Next week’s total solar eclipse will not disrupt SPP operations despite 100% obscuration levels in parts of its 14-state footprint, according to a report by RTO staff.
The eclipse will pass over North America on Monday, with parts of Nebraska, Kansas and Missouri experiencing totality — complete obscuration of the sun — for almost three minutes. Kansas City and Lincoln, Neb., are among the municipalities in the totality path. Other states in the SPP region will experience solar obscuration levels of 80% or more.
| GreatAmericanEclipse.com via SPP
“The eclipse is expected to have some impact on resources and loads in our region,” said Lanny Nickell, SPP’s vice president of engineering.
The RTO expects to lose about 200 MW of solar PV generation during the height of the eclipse, assuming clear skies. The system currently has 215 MW of registered utility solar resources; SPP has identified another 111 MW of distributed PV on its system, including residential rooftop solar and commercial solar farms.
The eclipse will pass over the SPP footprint for about three hours, beginning at the western edge around 11:30 a.m. CT and ending at the eastern edge around 2:45 p.m.
| SPP
Although solar generation will be reduced, the eclipse also will reduce air conditioning loads because of falling temperatures. But the temperature drop also will cut wind speeds, reducing wind generation, according to the report, which was prepared by a summer engineering intern. A drop in solar generation connected to the distribution system will appear as an increase in load from the transmission system’s perspective.
The report expects demand for lighting will increase during the eclipse, which would require additional generation.
“The eclipse is worthy of study in light of the increasing numbers of distributed generators in the SPP footprint,” the report said.
That study could come in handy in 2024, when another solar eclipse will cover Texas and Arkansas on its way to the Northeast. The National Renewable Energy Laboratory (NREL) projects the SPP region may have up to 1.1 GW of distributed PV in at that time.
Utility-scale solar is also likely to increase, given more than 7 GW of solar generation is being studied in the generator interconnection queue.
Ohio regulators on Wednesday rejected challenges to their order awarding FirstEnergy a subsidy worth more than $600 million, assistance the company said it needed to avoid having its credit rating reduced below investment grade.
The Public Utilities Commission of Ohio also rejected some rehearing requests by FirstEnergy while also granting others (14-1297-EL-SSO).
Opponents of the rider immediately vowed to appeal to the state Supreme Court.
In October, the commission unanimously rejected FirstEnergy’s request for an eight-year retail rate stability (RRS) rider totaling $4.46 billion, which the company said it needed to ensure its financial health at a time in which its coal- and nuclear-fueled generation is challenged by low natural gas prices.
Instead, the commission approved a three-year distribution modernization rider (DMR) totaling about $612 million for subsidiaries Ohio Edison, Cleveland Electric Illuminating and Toledo Edison. The commission said the additional money would allow the company to make investments in grid modernization. (See PUCO Rejects FirstEnergy’s $558M Rider, OKs $132.5M.)
Ohio Edison workers in a switchyard | FirstEnergy
In December, the commission agreed to consider FirstEnergy’s rehearing request, along with challenges by environmentalists, independent power producers, large customers and the Ohio Consumers Counsel (OCC).
In its unanimous ruling Wednesday, the commission said that it had already “thoroughly addressed” issues raised by OCC, the Northwest Ohio Aggregation Coalition, Cleveland Municipal School District and the Sierra Club. Commissioner Lawrence K. Friedeman recused himself.
It said the risk of FirstEnergy’s and its subsidiaries’ credit ratings dropping to below investment grade was “sufficient to constitute an emergency that threatens the utility’s financial integrity,” rejecting opponents’ claim that it should rely on the current credit ratings of the companies.
The commission also approved FirstEnergy’s request to strike portions of filings by the Ohio Manufacturers’ Association Energy Group, saying “new information should not be introduced after the closure of the record.” It also struck news articles included in filings by the Northeast Ohio Public Energy Council, which it said were hearsay.
In response to a request from FirstEnergy, it clarified its earlier ruling, saying that if Electric Security Plan (ESP) IV is terminated, the Rider Delivery Capital Recovery (DCR) revenue cap increases currently in place will continue until the commission establishes a new standard service offer (SSO). “If FirstEnergy exercises its right to terminate ESP IV at some point in the future following rehearing or an appeal, the Rider DCR revenue cap increases yet to be implemented at the time of termination will also be terminated along with the remaining provisions of ESP IV. However, FirstEnergy will be permitted to continue to recover costs already incurred under Rider DCR,” it said.
PUCO said it was “not persuaded by FirstEnergy’s assertion that DMR revenue could be recovered through a base distribution rate case. We do agree that certain costs of grid modernization, specifically the costs of any acquisition and deployment of advanced metering, including the costs of any meters prematurely retired as a result of the advanced metering implementation, may be recovered outside of an ESP [electric security plan]. Moreover, we also agree that the $568 million annual economic impact of the retention of the FirstEnergy Corp. headquarters is an economic benefit under the ESP and should be included as a consideration in the ESP versus MRO [market rate offer] test.”
