vote on the GIITF’s recommendation to change the criteria for allocating network upgrade costs to interconnection customers by adding a new energy resource interconnection service (ERIS) criterion.
Under the proposal, SPP would have first allocated cost responsibility to requests with 20% or more of the generator’s output flowing across a constrained element, as under current practice.
After applying the 20% transfer distribution factor (TDF) test, the proposal would have added a second screening to determine which requests have at least a 5% TDF. If the number of such requests resulted in a cumulative TDF of 20% or more, a mitigation would be assigned to the cluster, with the cost allocated to those requests with at least a 5% TDF.
SPP said the change would have resulted in the identification of four additional constraints in the DISIS-2016-001 study.
But several members said the recommendation didn’t go far enough in identifying constraints caused by interconnection requests. Staff agreed the current process doesn’t catch enough constraints.
The committee also accepted a storage white paper for incorporation into SPP’s generator interconnection processes. The document describes proposed rules for processing and evaluating storage interconnection requests. Two members opposed the motion and three abstained.
WASHINGTON — Infocast’s inaugural Storage East summit drew policymakers, grid operators, utilities and companies looking to break into energy storage to the Washington Plaza Hotel last week. Panelists discussed the optimism surrounding the industry, as well as strategies for locating resources and optimizing their services for maximizing returns.
FERC Commissioner Neil Chatterjee kicked things off by recalling actions the commission has taken on storage since he joined in August 2017. The highlight of these was the February issuance of Order 841, which directed RTOs and ISOs to revise their tariffs to allow energy storage resources full access to their markets. (See FERC Rules to Boost Storage Role in Markets.)
When Chatterjee joined FERC as chairman, he restored the commission’s quorum, which it had been without for six months. He said he had expected to be able to vote on a final version of the commission’s November 2016 Notice of Proposed Rulemaking as soon as he walked in, but he found that staff were still working on “a number of complex, legal and technical issues.”
“Understanding the importance of what was at stake, during my tenure as chairman, I worked closely with staff to push that final rule forward,” he said proudly. “I believe in the potential for storage to be a transformative technology for our grid. Storage is a game-changer. I’ll admit it’s a bit cliche, but there’s truth to it.”
He also noted the importance of Order 845, which revised the commission’s pro forma large generator interconnection procedures and interconnection agreement. One of the 11 changes the commission approved was to include storage in the definition of “generating facility.” (See FERC Order Seeks to Reduce Time, Uncertainty on Interconnections.)
Another change allows generators to sell their surplus interconnection capacity to other resources. Storage owners can purchase surplus capacity for their resources so they can interconnect without having to go through the full queue, Chatterjee said.
“While this change in policy sounds very wonky — and it is — I think it’s a subtle but important action we’ve taken to improve opportunities for storage development.”
Chatterjee also noted the challenges storage still faces. RTOs and ISOs face a Dec. 3 deadline for their Order 841 compliance filings. FERC is “likely to take several months” to review them, and any deficiencies it finds will delay implementation further, Chatterjee said.
He also said grid operators have been slow to develop new products to compensate storage resources for their different services.
“With the exception of PJM’s RegD product, there’s been little momentum toward expanding the traditional set of ancillary services in the past few years,” Chatterjee said. “The increasing penetration of renewables might provide additional momentum for such products, but in any event, whether and how these products come to fruition could have a significant effect on the opportunities for storage.”
Siting and Co-location
Multiple panelists discussed the best strategies for deciding where to develop storage resources.
Storage can receive the federal investment tax credit when added to existing qualifying resources, mainly solar facilities. But Michael Harrington, of Consolidated Edison’s Utility of the Future department, pointed out that the New York State Energy Storage Roadmap, issued in June, predicted that more than half of the 1,500 MW of storage the state aims to procure by 2025 would be downstate, close to New York City’s load.
“We do think there’s opportunity with upstate renewables, but certainly we recognize that storage is going to follow where the economics are the best,” he said.
Ascend Analytics CEO Gary Dorris explained why being near the city is so attractive for storage. The best way to determine where to site storage resources, he said, is finding where prices are most volatile: where congestion on the grid is most persistent.
Price spikes occur very infrequently on a typical New York node — only 1.5% of a 24-hour day — but they represent 22% of the average real-time energy price, according to Dorris. “So storage can be a wonderful physical hedge against price spikes, and that’s a real opportunity to mitigate uncertainty in supply by having that physical hedge in attacking those price spikes.”
