VALLEY FORGE, Pa. — PJM and some stakeholders are at odds over whether access to the transmission grid is a right generators purchase through interconnection upgrades or an opportunity granted by load to serve its needs. The philosophical difference is playing out in efforts to streamline the process for capacity resources seeking exceptions to offering into Base Residual Auctions.
PJM has proposed allowing generators to request exceptions from multiple auctions at once and allow timing as an acceptable reason for an exception. It also would clarify the documentation required by the RTO and its Independent Market Monitor for being removed from capacity resource status.
Lowman Step Up Substation | Central Alabama Electric Cooperative
Exelon, which initiated discussion of the issue, offered a proposal that differs from PJM’s only in not requiring a status change for units that are continually approved for an exemption and don’t offer into a BRA after three consecutive delivery years.
That is potentially the difference between whether the unit must relinquish its capacity interconnection rights (CIRs), which grant access to inject generation into the transmission system. If not enough CIRs are available, generators must pay for system upgrades to address their needs or risk not being allowed to sell all the power they can produce. Excess CIRs can have value and be sold.
At last week’s Market Implementation Committee meeting, Gary Greiner with Public Service Electric and Gas supported Exelon’s position, arguing that because generators spend millions of dollars for the upgrades the CIRs are the companies’ property.
Monitor Joe Bowring and ODEC’s Mike Cocco defended PJM’s proposal, arguing that load has spent billions to develop the transmission system that makes the rights possible. Bowring said the CIRs are for units that want to provide capacity for load and that “hoarding” them without committing to provide capacity is “effectively blocking” new units that do want to make that commitment.
“Imagine if [companies] had a benefit to restricting access to other competitors. … That does not make sense,” Bowring said. “If you can’t provide the capacity, it doesn’t make sense to block others who can. … You don’t own the right in perpetuity to inject power into the system because you paid for” necessary upgrades.
“It’s not a ‘forever’ property right. Many of these capacity injection rights were assigned to generators without them incurring any interconnection costs. They have an obligation to clear the capacity market within a three-year time frame or they lose these rights,” Cocco said.
David “Scarp” Scarpignato searched for middle ground.
“I agree with Joe,” he said. “There is a potential hoarding issue here. But there’s also on the other side, people pay for some rights.”
He explained that units that have received exceptions would become uncommitted capacity resources rather than energy-only resources and would keep their CIRs if they pass PJM’s annual deliverability tests.
Exelon’s Jason Barker noted that generators maintain CIRs only until one year after deactivation of the unit, so it “doesn’t exist in perpetuity.”
“The question is whether you’re meeting the requirements of the [Capacity Performance] paradigm, which changes on a regular basis,” he said.
He pointed out that generators’ interconnection service agreements would also need to change and there would be a “necessary discussion” if PJM made a proposal to change them.
Roy Shanker, an economist who often represents individual generators, said the key is determining whether a generator has no intention to offer into the auction or is simply delayed in doing so.
“If you aren’t trying to make progress toward [becoming a CP-compliant unit within three years], it is a form of withholding,” he said. “If you identify a market power issue, you fix it. … All this other stuff is irrelevant.”
VALLEY FORGE, Pa. — Generation reserve margins might drop and fuel-assurance risks could increase if coal and nuclear units retire sooner than anticipated, according to the preliminary findings of a NERC study focused on PJM and ERCOT.
PJM staff confirmed at the RTO’s Planning Committee meeting on Thursday that NERC had discussed the study at its own Planning Committee meeting earlier last week. The draft report has been sent out to members of NERC’s PC for comment, with the reliability overseer planning to present the final version to its Board of Trustees at its meeting on Nov. 6-7.
NERC spokesperson Kimberly Mielcarek said the target for public release is “before the end of the year.”
She declined to provide details before the study is final but pointed to the PC agenda, which outlines the study’s history.
NERC began soliciting policy input in May 2017 from stakeholders, proposing to conduct “an assessment of the potential impacts on Bulk Power System (BPS) reliability that could be caused by accelerated retirements of traditional baseload generator resources … to understand and address reliability challenges associated with the changing resource mix.”
NERC’s report would address accelerated closures of units like the Oyster Creek nuclear plant (shown in 1998), which shut down on Monday.
NERC staff analyzed aggregated supply and demand projections for the study, along with engineering studies on specific retirement scenarios. They also reviewed regional processes for managing plant deactivations.
According to the agenda’s description, the study found that “when generation retirements exceed or outpace needed replacement resources, the BPS is less capable of withstanding contingencies, unplanned facility outages and extreme conditions.”
It added that “replacing retiring coal-fired and nuclear generation with natural gas-fired generation provides essential reliability services but can result in near-term stress on the natural gas infrastructure and create challenges to fuel deliverability in extreme winter conditions and major natural gas contingencies.”
Managing those issues will require “continued adherence to rigorous resource adequacy assessment and transmission planning processes” as “large amounts of generator retirements can result in extensive network upgrade requirements” and “potentially the increased use of out-of-market solutions such as reliability-must-run (RMR) designation to address resource adequacy issues,” NERC said.
