The Organization of MISO States (OMS) on Monday voted to lodge a protest in an ongoing dispute over whether states can prohibit energy efficiency resources from entering RTO markets.
OMS Executive Director Tanya Paslawski said the protest asks FERC to apply the same treatment to EE resources as it did to demand response in Order 719. It also affirms the authority of states to have final say in the matter.
The protest filing was approved by the OMS Board of Directors at a July 17 meeting held during the National Association of Regulatory Utility Commissioners Summer Policy Summit in San Diego.
FERC Order 719 required RTOs to accept bids from DR resources for certain ancillary services “on a basis comparable to other resources” and allowed aggregators to bid DR on behalf of retail customers directly into the market under certain circumstances.
OMS’s request stems from a recent disagreement between PJM and the Kentucky Public Service Commission. Citing the need to prevent expensive and unnecessary capacity purchases, the commission issued an order restricting EE resources from participating in PJM wholesale markets except in special cases. PJM staff responded by producing a problem statement contesting state regulators’ authority to restrict EE participation its capacity market. (See “EE Problem Statement Narrowly Approved,” PJM Market Implementation Committee Briefs.) National trade group Advanced Energy Economy petitioned FERC in June for a declaratory order, asking the commission to assert jurisdiction over the terms of EE participation in RTO/ISO markets (EL17-75).
Paslawski said that while FERC expressly left EE resources out of the order, OMS supports their market participation.
OMS members at the San Diego meeting agreed with the filing’s tone to uphold state jurisdiction. Commissioner Ken Anderson said the filing’s “thrust” on the jurisdiction of states was fitting.
MISO Asks OMS for DER Ideas
MISO Executive Director of Market Design Jeff Bladen appeared at the OMS meeting to inform state regulators that the RTO is beginning to work on developing market rules for distributed energy resources — and that he’d like input from the organization.
“Like all emerging issues, this is very much a work in progress,” Bladen said.
MISO seeks to create a common definition for DERs, rather than defining resources by technology type, the first step to developing future policy and planning processes, Bladen said. The RTO is currently running simulations with increased concentrations of DERs in hypothetical conditions to determine how it can create a more coordinated grid in which DERs do not stress transmission operations and real-time reliability conditions.
“We’re trying to test scenarios to see if we’re on the right track,” Bladen said.
Michigan Public Service Commission Chair Sally Talberg asked if MISO could carry out such simulations without communicating with generation owners.
“We’re essentially ignoring the method of dispatch” at this point in our studies, Bladen said.
Stakeholders will again take up DERs as their “hot topic” discussion item at MISO’s next full board meeting in September. Bladen said MISO will ask for stakeholder ideas on how to best integrate the resources.
“We see ourselves as just another collaborator on this rather than giving the answers.”
Avangrid earned $120 million in the second quarter, up 17% because of new rate plans in New York and Connecticut, improved cost management and a 4% increase in renewable energy production, the company reported Wednesday.
Avangrid CEO James P. Torgerson | Avangrid
The company attributed last quarter’s spike in renewable output to the recently completed 208-MW Amazon Wind Farm in North Carolina but said production at its other wind facilities came in below average. Avangrid plans to sign power purchase agreements equating to 1,800 MW of new wind and solar through 2020.
“We’ve already secured 1,000 MW of that — or 55%,” CEO James P. Torgerson told investors and analysts during an earnings call.
Avangrid controlled more than 6,000 MW of renewable resources by the end of June, 349 MW of which was added this year. Another 600 MW is slated to come online during the second half of 2017, with wind representing 534 MW and solar making up the remainder.
Renewables Rising
The company manages two primary lines of business: Avangrid Networks comprises eight electric and natural gas utilities serving around 3.2 million customers in New York and New England, while Avangrid Renewables operates more than 6 GW of mostly wind power in 23 U.S. states.
Avangrid Renewables Pipeline | Avangrid
Avangrid is this year focusing on reducing its exposure to wholesale markets by decreasing its merchant capacity from 35% to 27%.
“Year-to-date, we’ve executed 589 MW of fixed-price contracts to reduce our merchant capacity, and we’re really committed to keeping on track and adding even more as we see opportunities,” Torgerson said. “The company targets to be at 75 to 85% PPA plus hedges that we have on merchant capacity, so by adding the long-term hedges, we will actually be over 80%.”