“Co-located storage with renewables certainly has benefits, but is co-locating renewables with storage going to become standard practice?” Chatterjee posited. “The answer to that question could have major implications for storage. We have evidence that the cost-benefit ratio of co-located storage is tipping in favor of adding storage.”
Prices in New York state are highest near the New York City metro area, where there is persistent transmission congestion. This presents the best economic opportunity for storage resources. | Ascend Analytics
He pointed to a 2017 resource solicitation by Xcel Energy’s Public Service Company of Colorado. While individual wind and solar resources received median offers of $18/MWh and $29 MWh, respectively (“amazing numbers in their own right”), wind and solar resources co-located with storage received a $3 and $7 premium.
“When you consider market incentives like … capacity constructs in PJM and ISO-NE, co-location could be extremely beneficial in allowing renewables to avoid performance penalties and take advantage of high prices,” he said.
Wish List from States, RTOs
Several speakers said grid operators and states could be doing more to value storage’s services.
In introducing a panel on innovative business models for storage, Dorris suggested that states should lower their property taxes for storage. Taxes are particularly high in the Northeast, where storage is most in demand. “That’s probably not being talked about as much as perhaps it could be given the nature of these projects,” he said.
The panelists focused on the lack of a “T&D benefit” in RTOs and ISOs, saying storage should be compensated for its congestion-reducing benefits as energy efficiency programs are. Such programs are valued in part for reducing the voltage levels on transmission and distribution lines, allowing transmission owners and utilities to defer costly upgrades.
“Just level the playing field between how you treat conservation and how you treat storage,” Dorris urged.
“As a developer, we need to have certainty, and we need to have predictability going forward,” said Thomas Leyden of EDF Renewables. “That’s not easy in a market-based system, but there are things that can be done to help our investors become more comfortable.”
Adam Rousselle, CEO of Renewable Energy Aggregators, went further. He noted that transmission owners get paid fixed rates of returns based on the value of their assets. “If we can not align the development of storage with the transmission owner, we won’t be building storage any time soon in PJM,” he said. “And if your solution delays their transmission investment, they’re competing with you, make no mistake about it.”
PHILADELPHIA — Fugitive methane emissions might be reduced throughout the natural gas supply chain by making accidental leaks and routine venting part of the carbon markets being considered for the power industry, panelists told attendees Wednesday at a policy forum hosted by The Kleinman Center for Energy Policy at the University of Pennsylvania.
The key would be developing a market that taxes emitters but also pays those who capture emissions, as the technologies would also be useful for reducing methane emitted by nature — either as part of natural processes or negative feedback loops exacerbated by global climate change.
“If you can price greenhouse gas emissions and you put in that financial incentive for capturing it, and then whatever brilliant technology gets developed, it faces the right incentives and it has a financial ability to move forward,” said Catherine Hausman, an assistant professor of public policy at the University of Michigan. “The carbon tax, the flip of that is the subsidy or whatever for what gets captured.”
She suggested a policy, which she acknowledged has legal concerns, where every potential source of methane in a region would be responsible for a share of the area’s emissions unless it can prove it wasn’t the source. That would incentivize gas producers and pipelines to monitor their operations to prove themselves innocent.
The panelists weren’t afraid to promote increased governmental regulation.
“Tax the emission if you can. Absent a tax … you need regulations on the way they run. … I am totally happy with regulatory measures that are not market-based in situations where you can’t develop market-based solutions,” Hausman said. “I always teach that zero pollution is not the right answer because it stops all economic activity. Now, very aggressive action is certainly needed.”
“I would love to get to the place where methane emissions from the oil and gas industry are appropriately taxed. … Our view is we’re not there yet,” the Environmental Defense Fund’s Ben Ratner said. “Where we really want to get to over time is prevention. … There’s just no way around government action.”
From left, Environmental Defense Fund’s Ben Ratner, Catherine Hausman, assistant professor of public policy at the University of Michigan, and moderator Karen Goldberg, a chemistry professor at the University of Pennsylvania and the director of the Vagelos Institute for Energy Science and Technology. | (c) RTO Insider
Another challenge for developing a carbon market will be defining what values are used to determine payments. As hard as it is to nail down a valuation of carbon — the panelists noted suggestions from $40 to $400/ton — so too is calculating the amounts emitted. And while researchers can estimate global emissions, “knowing the precise location [of the source] is what’s hard,” Hausman said.
“You have to solve the measurement problem,” she said.