Opponents of the rider reacted sharply, saying they will take their arguments to the Ohio Supreme Court.
“There is simply no basis in Ohio law to force utility customers to pay for a slush fund for FirstEnergy Corp. and its shareholders,” said Shannon Fisk, managing attorney at Earthjustice.
“We are very disappointed in the commission’s continued unwillingness to shield customers from FirstEnergy’s poor business decisions,” said Dan Sawmiller, senior representative for Sierra Club’s Beyond Coal Campaign. “The PUCO has missed yet another opportunity to focus the company on real efforts to modernize our electric grid and invest in new, clean energy technologies and instead has forced customers to pay up for unwise investments in outdated coal and nuclear plants.”
The Environmental Defense Fund said it was “confident the Ohio Supreme Court will … reject the regulators’ latest giveaway to dirty energy.”
FirstEnergy spokesman Doug Colafella said the ruling “affirmed the commission’s previous order that will help support future investments to modernize our electric system.”
“Grid modernization will benefit our customers and competitive suppliers by enhancing service reliability and enabling new products and services,” he said.
NEW YORK — While timelines for completing large power projects can be especially long in New York, developers are finding it easier to invest here now that the state is providing more predictability around clean energy procurement and market fundamentals.
That was the consensus of panelists discussing the impact of the state’s Clean Energy Standard (CES) on procurement at the Infocast New York Energy REVolution Summit held earlier this month at Times Square.
Gov. Andrew Cuomo’s Reforming the Energy Vision (REV) and its associated CES aim to meet two goals by 2030: a reduction in New York’s greenhouse gas emissions to 40% below 1990 levels and that renewables generate 50% of the state’s electricity.
To support those objectives, the governor in June announced the largest-ever state-mandated clean energy procurement, authorizing the New York State Energy Research and Development Authority (NYSERDA) and the New York Power Authority to oversee up to $1.5 billion of investment in major renewable energy projects, including offshore wind and solar.
“We’re encouraged by the number of projects, both in the interconnection queue at the ISO, and also in the pipeline of projects that are moving through Article 10,” said Doreen Harris, director of large scale renewables at NYSERDA. Article 10 is New York’s primary permitting process for authorizing the construction and operation of all utility-scale power projects 25 MW and above.
“It’s a good signal to us of the interest in New York and the supply that’s to come.”
Steady Wind
Harris said NYSERDA is focusing on three main areas around renewables: solicitation of long-term contracts; behind-the-scenes work running tracking systems and working with 152 load-serving entities; and aggressive pursuit of offshore wind.
Cuomo in January called for the development of 2,400 MW of offshore wind projects by 2030, starting with the 90-MW South Fork Project off Montauk, Long Island. (See New York Seeks to Lead US in Offshore Wind.)
“The way we are evaluating proposals is more complex than it used to be under the [renewable portfolio standard] in the sense that, first of all, we are looking to signal through some new threshold criteria the desire to really move projects through the pipeline in New York state,” Harris said.
Having the state replace goals with actual standards to achieve over five to 10 years “enhances the ability of developers to focus specifically on development of the best possible assets, with appropriate timelines,” said Jack Godshall, vice president of origination at Invenergy, the largest renewable energy provider in North America.
Firm procurement targets allow companies to spend time and capital developing assets for which they know there will be a market in coming years, Godshall said. “And that’s great for the state and also for the developers.”
Beneficial Load
Corporate clients deciding to “go solar” have shifted toward more and more larger procurements and off-site developments, according to Dennis Phayre, director of business development for EnterSolar, the top solar developer in New York.
“New York state now is limited to 2 MW on the distributed generation level, soon going up to 5 MW, but in our world, with the clientele we deal with, we certainly have to be looking at what comes beyond that,” Phayre said. “Having appropriate maturity barriers, so that we don’t have churn in awards, is super important to ensure that NYSERDA isn’t rebidding the same 100,000 MWh over and over again.”
NYSERDA Director of Policy and Regulatory Affairs John Williams said people tend to think of the DG outcomes of REV, but the program “always envisioned the supply side needing to undergo some pretty dramatic changes as well, and the Clean Energy Standard is the primary mechanism. When planning for a dynamic grid, we always imagined that there’s going to be a lot of dynamic activity on the supply side.”
Why all the focus on the power generation sector when it only represents about 20% of GHG in New York? Over the past decade, New York has nearly halved the sector’s GHG emissions, with an accompanying shift in load, according to Williams.
“The CES actually needs to take account of the shift of load,” Williams said. “We like to call it beneficial load, but clean energy-powered load only becomes beneficial to the degree that we can get consistent and continuous emissions reductions and a shift in that emissions profile in that electric generation sector. The value in an aggressive, continuous focus on power generation sector emissions is necessary because it winds up being the solution to emissions reductions that we need to see in other sectors.”