The Networks business continues to dominate the company, contributing 73% of overall adjusted net income year-to-date, up 9% over the same period last year. But the Renewables division is playing catch-up, seeing its adjusted net income rise 26% for the same period.
Offshore wind platform | Avangrid
The company sees clean energy and offshore wind initiatives in Massachusetts as “key opportunities” to increase income beyond its long-term plan, Torgerson said.
Avangrid plans to bid “multiple transmission and/or renewable solutions” into a collaborative effort by the Massachusetts Department of Energy Resources, Eversource Energy, National Grid and Unitil to solicit clean energy proposals for 9.45 TWh annually of renewable generation.
“They’re looking for incremental hydro on a firm basis, but also new Class I renewable portfolio standard [resources], which would be wind and solar,” Torgerson said. “A combination of both could include transmission projects under a FERC tariff.”
Massachusetts is also soliciting up to 1,600 MW of offshore wind proposals due in December, and Avangrid intends to bid into that in partnership with Copenhagen Infrastructure Partners, Torgerson said. The projects will be selected in April 2018.
NYPSC Quorum Commended
Torgerson lauded the recent appointment of a new chair and two additional commissioners to the New York Public Service Commission, which operated for several months with only two of five seats filled, causing a backlog.
As part of New York State’s Reforming the Energy Vision initiative, Avangrid subsidiaries New York State Electric and Gas and Rochester Gas & Electric have filed a combined proposal with the commission to launch an Energy Smart Community project. The two utilities have already installed 20,000 smart meters under the program.
Quorum Pending at FERC
Avangrid could stand to benefit — or not — from the restoration of FERC’s quorum. The D.C. Circuit Court of Appeals (15-1118) in April overturned FERC’s 2014 order setting the base return on equity for a group of New England transmission owners — including Avangrid’s Central Maine Power — at 10.57%. The court ruled that the commission failed to meet its burden of proof in finding the existing 11.14% rate to be unjust and unreasonable. (See Court Rejects FERC ROE Order for New England.) The TOs are seeking to begin billing at the prior ROE.
“That is the most recent rate that’s legally in effect at this point, and we requested to begin billing that again 60 days after FERC has a quorum, with retroactive billing to June 8 of this year,” Torgerson said. “If no FERC decision is reached, we’ll start doing that.”
FERC has lacked the necessary three-person quorum since the February departure of former Chair Norman Bay, and has been down to one commissioner — acting Chair Cheryl LaFleur — since Colette Honorable left last month.
LaFleur may be joined by four new members if Democrat Richard Glick and Republicans Kevin McIntyre, Robert Powelson and Neil Chatterjee win Senate confirmation. (See Trump Names Energy Lawyer McIntyre as FERC Chair.) Glick is a former vice president of government affairs for Avangrid.
Stakeholders got a first look at the preliminary projects resulting from MISO’s yearly market congestion planning study during the July 19 PAC meeting. The RTO has so far floated three potential projects in the West of the Atchafalaya Basin (WOTAB) area straddling Texas and Louisiana:
A new $137.6 million 500-kV line and substation expansion from Hartburg to Sabine in southeastern Texas that would qualify as a market efficiency project and is expected to be in service by 2023.
A $2.8 million replacement of 26 transmission structures along the Sam Rayburn-Fork Creek-Doucette 138-kV line in southeastern Texas, expected to be complete by 2020.
Equipment upgrades valued at $500,000 for the existing Carlyss substation in southwestern Louisiana by 2020.
Arash Ghodsian, MISO manager of economic studies, said the RTO’s market congestion planning footprint diversity studies will produce final project recommendations in August. Project candidates will be submitted for approval by the Board of Directors at the end of the year. (See “Studies Could Assist in Relieving North-South Constraint,” MISO Planning Advisory Committee Briefs.)
| MISO
MTEP Siting Up for Review
MISO is also planning on updating siting guidelines for projects included in its Transmission Expansion Plan.
This year’s siting model will be slightly altered to add likely wind and solar zones. MISO will also consider zonal resource adequacy requirements when determining siting and exclude thermal unit development from non-attainment areas subject the National Ambient Air Quality Standards.
The RTO plans to further improve its siting modeling process for the 2019 cycle through a series of stakeholder workshops that will begin in September. Matt Ellis, a MISO policy studies engineer, said the overhaul will focus on the placement of new technology, including 100 MW of queued energy storage resources, future utility-scale renewables, rooftop solar — predicted to reach 10 GW by 2027 — and the addition of more electric vehicles and their demands on load.