“There’s still so much uncertainty about global emissions … that we don’t know yet what [each source’s emissions limit] should be,” Ratner said.
Hausman suggested the key might be locating “super-emitters.”
The panelists also criticized the Trump administration for attempting to reverse regulations on methane emissions in the oil and gas industry. The Clean Air Act’s procedural rules barred the Obama administration from expanding its more stringent regulations for new and modified facilities to existing facilities, Ratner said.
The hope was for the next administration to make that expansion, he said. But “not only is this new administration not doing that, it seems to be intent to roll back” the Obama revisions, he said.
ARLINGTON, Va. — FERC Commissioner Neil Chatterjee and Assistant Energy Secretary Bruce Walker pledged to continue their work on grid resilience Wednesday following the apparent demise of the Trump administration’s latest plan to prop up struggling coal and nuclear plants.
The two appeared at the Department of Energy’s Electricity Advisory Committee meeting, where Walker charged the panel with reconsidering current practices on spinning reserves, calling it wasteful to have 15% of capacity “doing no work.”
Walker also did a little spinning of his own, insisting that DOE’s “leaked pre-decisional memo” calling for price supports for “fuel secure” generation was never about propping up nuclear plants or the coal industry. The memo became public at the beginning of June, after Trump — who had made saving the coal industry a signature campaign promise — directed Energy Secretary Rick Perry to “prepare immediate steps to stop the loss” of fuel-secure generators facing retirement. (See Trump Orders Coal, Nuke Bailout, Citing National Security.)
“It was not focused on coal or nuclear,” Walker said. “It was a recognition that there has been a significant change in the portfolio of generation throughout the United States … most notably a significant reliance on natural gas pipelines for electric generation.”
Talking to reporters after his speech, Walker elaborated. “The fact is, the words in the pre-decisional memo were ‘all fuel secure generation.’ Everybody misinterpreted the words for whatever political reasons they chose to,” he said. “There’s liquid natural gas that can have on-site fuel. There’s biomass conversion that has on-[site] fuel. … Pump storage, that’s fuel-secure generation. Hydro, that’s fuel-secure generation.”
Chatterjee in a Rush
The normally gregarious Chatterjee rushed with aides to an awaiting SUV immediately after his remarks from the podium, declining to take questions from the committee and refusing to talk with reporters.
Asked how the apparent failure of the Trump/Perry plan would affect FERC’s work, Chatterjee said, “We’ve got our resilience docket open.
“We’ll continue to work on it,” he said, getting into the car. FERC opened the resilience docket in January after rejecting DOE’s earlier bid to help coal and nuclear plants. (See FERC Rejects DOE Rule, Opens RTO ‘Resilience’ Inquiry.)
Was the demise of the DOE plan disappointing to him? “I didn’t even know what they were considering,” Chatterjee said.
McIntyre’s Future
Chatterjee’s haste may have had less to do with the coal and nuclear plan than with rumors that FERC Chairman Kevin McIntyre, who has been battling a brain tumor, may announce his resignation. Chatterjee — who had reportedly visited the White House on Oct. 16 — declined to respond to reporters’ questions about McIntyre’s status and whether he would resume as acting chairman.
McIntyre did not attend the commission’s open meeting Thursday, the second he has missed since a fall that left him visibly uncomfortable at the meeting in July. (See Ailing McIntyre Absent from FERC Open Meeting.)
Chatterjee noted McIntyre’s absence as he opened Thursday’s meeting, saying “My prayers are with him and his family.”
“I’m very sorry Chairman McIntyre is not able to be here today, and I continue to send warm wishes to him for his recovery,” Commissioner Cheryl LaFleur said.
In March, McIntyre issued a statement saying he had undergone “successful surgery” for a “relatively small” brain tumor that was discovered in summer 2017. He said he did not intend to provide further details or updates for privacy reasons.
At the July meeting, he wore a sling after disclosing he had injured his arm and suffered compression fractures in two of his vertebrae in a fall. (See “McIntyre Toughs it out,” FERC Says Farewell to Powelson.)
Although he was not present for the September meeting, McIntyre participated in its votes; he was not recorded as voting on Thursday.
Sources have told RTO Insider that the chairman is often absent from FERC headquarters and that meetings with him have been frequently rescheduled as a result. Spokeswoman Mary O’Driscoll last month declined to answer questions on the subject.
Chief of Staff Anthony Pugliese told reporters after Thursday’s meeting that the chairman would issue a statement on his status within a few days.