Great River Energy is urging MISO to account for the effects of inverter-based generation in the RTO’s transmission planning studies.
Inverter-based generation — often new technology resources asynchronously connected to the grid via an electronic interface — can harm reliability in weak power systems, Great River Energy’s Mike Steckelberg said at an Aug. 15 MISO Planning Subcommittee meeting. The Minnesota utility discovered the issue during a recent analysis, he said.
Great River Energy linemen | Great River Energy
Steckelberg cited a June NERC report warning that such resources can affect dispatch and reliability — including voltage control, frequency response and ramping — when too many of them are interconnected into weak power systems.
The company said MISO’s annual Transmission Expansion Plan study process should include screening for transmission with low short-circuit currents, comparing the megavolt-ampere level before a inverter-based resource is connected to the nominal power rating of that resource. If the calculation does not meet a certain threshold, MISO should remedy the transmission by modifying controls, connecting to a stronger source, planning for more transmission or reducing the size of the generation project.
GRE transmission | Great River Energy
“This is a fairly easy screen to be doing ahead of time,” Steckelberg said. While the screen would not have to be a “full-blown study,” it does need to be incorporated into MISO’s generation interconnection studies.
Steckelberg said MISO’s Interconnection Process Task Force and Planning Subcommittee both need to address the issue, and transmission owners and planners should be able to review new interconnection requests for low short-circuit current issues.
Entergy’s Yarrow Etheredge and American Transmission Co.’s Patrick Gerum said their companies shared GRE’s concerns.
Customized Energy Solutions’ Ginger Hodge asked for MISO’s response on the issue.
MISO Director of Planning Jeff Webb said he and his staff would review the request and put together a response at the Planning Subcommittee’s next meeting in October.
Frequent rule changes and an uncertain market structure are causing dissatisfaction among CAISO demand response providers and eroding participation in the programs, those providers say.
Problems with data verification and settlement required the ISO to recalculate its 2016 DR results, and providers say there are other issues with the program, which aggregates utility customers to facilitate their participation in the ISO’s wholesale markets.
“We have not received any energy payment of any dispatch of our resources going back to June 2016,” EnerNOC Director of Regulatory Affairs Mona Tierney-Lloyd told RTO Insider. While Tierney-Lloyd doesn’t think there are large payments still outstanding, “it is obviously sub-optimal,” she said.
EnerNOC control room | EnerNOC
EnerNOC and other companies aggregate retail electric customers and bid the load reductions into the CAISO market to offset the need for generation. Wholesale DR aggregates and compensates electricity users that reduce their consumption to below a pre-established baseline. Separately, utilities also maintain DR programs in which they provide customers a financial incentive to decrease load.
Tierney-Lloyd believes there are several factors causing the decline in DR program participation, including rule changes and modifications to the way DR resources are dispatched. There are also inconsistencies between CAISO and California Public Utilities Commission rules, she said. Agency misalignment is the primary cause of what she said is significant decline in DR program participation.
Participation in PG&E, SCE Demand Response Programs, 2011-2016 | EnerNOC
“It takes work on our side to get those customers familiar with those rule changes,” which also adds costs, she said.
During hot weather, it is more difficult for customers to reduce their usage below baseline, resulting in some taking efforts to reduce demand without getting paid. Others keep a close eye on CAISO operations and don’t understand why they are getting dispatches when no shortages are seen on the system.
CAISO uses DR as a way to make the grid more efficient and reduce greenhouse gases associated with climate change. While the ISO has a number of DR program improvements underway, its past problems slowed payments to market participants. (See CAISO Resettling 2016 Demand Response Results.)
In 2016, the DR system was sometimes unaware that an event had occurred, or the system did not deliver settlement data, CAISO said. The system was not receiving the correct “payload” to identify that a DR event occurred, so the system was unaware of the event and no performance measurement was completed. But even when the event day and historic meter data were available, the DR system in some cases did not send the values to the settlement system, so no settlement occurred. The ISO’s full resettlement should be completed in October.
The CAISO Board of Governors recently approved the second phase of a program meant to make distributed resource integration easier, dubbed the Energy Storage and Distributed Energy Resources (ESDER) Phase 2 proposal. (See New CAISO Rules Spell Increased DER Role.) ESDER includes a set of alternative energy usage baselines to assess the performance of proxy demand resources, one of a series of refinements to the DR program.
NEW YORK — New York must improve its policies and regulations around distributed energy resources in order to ensure that community solar can help meet Gov. Andrew Cuomo’s goal of 325 MW installed solar capacity in the city and nearly 3,000 MW statewide by 2023.
| SEIA
That was the perspective of participants on a community solar development panel at the Infocast New York Energy REVolution Summit held Aug. 1-3 at Times Square.