Ellis said projects in the interconnection queue generally exhaust themselves within a three- to five-year cycle, but MISO plans for its transmission system 15 years into the future.
He also asked for stakeholders to submit ideas by Aug. 11 on how MISO’s siting process can account for new technology.
MISO will also conduct a multi-value project triennial review this year, sizing up its existing portfolio and quantifying benefits. FERC requires a full review of the approved portfolio benefit every three years.
Project manager David Lucian said the review will have no effect on cost allocation for existing projects, but findings could be used to adjust project criteria in future projects. The review includes analyses of economic benefits, generator flexibility, renewable target standards, natural gas risks and job creation.
MISO last conducted an MVP triennial review in 2014, concluding that the portfolio held a benefit-to-cost ratio ranging from 2.6 to 3.9 and should create anywhere from $13.1 billion to $49.6 billion in net benefits over the next 20 to 40 years.
The triennial review report will be filed with FERC by the end of the year, PAC Chair Cynthia Crane said. Results will also be published in the MTEP 17 report due in December.
SAN DIEGO — New electricity business and regulatory models will be needed in the U.S. to transition to a future with more distributed and renewable resources, changing customer needs and new technologies, market participants and regulators said this week.
Industry representatives and state regulators gave an overview of the changing landscape at the National Association of Regulatory Utility Commissioners Summer Policy Summit. Common themes were the growth of distributed resources, managing large amounts of new renewables and developing fresh approaches as more electricity consumers also become producers.
Pacific Gas and Electric CEO Geisha Williams said that the key is to implement renewables, distributed generation and other new technologies “and not leave anybody behind.” About 40% of the utility’s customers are low-income, and they should not have to choose between paying for electricity and other critical expenses such as health care, she said.
The model of billing energy consumers purely based on the amount of electricity they use is becoming obsolete, Williams said. “That model is fundamentally at risk at this point.”
Many electric consumers are also producers, as behind-the-meter and distributed resources grow. Retail energy sales in the future “may very well likely not be a one-size-fits-all,” she said, similar to how mobile phone users have different data plans because they have widely different needs. This could entail using a tiered approach, service and access charges and new incentives for capital investment.
It is important that regulators and lawmakers put the right policies in place to implement new technologies and practices in an affordable way, Williams said, adding that “affordability is a strategic imperative to us.”
The country’s generation and distribution systems “are really undergoing a period of very dramatic change,” Nuclear Energy Institute CEO Maria Korsnick said. She contended that nuclear, particularly small modular reactors, should play a role in maintaining clean and affordable energy.
“Small modular reactors could be game-changers in many respects,” Korsnick said, providing smaller increments of power compared with a large central station plant and giving utilities more discretion in meeting demand. Modular reactors can also bring off-grid power to remote places and cycle up and down like a natural gas plant — but with no emissions.
In Pennsylvania, distributed resources are “popping up as a result of new opportunities,” Public Utility Commissioner John Coleman said. The agricultural sector is learning that biodigesters can help manage waste products while producing electricity. The question is to how to compensate these new resources.
As for the traditional ratemaking model: “Maybe it is at risk,” Coleman said. “Maybe it is time to start thinking of some of these things in a different way.”
The Pennsylvania PUC is surveying industry on new compensation approaches and ways to incentivize investment. He noted that the majority of the state’s consumers are served by competitive suppliers and electricity rates have dropped by about 30%. Natural gas plants are also rapidly replacing coal-fired units in the state.
Other than distributed resources, utility-scale generation is also changing, according to Ohio Public Utilities Commissioner Beth Trombold. The state has a potential 8,000 MW of new gas-fired generation coming online, with four gas plants under construction, one certified and four more under review. There is about 1,200 MW of new wind and 400 MW of new solar waiting in the wings, which will greatly increase the amount of renewables in the state.
Ohio is also in the middle of a grid modernization program and asking, “What kind of regulations and technological innovation are out there to enhance the customer-utility relationship?” Trombold said.
California Public Utilities Commission Chairman Michael Picker said that integrating renewables in the state has not been as challenging as was feared, and it is now more important to consider where they are placed.
Legislation is in the works in California to achieve a zero-carbon electricity grid by 2045 and the state recently extended its cap-and-trade program to 2030. (See California Lawmakers Extend Cap-and-Trade.)