With the resignation of Republican Commissioner Robert Powelson in August, the commission is now split 2-2 between Republicans and Democrats. Earlier this month, President Trump nominated the Department of Energy’s Bernard McNamee as Powelson’s replacement. (See Trump Nominates DOE’s McNamee to FERC.)
Perry: Out of Our Hands
DOE’s Walker, who heads the Office of Electricity, did not explicitly confirm the numerous news reports that the White House had rejected DOE’s proposal following opposition from the National Security Council and National Economic Council. Perry told reporters in September that DOE had finished its resilience proposal and was awaiting a White House decision.
The memo outlined “one of the many possible solutions,” Walker said. “We are focused on national security. We will continue to look at what are the things that best support the infrastructure that’s needed under national security.”
Great Plains Energy’s merger with Westar Energy in June has increased market concentration in the new company’s reserve zone, but it “is not necessarily a cause for concern at this time,” SPP’s Marketing Monitoring Unit said in its most recent quarterly State of the Market report.
| Great Plains Energy
The new company, Evergy, is the largest energy consumer in SPP, accounting for 19.7% of summer consumption, according to the Oct. 15 report, which covers June through August.
System summer energy consumption | MMU
Evergy, American Electric Power (17.1%), Oklahoma Gas and Electric (11.6%) and Southwestern Public Service (10.2%) consumed almost 60% of the RTO’s total energy in the summer, pushing the market’s post-merger Herfindahl-Hirschman Index (HHI) above 1,000 at times, indicating a “moderately concentrated market.”
“If a continually increasing trend is observed in the future, it would require further analysis,” the report says.
The Evergy reserve zone’s average summer prices were below 2017 levels for July and August, at around $30/MWh and $25/MWh, respectively. June prices were more than $30/MWh, primarily because of higher temperatures and loads across SPP.
The report notes:
Low energy prices, with summer prices averaging around $25/MWh;
A continued decrease in intervals that experienced negative energy prices; and
A decline in overall congestion across the footprint.
The report’s “special issues” section also reviews the market’s manual commitment process. The MMU said that while SPP operators have improved their consistency in coding and reporting manual commitments, they should add more detailed and consistent reasons for local, transmission, capacity and stagger commitments.
Noting that FERC Order 844 in April added market-transparency requirements for resource commitments, the Monitor recommended SPP report publicly all manual commitments. It also noted the high number of manual capacity commitments for ramping needs and renewed its call for a ramp product, saying it would be more effective.
The MMU will host a webinar on Nov. 8 to discuss the report.
WASHINGTON — Observers of FERC’s technical conference on grid operators’ preparations for winter on Thursday would be forgiven if they experienced deja vu.
Most of the RTOs say they are ready; CAISO is keeping an eye on natural gas storage levels but not concerned; and the possibility of fuel shortages during an extended cold spell is keeping ISO-NE officials up at night.
“You know, I feel like we’re in a long-running production of ‘same time next year,’ where every fall you come and say, ‘We have plenty of capacity, we might not have enough gas, I’m cautiously optimistic we can make it through,’” FERC Commissioner Cheryl LaFleur told Peter Brandien, ISO-NE vice president of system operations.
The National Oceanic and Atmospheric Administration is predicting a warmer-than-normal winter for most of the U.S., including New England. But Brandien said it is not the average temperature that concerns him; it’s the duration of low temperatures.
“It’s not that the electric load increases; it’s that the fuel kind of disappears” because home heating takes priority over electricity generation, he said. “Last winter, December, January and February were all above average temperatures and weather. But we experienced extreme cold weather Dec. 26 through Jan. 8, and it’s those kind of spells that cause us concern.”
When gas is short, ISO-NE relies on oil as backup fuel. But severe weather can cause delays not only for barges shipping in LNG, but for trucks carrying barrels of oil. Generators burning oil also face emission limits.
In their presentation to commissioners during their open meeting earlier that day, FERC staff also noted this will be the first winter under ISO-NE’s Pay-for-Performance capacity construct, which became effective June 1. The program is intended to better incent generators to perform during scarcity and emergency conditions, and influenced PJM’s Capacity Performance construct.
But being the first years of these programs, Brandien said anything beyond a weeklong cold spell was unknown territory for the RTO.
No Worries Elsewhere
Representatives from the other FERC-jurisdictional grid operators reported that they were able to maintain reliability last winter despite two major cold snaps in January — one including the so-called bomb cyclone — and that they were similarly prepared for this winter.