“The community solar programs in New York were slow to start, much slower than we originally anticipated because the market signals weren’t quite there for a while,” said Cynthia Christensen of Namaste Solar, an employee-owned cooperative with headquarters in Boulder, Colo., and an office in New Paltz, N.Y. “Investors always like certainty. Good, bad or indifferent, give them certainty.”
Panel moderator Valessa Souter-Kline, policy coordinator for the New York Solar Energy Industries Association said, “Community solar is still fairly new. The order authorizing it [Reforming the Energy Vision (14-M-0101)] came out in 2015, and it’s had a slow start because when the CDG [community-distributed generation] order came out, the state also started digging into some other policy issues, including the value of DER. So there has been some policy and regulatory uncertainty.”
The Value Stack
The state’s Public Service Commission in March issued a Value of Distributed Energy Resources (VDER) order (15-E-0751) that began the transition away from net energy metering and toward an approach that aggregates specific value components. (See NYPSC Adopts ‘Value Stack’ Rate Structure for DER.)
Drew Warshaw, vice president of community solar for NRG Energy, said that the VDER order differed significantly from its draft form.
“As a result, the slow ramp-up that we’ve had is going to continue unless some of the economics around that problem change. In terms of the governor’s and the administration’s goal of 325 MW of community solar — we don’t see that happening without significant changes around the program economics,” Warshaw said.
To incent community solar, “there are any number of levers on the revenue side that the state can pull,” Warshaw said. “I think the [New York State Energy Research and Development Authority] block program is certainly one — and the market transition credit, which is one of the pieces in the value stack of the VDER order.”
City Goals
Mayor Bill de Blasio in 2015 launched the OneNYC climate change program, which aims to lower the city’s greenhouse gas emissions to 80% below their 2005 levels by 2050, achieve the best air quality of any large U.S. city and send no waste to landfills by 2030.
Benjamin Mandel, renewable energy policy adviser with the mayor’s Office of Sustainability, said the city is working to ensure that as the market moves beyond net metering, it “has the right kind of signals both in terms of where it benefits utilities and also where does policy benefit and where we want to see DER projects going, including community solar.”
In terms of the installed capacity needed to meet its greenhouse gas mitigation goal, the mayor’s office estimated it would need 7 GW of solar citywide, which is “our entire technical potential,” Mandel said. “For reference, we’ve probably got between 110 and 120 MW installed citywide right now … a stretch goal is to reach 1,000 MW of installed solar capacity citywide by 2030.”
The mayor’s office works with Sustainable CUNY and the NYC Economic Development Corporation to expand access to the benefits of solar energy and other forms of renewable energy. Programs include Solarize NYC — for community group purchasing — and a related program called Shared Solar NYC.
Since 2006, the NYC Solar Partnership program has connected government and industry with oversight agencies that permit rooftop solar projects and with the interconnecting utility, Consolidated Edison. This “has greased the skids” and allowed the city to narrow the disparities in solar adoption between the five boroughs and less dense areas like Westchester or Long Island, Mandel said.
And the city has its own large constituents. Bomee Jung, vice president of energy and sustainability for the New York City Housing Authority, said, “If NYCHA doesn’t meet its goals, it’s not likely that the city’s going to get there without us.”
The housing authority serves about 400,000 people in 176,000 apartments and another 200,000 people through its voucher program, the largest numbers of any city in the country.
Near Future
“You’re going to have a fairly limited market here in the near future for a few reasons,” said Tom Hunt, vice president of corporate development for Clean Energy Collective, which licenses community solar software to developers and utilities.
“You have economics under Phase One [of New York’s Clean Energy Standard] that probably don’t work in at least a few different load zones … and in those load zones where the economics do work, you’re going to have some pretty significant interconnection issues, or siting issues for here in the city,” Hunt said.
“The math will work, the economics will work in Con Edison Zone J [NYC], but the challenge there is siting,” Warshaw said. “We have a service area that produces an amount of community solar at scale that’s really going to make an impact. So that’s the challenge that a company like NRG sees, which is very focused on building out community solar, has the money to invest in New York and feels like a lot of positive things are happening in New York in terms of the climate, the horsepower and the brain power in Albany focused and wanting to do this.”
Some solar developers claim that there’s going to be 2 GW of community solar built in the next 12 months in load zones A through C, but Hunt is doubtful.
“I don’t know that there’s 20 MW within all that that have figured out how you deliver a full program in terms of bringing customers in and billing them, invoicing them, let alone getting utilities on your side so you can bill credits,” Hunt said. “While we’re certainly optimistic about the order and what it means, there’s a lot of work left to be done, and which we think needs to be done in order to make this market sustainable.”
VALLEY FORGE, Pa. — Unpredictable rainstorms throughout PJM in the middle of July resulted in overestimated load forecasts last month, the RTO’s Chris Pilong told members during an Aug. 8 Operating Committee meeting.