“At this point, it’s not about getting more, it’s what you get, where you get it … and when it’s available,” Picker said of renewable generation. The state is experiencing lower electricity demand overall but higher peaks. The PUC is moving away from “silos” in terms of what kind of resources are put on the grid, but back to an integrated resource plan model, he said.
In terms of reducing greenhouse gases, more of the transportation sector must be electrified, he said. The transportation sector emits 40% of GHG in the state; gas for heating and other uses emit about 30%, while just 20% is emitted from the electricity generation.
CAISO will lean heavily on increased output from conventional generators — and a backstop of regulation reserves — to fill the void left by reduced energy production from California solar resources during next month’s solar eclipse.
The grid operator estimates that about 4,194 MW of utility-scale solar will fall off the system from the time the moon begins to pass in front of the sun (9 a.m.) to the moment of peak obscuration (10:22 a.m.) during the Aug. 21 event.
Graph shows a comparison between CAISO’s Aug. 21 eclipse load forecast compared with that for full-sun conditions. | CAISO
At the peak, grid-connected solar generation will come up about 5,600 MW short of what would be expected under full-sun conditions. Net load will surge to about 6,000 MW above normal because of diminished output from rooftop installations.
But the grid operator has been preparing its response since last year. (See With Solar Eclipse Looming, CAISO Weighs its Options.) After a winter of ample precipitation, “large and fast-moving” hydroelectric resources are being positioned for rapid response during both the loss and return of solar, according to Deane Lyon, a CAISO real-time operations shift manager.
Planners are also banking on gas-fired generators to help cover the gap.
“We’re actually working with Pacific Gas and Electric and [Southern California Gas] and coordinating with their gas control centers because, besides the hydro, the gas-fired thermal is going to have to make up for a lot of the loss of solar generation,” Lyon said Tuesday during a bimonthly Market Performance and Planning Forum.
The ISO will also procure about 900 to 1,200 MW of regulation up reserves for the three-hour period affected by the eclipse — compared with a typical procurement of 300 to 400 MW.
“That’ll help us manage as the solar goes away,” Lyon said.
Lyon noted that CAISO has been consulting with Western Energy Imbalance Market (EIM) participants to develop a “consistent policy” regarding transfer service requests (ETSRs) — or dynamic transfers across balancing areas — during the eclipse so that the ISO can take advantage of imports to the greatest extent possible.
“We got commitments from the operations folks at the EIM entities that they’re willing to keep the ETSRs wide open and fully operational for the balance of the eclipse,” Lyon said, acknowledging that the ISO does not expect a “huge” uptick in transfers given that Arizona Public Service and NV Energy will also be losing solar off their systems at about the same time.
On the flip side, the eclipse is not expected to actually undercut imports.
“APS has solar, but not PacifiCorp,” Lyon said. “We don’t expect it will have that big of an effect.”
Paula Lipka, of PG&E’s short-term electricity supply team, asked if the ISO intends to increase its procurement of flexible ramping and spinning reserves — as well as regulation.
“An increase in flex ramp procurement is being considered. As far as spinning and non-spinning reserves, we will have adequate amounts of that,” Lyon responded.
Regulation reserves are the ISO’s key concern.
“We’re trying to maintain our system balance for the duration of the sun going away and returning, which is going to be a pretty big challenge,” Lyon said.
SPP is accepting applications from industry experts to serve on an independent panel reviewing the RTO’s 2018 competitive transmission construction proposals.
The panel will review, rank and score proposals for competitive projects under FERC Order 1000. The previous two panels recommended one such project — a 22.6-mile, 115-kV line from Walkemeyer to North Liberal in southwest Kansas. However, the project was withdrawn because of decreased load projections. (See SPP Cancels First Competitive Tx Project, Citing Falling Demand Projections.)
| Westar
Interested candidates must have expertise in at least one of the following transmission-related areas:
Engineering design;
Project management and construction;
Operations;
Rate design and analysis; or
Finance.
SPP will accept applications through Sept. 1 and choose panelists later this year based on recommendations by the RTO’s Oversight Committee, which must be approved by the Board of Directors. Selected panelists will be considered contractors and will be compensated through a monthly retainer and hourly rate.
Panelist applications, instructions and more information can be found on SPP’s website or by contacting Ben Bright, the RTO’s regulatory processes manager.
MISO has introduced a three-step checklist that owners of behind-the-meter (BTM) generation can use to prove deliverability for the Planning Resource Auction, but some stakeholders are calling foul on the differing auction requirements.