Emilie Nelson, NYISO vice president of market operations, also referenced the late December/early January cold snap, which led to the ISO’s third highest winter peak load since 2004, at about 25.1 GW. Nelson said NYISO does not expect any problems this winter, but it is undertaking several efforts to plan for the long term. One of these is a fuel security study next year “to evaluate the ability to meet electric system needs during stressed system conditions, such as prolonged cold weather events and disruptions in fuel availability.” (See related story, NY Ready for ‘Average’ Winter; Burman Worried.)
Both Robert Benbow of MISO and Bruce Rew of SPP noted the mid-January cold snap in the South, when both MISO South and SPP set new all-time winter peaks on Jan. 17 of 32.1 GW and 43.6 GW, respectively.
While MISO maintained reliability through the event, Benbow said the RTO saw opportunities to improve its coordination with members and neighbors. Those lessons helped improve performance during a maximum generation event in September attributed to a major load forecasting error, he said. (See MISO: Sept. Emergency Response Improved by Jan. Event.)
Nancy Traweek, executive director of system operations for CAISO, said nothing has changed in regards to gas since last winter. Two pipelines in California — Southern California Edison’s Line 235-2 and Line 4000 — remain out of service, and her “favorite friend,” the Aliso Canyon storage facility, is still a last-resort resource for withdrawals. Rather than winter, Traweek said, the ISO is still concerned about summer.
“Right now we’re still considered in summer; it’s very warm and dry in California, and really the biggest risk we have right now is the risk of wildfire,” Traweek said. “It’s becoming a year-round issue. It used to be October would be our big wildfire season, and now we can see it any time of the year.”
Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees 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 Wilmington, Del., covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Markets and Reliability Committee
1. PJM Manuals (9:15-9:35)
Members will be asked to endorse the following proposed manual changes:
B. Manual 13: Emergency Operations. Revisions developed as part of PJM’s comprehensive security-threat review.
C. Manual 11: Energy & Ancillary Services Market Operations. Revisions developed to address FERC approval of Tariff changes related to a new day-ahead pseudo-tie transaction product designed to address overlapping congestion for units pseudo-tied out of PJM.
D. Manual 28: Operating Agreement Accounting. Revisions developed to address FERC approval of Tariff changes related to a new day-ahead pseudo-tie transaction product for units that are pseudo-tied out of PJM.
Members will be asked to endorse draft Tariff language to remove an apparent overlapping credit reduction provision for qualified transmission upgrades, to clarify milestone documentation requirements for internally financed projects, and to clarify that capacity market sellers should submit requests for reductions.
Members will be asked to endorse the joint PJM-Independent Market Monitor package developed at the special Market Implementation Committee sessions related to transmission constraint penalty factors and draft Manual 11 and Manual 33 revisions, as well as Operating Agreement and Tariff language. (See “Transmission Constraint Relaxation Removed,” PJM Market Implementation Committee Briefs: Sept. 12, 2018.)
Members will be asked to endorse either of two proposals to better value summer-only demand response resources. One proposal was endorsed by the Summer-Only Demand Response Senior Task Force, and the other was developed by EnerNOC. (See Plan Would Reduce PJM Capacity Curve Through Peak Shaving.)
Members Committee
Consent Agenda (1:20-1:25)
Members will be asked to endorse proposed Tariff and OA revisions developed by the Governing Documents Enhancement & Clarification Subcommittee.
1. Opportunity Cost Calculator (1:25-1:45)
Members will review progress to date on PJM’s review and approval of the Monitor’s opportunity cost calculator and then be asked to approve proposed OA Schedule 2 revisions related to opportunity cost calculators. (See “PJM, Monitor Come to Agreement on Opportunity Cost Calculator,” PJM MRC/MC Briefs: Sept. 27, 2018.)
2. M15: Cost Development Manual Biannual Review (1:45-1:55)
Members will be asked to endorse draft revisions to Manual 15 developed through the required biannual review, which include addressing terminology inconsistencies and updating the Handy Whitman Escalation Index.
3. Market Seller Offer Cap Balancing Ratio Proposal (1:55-2:10)
Members will be asked to endorse proposed Tariff revisions that would change how PJM estimates the expected future balancing ratio used in the default market seller offer cap. The proposed method would take the average balancing ratios during the three delivery years that immediately precede the Base Residual Auction using actual balancing ratios calculated during RTO performance assessment intervals (PAIs) of the delivery years, along with estimated balancing ratios calculated during the intervals of the highest RTO peak loads that do not overlap a PAI for any preceding delivery year with less than 360 intervals (30 hours) of RTO PAIs. (See “Balancing Ratio,” PJM Market Implementation Committee Briefs: July 11, 2018.)