“Just about every afternoon, we had rainstorms that were possible … and just about every day, those storms did hit,” he said, noting that they reduced temperatures and caused daily forecasts to exceed actual load by as much as 6,000 MW.
One example: While the RTO forecast peak demand of approximately 150,000 MW on July 20, early afternoon storms capped load at about 145,000, Pilong said. That allowed the summer peak so far to remain the previous day, July 19, when demand hit 146,635 MW, he said.
PJM’s peak load forecasting error for the month was 4.58%, 0.79 percentage points above July 2016, PJM’s Joe Ciabattoni said. The overall forecasting error was 3.13%, just above PJM’s 3% target. Ciabattoni attributed the deviation to the “pop-up storms” on the western side of the footprint. The errors were highest in the distribution territories of Dayton Power & Light, Duquesne Light, FirstEnergy’s American Transmission Systems Inc. and Duke Energy Ohio/Kentucky.
The monthly balancing authority area control error limit, which measures how well the RTO maintains constant frequency control, was 99.9%, with total excursions and excursion minutes at their lowest levels in at least the past year.
The Anatomy of a LMP Spike
LMPs jumped to about $900/MWh around 10:30 a.m. on July 27, Pilong said. An outage the previous evening on the Black Oak-Hatfield 500-kV line created increased flow on the Conastone-Peach Bottom 500-kV line. PJM had been controlling flow over the latter segment to roughly 93% of its limit, but flow levels on the line can be volatile, as they are sensitive to load or generation movements. Moves from hydro units and shifting load increased flow over the line by about 5%, Pilong said.
Operators directed PJM’s security-constrained economic dispatch (SCED) engine to reduce flow over the line by 6%, but the demand was too great and sent the engine into a “relaxation mode” in which it doesn’t attempt to control the flow. Pilong said that in those instances, SCED just fails to solve the case and moves on to resolve the rest of the system.
Operators reduced their request to 2%, which SCED could perform but only by raising the LMP to about $900/MWh. The price spike caused generation to respond, which reduced the strain on the line and allowed SCED to realign prices.
GT Power Group’s Dave Pratzon asked if such short-term and unexpected fluctuations were caused by PJM’s move from 15-minute to 10-minute dispatch settlements. He also questioned whether generators will be expected to follow PJM’s dispatch signals during those periods and how signal deviations will be handled.
Pilong said that with the shorter lookaheads, larger transmission changes will create greater price separation. Part of the issue, he said, is the response time of low-cost resources.
“If the low-cost generation isn’t able to move as rapidly as we need it to, we may need to reach out to more costly resources for a short period time,” he said.
In response to a stakeholder data request, PJM’s Lisa Morelli explained why the real-time SCED engine has not priced for shortages that stakeholders have observed in published data.
The public data come from PJM’s emergency management system (EMS), Morelli said, which has more conservative estimates than SCED. The most significant difference for this was a 2% “back off” in which the EMS system assumes resources will only achieve 98% of their stated capability. This assumption was removed in changes made on July 11, Morelli said, and immediately resulted in a 300-MW increase in the EMS synch reserve.
There are also differences between real-time SCED’s 10-minute lookahead and EMS’ real-time data. Additionally, real-time SCED uses units’ SpinMax (the reserve maximum) to estimate reserves, while the EMS uses the lesser of the SpinMax or the EcoMax (the economic maximum).
Exelon’s Sharon Midgley noted that the data request also asked for all of the unapproved real-time SCED cases, which she said would provide more clarity on whether PJM operators are being presented with real-time SCED cases that include shortages but are declining to select them.
Midgley and Old Dominion Electric Cooperative’s Adrien Ford said they had not been aware of the removal of the 2% back off and asked that PJM be more communicative with such changes in the future.
Morelli said there has been a 12% improvement in the alignment between the two measurements since PJM moved to the 10-minute settlement.
VALLEY FORGE, Pa. — PJM’s Michael Herman told members at last week’s Planning Committee meeting that proposed Manual 14B updates to incorporate modeling changes reflecting the cancellation of the Con Ed-PSEG “wheel” would include reductions in emergency transmission limits.
The capacity emergency transfer limits (CETLs) would be reduced in certain load deliverability areas (LDAs), including by 500 MW in EMAAC, 1,100 MW in MAAC, 1,527 MW in PSEG and 1,309 in PS North.
At PSEG, that would put the CETL at just 574 MW above the capacity emergency transfer objective (CETO), the threshold for necessary transfer capacity to ensure reliability in an emergency. In PS North, the difference between CETL and CETO would be just 335 MW.
The modeling adjustments come in response to Consolidated Edison’s decision to end a decades-long agreement with PJM to route 1,000 MW from upstate New York to New York City through Public Service Electric and Gas’ northern New Jersey territory. The change necessitated reanalysis of regional power flows, which eventually identified that continuing an “operational base flow” of 400 MW would be the most reliable solution. (See Analysis Recommends Continuing Reduced Con Ed-PSEG ‘Wheel’ for Grid Stability.)