The three-pronged approach will involve different sign-offs from affected load-serving entities, transmission owners and MISO. The LSE will determine whether the BTM customer can participate in the wholesale or retail market, while the TO will ascertain study requirements for access to the transmission system when the BTM generator interconnects to a non-transferred facility. The RTO will determine the resource’s deliverability or transmission service procurement in order to use the transmission system.
| MISO
“This is meant to provide some guidance on the more intricate relationship between LSEs and TOs,” MISO Manager of Resource Adequacy John Harmon said during a July 12 Resource Adequacy Subcommittee meeting. “MISO is not looking to gain new authority in this endeavor; we’re trying to stay within the bounds of our Tariff.”
Since the beginning of the year, MISO staff have been grappling with deliverability rules that would allow BTM generation in excess of a utility’s planning reserve margin requirement — but without existing transmission service — to enter the annual capacity auction. The RTO last month proposed requiring that a BTM resource submit to an optional engineering study to identify a deliverable volume of capacity eligible to be bid into a single auction. However, the study would have only temporary value. The resource would then be required to enter the same volume into the interconnection queue study process before offering capacity into any subsequent auctions. (See MISO Proposes Deliverability Rules for Behind-the-Meter Capacity.)
Harmon said MISO is proposing to adopt the optional study avenue for two planning years until June 1, 2019. After that, resource owners will have to enter the interconnection queue.
Deliverability amounts discovered in the optional study will have a “limited applicability” and will not be used to determine deliverability in the interconnection queue process, Harmon said.
Indianapolis Power and Light’s Lin Franks asked why BTM generation should essentially be treated as “free riders” on the grid, and not supported by utility aggregators.
“I don’t know of any place where behind-the-meter generation [has] paid for transmission service. They’ve paid nothing whatsoever for access to the Bulk Electric System,” Franks said. “There are some holes.”
Harmon said BTM will only have access on an as-available basis, and that the proposal is an “interim solution” to ushering BTM generation into a more formal interconnection process.
Dynegy’s Mark Volpe asked if MISO was proposing a go-around to the rules that every other capacity resource has to abide by.
“You’ve got a gigantic comparability issue here,” Volpe said.
| MISO
Harmon pointed out that before this year, excess BTM generation was delivered undetected. “We think there’s good cause for a transition period,” Harmon said. He also added that the proposal might not be “100%” yet, but that MISO and stakeholders are striving toward the same goal.
He asked for additional stakeholder feedback on the deliverability proposal by July 26.
PRA Qualification Deferral to Become a Reality
MISO will file Tariff changes this fall to give certain capacity resources the option for additional time to qualify for the PRA.
The deferral will also be spelled out in the Business Practices Manuals and will allow certain resources to postpone completion of generator verification tests or installed capacity value calculations until after the auction. Capacity resource owners that intend to defer must inform the RTO before Feb. 15 and complete a generator verification test no later than May 31 in order to participate in the upcoming planning year.
MISO uses the verification test to determine the total capacity that a planning resource can reliably provide based on performance and availability data for summer peak conditions.
The draft BPM language states that the deferral is for untested new planning resources, existing resources “returning to operation from a catastrophic outage or suspension,” resources in the midst of increasing capability, suspended resources and resources “awaiting other miscellaneous resource approvals to achieve commercial operation.”
Analyst Scott Thompson said deferrals could also be used by intermittent capacity resources that have yet to come online at the time of the auction or generators that are completing environmental upgrades that prevent operation.
Most load-modifying resources called up for the first time in a decade during MISO’s April 4 maximum generation event failed to respond properly to scheduling instructions, officials said last week.
MISO Manager of Resource Adequacy John Harmon said 19 LMRs — demand resources and behind-the-meter generation that provide capacity — responded to meet a maximum scheduling instruction of 715 MW during the emergency in MISO South. Four LMRs failed respond at all and will face penalties under Module E of the RTO’s Tariff.
Harmon said the underperformance by some LMRs was offset by the larger-than-expected load reductions by others. The RTO was short about 25 MW of scheduling instructions in the last hour of the emergency declaration.
He stressed the importance of LMR owners providing accurate load curtailment capability to MISO every day. “It’s important that LMRs update their availability daily in the MISO communication system. Our operators rely on these each day and … are banking on the numbers when the need could arise to shed firm load,” Harmon said at a July 13 Market Subcommittee meeting.
LMRs are only required to be available for emergencies during the summer peak season and do not have to be available during non-summer months. However, the plants must notify MISO when they are unavailable through the RTO’s communication system.