It’s a good bet the ongoing FERC paper hearing to revise PJM’s capacity construct will be a major topic of discussion at the annual meeting of the Organization of PJM States Inc. (OPSI) at the end of this month.
PJM CEO Andy Ott alluded to the looming debate last week in a letter to OPSI responding to the organization’s Sept. 26 correspondence on the issue. OPSI sent its letter to the Board of Managers just days before the first round of comments were due in the FERC docket. (See Little Common Ground in PJM Capacity Revamp Filings.)
FERC ordered the hearing June 29 after concluding that increasing state subsidies for renewable and nuclear power were suppressing capacity prices. The commission’s 3-2 ruling required PJM to expand the minimum offer price rule (MOPR) to cover all new and existing capacity receiving out-of-market payments, including renewable energy credits and zero-emission credits for nuclear plants. The MOPR currently covers only new gas-fired units.
The commission’s ruling rejected PJM’s April “jump ball” capacity filing (ER18-1314), granted in part a 2016 complaint led by Calpine (EL16-49) and initiated a Section 206 proceeding in a new docket (EL18-178). FERC also recommended creating an “FRR Alternative” allowing states to pull subsidized resources — and associated loads — from the capacity auction.
In its letter to PJM, OPSI contended “FERC erred in finding, absent evidentiary support, that PJM’s existing Tariff, the status quo, is unjust and unreasonable.”
In his response, Ott committed himself and other board members to “be available to discuss these matters with OPSI representatives” at the annual meeting, which begins Oct. 30 in Chicago.
He said PJM “understands the general concern” with accepting the RTO’s proposed resource carve-out (RCO) “before adequate resource compensation structures are established.” But he warned the organization that any alternative it suggests must be implemented by next year’s Base Residual Auction, which has been delayed until August.
“PJM is open to dialogue on this point but would urge OPSI to ensure that any OPSI proposal in this area reconcile these competing goals,” Ott wrote.
He said the alternative OPSI proposed in its letter to the board and supported in the Maryland Public Service Commission’s filing in the docket, a so-called competitive carve-out auction, requires that “critical implementation details must be developed before it may be implemented” and that “it is not expected these details can be resolved in time for the 2019 capacity auction.”
The New York Department of Public Service assured the Public Service Commission on Thursday that utilities are prepared for the upcoming winter and that customers’ bills will be on par with last year’s. But Commissioner Diane Burman was worried about possible outliers.
Every number Utility Supervisor Chris Stolicky and his panel presented, including the $800 winter bill customers should expect to see, was based on an “average winter.”
Burman was interested in knowing if the DPS had stress tested any of their numbers for an event like the winter of 2013/14, when a polar vortex posted record-low temperatures and drove energy prices far above projections.
“I am concerned, for one, because the Energy Information Administration predicts, nationally, to expect average household bills to rise because of a higher forecast in energy price[s],” Burman said.
Engineering Specialist Paul Darmetko said they had not done any stress testing, but that the chance of electric prices approaching those of the polar vortex winter were “slim-to-none” because of the hedging the utilities have taken.
“If the market price increases by 100%, the utilities have locked into hedges that are 70% of the portfolio, so the customers could really only see about 30% of any market price spike that does occur,” he said.
Cindy McCarran, the PSC’s deputy director for natural gas and water, said utilities’ hedging programs also act as an “insurance policy” against gas price increases.
“Prices may very well spike because of cold weather or something like that, but because our utilities buy a lot of fuel ahead of time [and] lock in the price … our firm natural gas customers are certainly not subject to those big spikes,” McCarran said.
Burman reminded the panel that stress testing became a topic after the 2013/14 winter. The DPS had acknowledged a need to dive deeper into the numbers, she said, but nothing has evolved since.
“We said [in 2014] that we need to look deeper. Check for scenarios in cold winters. Take most of the coldest winters and do stress test analysis.
“How many negative events are we prepared for? … We need to [do] further study and bring this discussion back.”
None of the other commissioners voiced similar concerns.
Stolicky did say earlier in the session that local distribution companies must prepare for “extreme days in normal winters,” and noted that last April was one of the coldest Aprils on record in New York.