In the updated CETL calculations, PJM removed any non-firm energy transfers. However, it kept them in its updated capacity import limit calculations. Stakeholders questioned why non-firm was removed from the CETL.
“If it’s a non-firm product, we just can’t depend on it during these critical times,” PJM’s Mark Sims said. “There could be a time when our system is stressed, the neighboring system is stressed, and then to depend on non-firm energy to support your system … just doesn’t make sense.”
The revisions were approved by acclamation with one objection and 14 abstentions.
PJM has scheduled a webcast on Aug. 30 from 1-3 p.m. to address questions about the CETL procedural changes.
Resilience Planning to Recognize Outage Propagation Potential
Sometimes, resilience means knowing when to give up.
In analyzing its planning criteria, PJM will be considering what is likely to happen downstream when a piece of equipment fails. Sometimes, this will mean the equipment simply collapses at that point. But it could also open a pathway for cascading failures further throughout the system and a larger collapse. (See “Resilience to Become Planning Driver,” PJM PC/TEAC Briefs: July 13, 2017.)
“If you had an existing station where you improved the strength of it such that during an event, where normally it would be lost very quickly and cleanly, it’s now hanging on,” Sims said.
As a result, the grid operator could face a scenario “where the system collapsed instead of being bounded because you actually have a stronger part of the system which allows the event to propagate further and in the end the result is worse,” he said.
To prepare for such a contingency, PJM is developing appropriate metrics and criteria for factoring resilience into planning.
“These are not events that happen often. I can’t pull data on voltage collapses,” Sims said. “We have to do our best to make some valid assumptions.”
Stakeholders have previously asked how PJM plans to address the subjectivity of the topic.
“To PJM, megawatts would just be load, but to others, megawatts are customers,” said John Farber with the Delaware Public Service Commission. He asked if PJM plans on considering the amount of load that would be impacted by a piece of equipment failing.
“I don’t know if you’re suggesting that some load is perhaps more critical than others, [but] I think many people would generally agree with that,” PJM’s Paul McGlynn said.
“I salute your eagerness to swim with the alligators,” Farber replied.
Market Efficiency Analysis Ongoing
Staff have completed analysis of market efficiency projects in the Reliability Pricing Model and are nearly finished examining interregional projects, Sims told members at last week’s Transmission Expansion Advisory Committee.
The RTO is currently reviewing projects from PPL’s zone.
The analysis identified six projects to be recommended for approval by the Board of Managers, including four in Commonwealth Edison’s LDA and one in Duke Energy Ohio/Kentucky. Two of the ComEd projects were proposed by American Electric Power.
Six other proposals — two from AEP and Exelon, one from Transource Energy and three from Northeast Transmission Development — were not recommended. PJM is expecting to seek approval on recommended projects at the board’s October meeting.
Reliability Analysis for 2022 Finds 190 Violations
PJM’s reliability analysis of the Regional Transmission Expansion Plan for 2022 conditions found violations at 190 flowgates.
The majority (115) were generation delivery issues, with most of those (50) being on 138-kV lines on the western side of the RTO’s footprint. Overall, the 138-kV system had the most issues, with 77 violations identified.
The runner-up was the 345-kV system, with 46 violations identified. That system also had 35 of the 37 overall total high-voltage violations. All 35 were in the MAAC region.
Of the total 190 flowgates identified with violations, 41 will be included in the 2017 RTEP proposal window: 33 in the West region, five in the South region and three in MAAC. Generation delivery issues account for 35 of the available projects and six are N-1 thermal violations.
The remaining 149 flowgates were excluded because they were either “immediate need” projects or under 200 kV, which are expected to be addressed by the incumbent transmission owner.
VALLEY FORGE, Pa. — Going into last week’s Market Implementation Committee meeting, it appeared that PJM and its Independent Market Monitor would not find common ground regarding several changes to Manual 11 in preparation for implementing intraday offers on Nov. 1. (See “Revision on Intraday Offers Postpones Vote,” PJM MIC Briefs: July 12, 2017.)
“I don’t believe we are going to come to agreement on [the differences], so even if we delay the vote until next month, there is still going to be a difference of opinion,” said PJM’s Lisa Morelli.
But stakeholders pressed the sides to coalesce around a proposal, which resulted in PJM and Monitor staff — along with Calpine’s David “Scarp” Scarpignato — huddling during a break to hash out their dispute. The outcome is expected to be available for the Markets and Reliability Committee meeting on Aug. 24.
The issues were twofold: first, whether or not generators’ ability to “opt in” to utilizing intraday offers must be enunciated in their fuel-cost policies; and second, how to apply offer caps when a unit decides to change its offer after it has already received a commitment and failed the three-pivotal-supplier test.