In May, the RTO promised to conduct a performance evaluation of the LMRs during the event. (See “Several Factors in Spring MISO South Maximum Generation Event,” MISO Market Subcommittee Briefs.)
April 4, 2017 Max Gen Event Conditions | MISO
MISO has calculated a total penalty of about $2,000 for the four LMRs that failed to respond. The revenue from the penalties will be allocated to all market participants with load in the Entergy Arkansas local balancing authority, and on a market load ratio share basis to the Entergy New Orleans, Louisiana, Texas and Mississippi LBAs.
The RTO will assess and begin to distribute penalties this week. The generators could avoid punishment if they can identify force majeure reasons that prevented them from responding.
Harmon said MISO will review its approach to training and operations drills to improve LMR performance. It also will review its current process and Tariff to make sure LMRs are “incentivized to update availability each operating day,” he said.
“We saw a lower rate of LMRs being able to meet the load reduction that they said they could meet. That suggests to us that market participants can tighten up the precision of the information that they provide to MISO on a daily basis,” Harmon said.
Executive Director of Market Design Jeff Bladen said there might be a disconnect between what market participants can provide in load curtailment and MISO’s scheduling instructions.
“The issue is when someone tells us that they can drop from 100 MW to 10 MW, and they’re operating at 70 MW and drop to 10 MW, that’s not a 90-MW drop; that’s a 60-MW drop. Whether there’s a penalty or not, we want to operate reliably. It’s not a question of right or wrong, it’s a question of can we operate reliably,” Bladen said.
The April 4 event was driven by unseasonably high temperatures and an unusually high amount of transmission and generation outages in MISO South. It prompted the Independent Market Monitor to call for greater MISO authority in approving maintenance outages. (See MISO South Outages Worry RTO, Monitor.)
VALLEY FORGE, Pa. — PJM last week presented Operating Committee members with a proposed pro forma agreement for dynamic schedules, saying it would eliminate potential confusion and improve reliability.
Dynamic schedules are power flows into the RTO from a generator that is controlled by and located in a different grid operator’s territory. Unlike pseudo-tied units, the flows are not modeled in PJM’s systems as internal supply.
Because PJM lacks a standard agreement for dynamic schedules, individual agreements may contain variations in language that can result in incorrect operating procedures, the RTO said.
Under PJM’s proposal, the native balancing authority would only need to acknowledge awareness of the agreement because it remains operationally responsible for the resource. Unlike pseudo-ties, dynamic schedules require tagging and are subject to curtailment under NERC’s transmission loading relief procedures, PJM’s Phil D’Antonio said.
D’Antonio said PJM hadn’t yet decided whether they would seek to make the agreement retroactively enforceable for existing schedules. The agreement will be brought to a vote at next month’s OC meeting.
PJM’s Jacqui Hugee gave the OC an update on additional Joint Operating Agreement revisionsMISO has requested relating to the pro forma pseudo-tie agreement. “For the most part, the changes are to clarify the language that is there,” she said. (See Late Agreement with MISO Forces Another Delay on Pseudo-Ties.)
Stakeholders voiced concerns about the language, but Hugee explained that PJM does not need, nor will it seek, stakeholder endorsement for the changes.
SCED Changes Implemented
PJM on Monday transitioned from a 15-minute to a 10-minute “look ahead” on its security-constrained economic dispatch (SCED) engine. The changes went into effect at 9 a.m.
PJM’s Joe Ciabattoni said the RTO will review the system’s performance after a week to ensure there are no reliability issues and evaluate whether to retain the changes. Ciabattoni said PJM does not need stakeholder approval to make the changes.
“We’re trying to better align real-time reserve levels with reserves calculated and dispatched by SCED,” he said. “Historically, we started with a 22-minute look ahead and have moved it over time to 15 minutes.”
Resilience Planning Moves Forward
PJM’s Jonathon Monken reviewed the RTO’s ongoing development of system resilience, noting that communication has expanded with related industries such as natural gas distributors. (See “Bryson Leads on Next Steps for Fuel Resiliency,” PJM OC Briefs.)
“I would expect that this will drive a lot of exercises and drills, recognizing that when we identify a vulnerability, we would much prefer to test it in an exercise environment than experience it in real life,” said Monken, senior director of systems resilience and strategic coordination.