Later in the meeting, IMM staff member Joel Romero Luna detailed differences with PJM on the triggers for updating price- and cost-based offers. The Monitor argued that they need to be updated simultaneously, even if the generator only wishes to update one, and the fuel-cost policy must specify the events that will trigger an update. If both offers did not have to change at the same time, it would permit the exercise of market power, the Monitor said.
“The point of intraday offers is to ensure that the current market value of gas is reflected in power prices. If the cost of gas goes down during a day and the generation owner does not have to reduce the offer, then the result is the exercise of market power,” Monitor Joe Bowring said. “If the generation owner opts for flexibility, which we think is a good idea, flexibility must reflect both increases in gas costs and decreases in gas costs.”
The Monitor also argued that all market-power mitigation analysis and approval should keep up with offer updates, but PJM said those revisions would require additional Tariff changes that might not receive FERC approval by the necessary Nov. 1 implementation date. PJM’s revisions, staff argued, could be implemented immediately. The Monitor’s changes would also require additional software changes, Morelli said.
PJM hoped to have its revisions approved and then work with the Monitor on its revision requests, but stakeholders asked that the two staffs resolve their differences before taking a vote.
“You can get it together now, or let’s go straight for guns and lawyers,” said Ruth Ann Price of the Delaware Division of the Public Advocate office. She expressed worry that no process had been defined or agreed upon to address the Monitor’s concerns if the PJM revisions were endorsed, and about the costly and time-consuming process involved in filing an action at FERC that could impede the smooth implementation of intraday offers.
Scarp said it was important that any additional changes be discussed through the stakeholder process and not be a “grand bargain” between PJM and the Monitor. Morelli said any changes would be presented as an expedited problem statement and issue charge.
The Monitor’s position received some pushback from generation owners.
“I think that if [an offer is] not mitigated, I shouldn’t have to have people sitting around, making work for them, just to appease [the Monitor] just because we made a market decision,” American Electric Power’s Brock Ondayko said.
UGI’s Gil Crystle questioned why price- and cost-based offers should be linked in the fuel-cost policy for simultaneous updating, as price-based offers can be adjusted for little more reason than just trying to get dispatched. “My price-based offer, I can change that all day long for no apparent reason, right?” he asked. “There can be a scenario where I don’t even care. … I’ll take whatever the market bears.”
Following the conclave, the sides agreed to defer the MIC vote until September’s meeting but work together to have the single proposal prepared for the August MRC meeting. The MRC vote will be held at the September meeting. The proposal will include all revisions that both sides agree can be implemented by the Nov. 1 deadline. They will also present Tariff and manual changes that both sides agree on, but that PJM believes will require FERC approval for implementation. The Monitor will present a problem statement and issue charge in September or October for the “opt in/opt out” changes on which PJM does not agree.
In a related disagreement, PJM and the Monitor also outlined their differing Manual 11 revisions for energy market offer verification. PJM’s revisions would limit offers to a hard cap of $2,000/MWh for dispatch and setting LMPs. Only cost-based offers would be allowed to exceed $1,000, and all but those that set LMPs would require verification. The Monitor acknowledged verification is essential and raised a list of issues with PJM’s proposal focused on the inadequacies of PJM’s approach to verification.
PJM is also removing references to offer capping and market-power mitigation from Manual 28, as they are now in Manual 11.
Fuel-Cost Policy Update
As part of the preparation for implementing intraday offers on Nov. 1, PJM and IMM staff have been working with generators to get fuel-cost policies reapproved. Policies were submitted in May to conform with recently implemented analysis changes. (See PJM Monitor Rejects Fuel-Cost Policies for 11% of Units.)
Romero Luna said 56% of units passed Monitor evaluation for Nov. 1. Among the failed submissions, some only required minor changes such as formatting, while others required major changes to conform with the new rules regarding intraday offer updates. The policies requiring major changes are “all gas units, basically,” Romero Luna said.
PJM’s Jeff Schmitt also outlined changes that the RTO is requesting for fuel-cost policy submissions, such as indicating if the variable operations and maintenance, emissions or 10% adders are used in cost-based offers.
“You’ve got to think through how you’re going to create a $1,000 offer and above,” he said.
Stakeholders endorsed by acclamation two problem statements and issue charges proposed by the Monitor. (See “IMM Presents Problem Statements on Transmission,” PJM MIC Briefs: July 12, 2017.)
The first set addresses what the Monitor believes is the need for clear rules governing the use of transmission penalty factors in setting prices in the PJM energy market when there is locational scarcity.
The second addresses market path/interface pricing point alignment, calling out situations that can arise when market participants submit transactions that are not consistent with actual physical power flow. Market manipulation results when scheduling is inconsistent with actual power flows, Bowring said. “There’s not an explicit rule” covering the issue, he said. “There needs to be a clear rule for the benefit of those entering transactions, for other market participants and to ensure that market power is not exercised.”