He said that PJM is developing both internal and external roadmaps for enhancing resilience to severe weather, physical or cyber attacks or disruptions in fuel supplies. He also reviewed PJM’s Resilience Steering Committee, which includes himself and 14 other PJM staffers with responsibilities for various aspects of the plan.
John Farber of the Delaware Public Service Commission questioned using resilience as a driver for approving projects in the Regional Transmission Expansion Plan. While it was not listed on the current version of the external roadmap he presented, Monken confirmed that it is still a focus.
Farber warned that evaluation of resilience in RTEP projects wouldn’t be “as straightforward as described” and said completing quantifiable metrics by the end of 2018 is an aggressive timeline. “I would just note that the last time that PJM addressed drivers in the RTEP process … that took two and a half years. And those were, in my view anyway, difficult years,” he said.
“We certainly recognize the fact that we’re certainly not going to go faster than what the stakeholders would like it to go,” Monken said.
Ramp Rate Changes
PJM’s Cheryl Mae Velasco highlighted enhancements to its Markets Gateway online tool that will allow generators to adjust their regulation offers throughout the day instead of just once daily.
“The [web-coding] vendor had a chance to put them in,” Velasco said. “They’ve been on the backlog for quite a while.”
The announcement was met with appreciation, but also a request.
“These are items that could provide optionality in how we operate units, so to hear about it in the Operating Committee a week before [implementation] is, for me at least, problematic,” American Electric Power’s Brock Ondayko said. He asked that similar changes be brought to stakeholders’ attention “preferably” two or three months in advance.
“Once we found out [that the vendor had made the updates], we sent the communications out as soon as possible,” Velasco responded.
PJM’s Ken Seiler acknowledged Ondayko’s concern and said he would work with the RTO’s Tech Change Forum to provide earlier notice in the future.
Ciabattoni said that generators making changes to their ramp rates will not require corresponding price points in their cost-based offers.
PJM estimates a loss of up to 2,500 MW in solar output during the solar eclipse that will occur on Aug. 21. The event is expected to last about an hour.
While grid-connected and behind-the-meter systems will be impacted the same, the difference in deployed amounts means that grid-connected output is expected to drop about 500 MW, while BTM resources could drop about 2,000 MW. PJM expects it will need to increase non-solar generation by about 1,000 MW if it’s an overcast day and up to 2,500 MW if it’s sunny. Coordination will be important during the ramp up and ramp down periods.
PJM’s Joe Mulhern said the eclipse is expected in the middle of the afternoon when the sun is high and solar generation is near its peak output. If it’s a hot day, load will no doubt be near its peak as well, he said. However, a NERC analysis showed no reliability impacts are expected for the Bulk Power System.
PJM’s Glen Boyle announced that the Primary Frequency Response Senior Task Force will have its first meeting at 9 a.m. July 25, with monthly meetings to follow for at least six months. (See “PJM Defends Interest in Paying for Frequency Response,” PJM Markets and Reliability Committee Briefs.)
VALLEY FORGE, Pa. — PJM’s Lisa Morelli presented the Market Implementation Committee last week with revisions to the RTO’s proposal for handling intraday hourly offers in the energy market, delaying a scheduled vote on the plan.
The changes made to Manual 11: Energy & Ancillary Services since the first read on the proposal included a clarification that PJM’s real-time security constrained economic dispatch (SCED) uses data that are effective for the look-ahead solution interval rather than the case execution time. In response to feedback from the Independent Market Monitor, it also clarifies that a generator’s intraday opt-out election must be consistent with its fuel-cost policy.
“Resources should not be able to circumvent [market power] mitigation just by changing the relative levels of price versus cost,” Josyula said.
Luna focused on how generators can elect to opt out of intraday offers. PJM’s rules require that if generators change their price-based offer, they must also change their cost-based offer, he explained. “It’ll be easier for anyone who has a fuel-cost policy to say, ‘If I don’t have it in there, my default is to opt out,’” he said. “If no one changes their fuel-cost policies to incorporate hourly offers, it’s not clear how they can be compliant with the rule that has been presented because [hourly offers] can change your cost-based offer.”
It’s unclear whether the Monitor’s differences will result in separate proposals.
“It might be separate. We’re not completely there yet to say … they are, in fact, two different things. That might be where we end up in another round of conversations,” said PJM’s Chantal Hendrzak, who chairs the MIC.