A “Top 10” project list emerged after stakeholders ranked 34 market modification proposals in the RTO’s annual Market Roadmap process, MISO Senior Manager of Market Strategy Mia Adams said during an Aug. 10 Market Subcommittee meeting.
Stakeholder scoring results still have to be tallied alongside staff weightings to arrange what market projects the RTO will eventually undertake first.
“This is not a prioritization yet. We’ll come back again this fall with an updated work plan,” Adams said. “However, it does look like [staff and stakeholders] are in pretty good alignment this year, more so than last year.”
This year, MISO limited stakeholders’ scoring to a maximum of four “high” and six “medium” priority designations, with an unlimited number of “low” and “do not pursue” designations. This year’s market project candidates included proposals outlined in the Independent Market Monitor’s annual State of the Market report. (See MISO, Stakeholders Embark on Market Roadmap Rankings.)
Rising to the top of stakeholder priorities: energy storage. Sixty-one market participants with voting rights determined that the most pressing issue for the market is defining a new resource type to accommodate the unique qualities of energy storage. During a special storage workshop last month, stakeholders asked MISO for a storage market definition. (See MISO Rules Must Bend for Storage, Stakeholders Say.)
Three other issues earned high priority from stakeholders:
Creating an automatic generation control software enhancement that deploys fast-ramping resources more quickly. MISO currently estimates that software can be operational in late 2019;
Better modeling of MISO’s approximate 40 combined cycle generators worth 29 GW, which was first requested by market participants in 2011 and is currently in a benefit analysis and design option phase. The new modeling could save an annual $14 million to $34 million in production costs, according to MISO’s Yonghong Chen, but won’t be ready until 2020.
Market improvements recommended by Monitor David Patton took four of the six medium-priority designations in final stakeholder scoring:
Setting up short-term capacity pricing and reliability standards so energy can be provided within 30 minutes when needed to manage capacity needs;
Factoring seasonal needs and risks into the capacity auction;
Refining modeling and rules so demand response and storage resources “operating across multiple buses” can aggregate to meet a minimum megawatt participation limit;
Expanding conditions and temperature-adjusted transmission ratings into MISO’s Energy Management System;
Creating a virtual spread product; and
Incentivizing frequency response service.
MISO will release its final Market Roadmap by December.
Five-Minute Settlements Delayed?
Several stakeholders have asked MISO to consider pushing back the March 1, 2018, target for implementing the five-minute settlements calculation. (See “Five-Minute Settlements BPM due in Summer,” MISO Market Subcommittee Briefs.)
Northern Indiana Public Service Co.’s Bill SeDoris said his company is still awaiting Business Practices Manual language while it works to implement five-minute settlements, and could miss the deadline while still making software and mechanical adjustments. DTE Energy’s Nick Griffin agreed.
“We are hearing from folks the same concern,” said MISO Executive Director of Market Design Jeff Bladen. “We are still subject to a FERC order. … We can ask for an extension, but we have a FERC order that we have to comply with. That said, we can only do what everyone is feasibly capable of.”
Bladen said MISO has already requested a later implementation date than other RTOs, but it will further discuss the possibility of an extension during the September Market Subcommittee meeting. He said MISO still has a team working to create five-minute settlements rules, but the work, originally due in early summer, has been delayed. It is also working on identifying units that habitually deviate from setpoint instructions, he said.
MISO has used geometric analysis to identify 159 electrical pricing node candidates to comprise Mississippi’s own commercial trading hub, said Michael Robinson, principal adviser of market design.
The nodes are located in both the MISO South and Southern Mississippi Electric Power Association territories, Robinson said. All other MISO trading hubs contain at least 100 electric pricing nodes, and the RTO’s analysis considered 622 possible nodes.
The proposed hub, the first MISO hub in the state, will be rigorously stress-tested over the next two months before final recommendation is made at the October MSC meeting, Robinson said. The RTO hopes the new hub will go live before the end of the year. (See MISO Examines Potential Mississippi Trading Hub.)
Market Reopen Incident
Stakeholders also asked why MISO had to briefly reopen its day-ahead market after market close on July 26.
MISO Executive Director of Strategy Shawn McFarlane called the reopening a “market participant issue.”
“To not correct this issue would have caused all other sorts of issues in the market,” McFarlane said, adding that the error fell into the “broad category” of data-entry errors. He declined to provide any other details.
Tariff changes made last year enable MISO to extend or reopen the day-ahead market to address technical problems. (See “Day-Ahead Market Extension to be Written into Tariff,” MISO Market Subcommittee Briefs.) Stakeholders asked MISO officials for a future presentation describing under what scenarios MISO may reopen the market. Bladen said MISO could put together a presentation for the September MSC meeting.