Morelli also announced that all generators, no matter if they plan to update schedules hourly or not, will need to update their schedule IDs to PJM’s new list by Nov. 1. The RTO will be posting a step-by-step guide in its Markets Gateway online tool. With the implementation of intraday offers, PJM will only accept cost-based schedules 1-9, eliminating 70 others. The number of price-based schedules is being reduced from 19 to two.
PJM Indifferent on Black Start Fuel Compensation
Before presenting proposals from Calpine and the Monitor on calculating fuel-storage compensation for black start units, PJM’s Tom Hauske made it clear the RTO is agnostic to the voting results. He was repeatedly asked for PJM’s position, and he repeatedly declined to take one. (See “Started from the Bottom, Now We’re at the MTSL,” PJM Market Implementation Committee Briefs.)
“What we’ve taken as a position is that we can live with any of the three,” he said, including the status quo among the options.
The Monitor’s proposal would calculate the unit’s compensation for fuel storage — known as minimum tank suction level (MTSL) — based on the ratio of the fuel tank’s total volume to the amount of fuel needed to fulfill the black start requirements of 16 hours of continuous operation. The proposal from Calpine’s David “Scarp” Scarpignato would compensate units based on the average annual fuel volume in the tank.
Scarp and Monitor Joe Bowring sparred for a while on the merits of Scarp’s proposal. Bowring asked why “black start should pay an even bigger piece based on whatever random amount of oil is in the tank.” PJM currently pays about $500,000 per year in compensation for black start fuel storage based on current rules that pay for the entire tank. So either proposal would reduce the costs, the sponsors say.
The conversation between Scarp and Bowring eventually devolved into a fast-food metaphor focused on how much frying oil a restaurant would need to switch menu options. At the end, Scarp asked for clarification on whether his proposal would be set for a vote as an alternative to the Monitor’s proposal. When that was confirmed, he explained that he only meant for his proposal to spur discussion and asked that it be removed.
The vote at next month’s meeting will be on the Monitor’s proposal versus the status quo. Greg Poulos, executive director of the Consumer Advocates of the PJM States, announced his membership is leaning toward the Monitor’s proposal.
Energy Efficiency Kicked to Demand Response Subcommittee
PJM staff canceled plans to begin discussions in the MIC regarding rules for energy-efficiency products entering into the capacity market after stakeholders said they could resolve the issues more quickly through the Demand Response Subcommittee first. (See “EE Problem Statement Narrowly Approved,” PJM Market Implementation Committee Briefs.)
CPower’s Bruce Campbell pushed back on the change of venue, saying it will be difficult for the subcommittee to cover DR, the energy efficiency rules and how to address the impact of state policy initiatives on the markets.
PJM’s Pete Langbein warned that the four- to six-month timeline for results indicated in the energy-efficiency issue charge is “very aggressive.”
IMM Presents Problem Statements on Transmission
Bowring presented two problem statements and issue charges related to transmission concerns on first reading. The first problem statement and issue charge focuses on transmission penalty factors, for which he said PJM has no rules.
In its dispatch model, PJM allows transmission constraints to be violated under some conditions. The violated constraints have defined penalty factors that affect LMPs to reflect the local scarcity. Bowring says the penalty factor for a violated constraint should equal the shadow price — the incremental reduction in congestion cost achieved by relieving a constraint by 1 MW. PJM, however, uses “constraint relaxation logic” to affect the shadow prices, typically causing the shadow price to be slightly below the penalty factor, Bowring says.
Other grid operators, such as MISO, have explicit rules on the topic, he said.
In a presentation on the issue at the Members Committee webinar last September, Bowring recommended that PJM explicitly state its policy on the use of transmission penalty factors: the level of the penalty factors; the line ratings to trigger their use; the allowed duration of a violation; and when the penalty factors will be used to set the shadow price.
In asking you to approve this problem statement, I’m not asking you to agree with my characterization,” he told the MIC on Wednesday. “There are no rules. It should be written down. … I don’t know how long it’s been occurring at PJM — probably since the beginning.”
Morelli said PJM is in favor of the problem statement. “In addition to adding some consistency to how some of this works, it’s also taking a look at constraint reorganization where, essentially, we don’t allow the penalty factors to set price,” she said.
The second problem statement and issue charge focuses on pricing point alignment for cross-border transactions. The current procedure allows for “scheduling energy inconsistent with power flows” that “creates harmful market inefficiencies,” according to the problem statement.
“Our underlying principle is that pricing should be consistent with physical power flows — a radical concept, I know, but it’s not currently being implemented,” Bowring said.