VALLEY FORGE, Pa. — PJM has scheduled a two-day workshop on enabling distributed energy resources to “ride through” frequency fluctuations but postponed action on a task force on the issue in the face of stakeholder concerns.
PJM’s Emanuel Bernabeu told the Planning Committee last week that the workshop is the first step in developing a guidance document for how DERs should implement a ride-through standard and presented a problem statement and issue charge to create a DER Ride Through Task Force. The proposal met with immediate concern from representatives of transmission owners, who felt it focused on jurisdictional issues rather than safety and reliability.
“That gives us pause,” FirstEnergy’s Jon Schneider said. “The spirit of this initiative is really to find the right balance … so it can support the bulk transmission system and the distribution system. … What’s resonating is jurisdiction rather than safety.”
“Absolutely what we want to do is what you described,” Bernabeu said.
Duquesne Light’s Tonja Wicks also voiced concerns, including that a focus on interverter-based technologies that was in previous versions of the proposal had been removed. That focus was challenged as not being technology-neutral during the proposal’s first read at last month’s PC meeting, but Wicks said the scope could be overly broad without it.
The reticence threw a wrench in PJM’s plan to receive approval for the task force in advance of the two-day workshop, which has already been scheduled for Oct. 1-2. Bernabeu received no concerns with his explanation of the issue at the monthly Operating Committee meeting earlier last week. There, he highlighted three disturbances within the past 12 years that were triggered by large amounts of renewable generation disconnecting from the grid in response to frequency fluctuations. A 2006 outage in Europe — which Bernabeu called “one of my favorite blackouts” — identified the threat from many small generators collectively tripping in what’s been termed the “50.2-Hz Problem.”
“Basically, they did not have this concept of ride-through,” Bernabeu said, adding that similar issues occurred in two subsequent incidents in Southern California and Australia in 2016. “You would think we would have solved this.”
A challenge in PJM’s territory, he said, is that the vast majority of DERs aren’t under PJM’s authority and instead follow state and local regulations. Staff hope the task force will settle on a standard that can then be provided to state and local regulators as guidance. The issue charge calls for developing a PJM-wide “profile consisting of an abnormal voltage and frequency performance category and specified trip settings, if adjusted from the defaults.” As an alternative, the rule could specify minimum ride-through and trip times and defer to distribution utilities on implementation details, the issue charge said.
The topic isn’t “overly complex,” Bernabeu said, but will require a broad group for input.
“We can’t ignore the fact that it’s the vast majority of DER sources. … What we want to establish is consensus across the footprint on specific standards,” he said. “If we succeed, everyone will embrace it.”
Staff agreed to postpone requesting a vote on the proposal to address TOs’ concerns, but they also asked if there was any issue with holding the workshop as scheduled on an “ad hoc” basis. No one opposed.
Vote Delayed on Capability Testing
Staff had also agreed prior to the meeting to postpone a vote planned on revisions to Manual 21 that would change some of the procedures for generators’ annual capability testing. The proposal has created concern because it could reduce units’ capacity injection rights. (See “Skepticism of Gen Capability Changes Continues,” PJM Operating Committee Briefs: June 5, 2018.)
PJM’s Patricio Rocha-Garrido also presented an analysis of the effective load carrying capability (ELCC) for wind units. The study calculated ELCC values for each year from 2009 through 2017 using the 12,540 MW of wind units projected to be operating in 2021. It found that the mean ELCC is 11.5% of the nameplate capacity and the median is 10.2%. The numbers backed up PJM’s argument for using median capacity factors for wind rather than mean. The median of capacity factor values PJM calculated for wind output from 2015 to 2017 was 7.9%, while the mean was more than twice as high at 16.7%.
Some stakeholders were critical of the analysis, saying it didn’t account for geographic differences and that using historical numbers for expectations of future performance ignores technology improvements.
“I don’t think we should be using any assumptions on the future, because what do we assume?” Rocha-Garrido said in response. He added that while GEMARS, PJM’s hourly loss-of-load-expectation tool, is capable of more detailed analyses, the study was in relation to the installed reserve margin, which is calculated at the RTO level, so “it’s immaterial to me where [the units] are located.” He acknowledged that units could receive a higher value if they were able to increase their output during the hours tested but said he doesn’t “see a significant difference” between PJM’s methodology and alternatives suggested by stakeholders.
Dave Mabry, representing the PJM Industrial Customer Coalition, said he was still trying to understand the differences between the RTO’s study and a similar study by General Electric that came to different conclusions. He suggested that perhaps ELCC is the metric that should be used for measuring wind capacity.
Rob Gramlich, representing the American Wind Energy Association, criticized what he felt was a low amount of data provided and said he appreciated PJM tabling the vote for further discussion.
“We still have a lot of concerns,” he said.
IRM, FPR Reduced
PJM is recommending a 15.7% IRM and a 1.0887 forecast pool requirement (FPR) for next year’s Base Residual Auction, both of which are slight reductions from last year. The IRM recommendation fell 0.1% and the FPR — which reflects the reserve margin to account for peak loads and generator outages — dropped 0.0011, both based on the 2018 capacity model.
Update on Integrating Cost-containment Guarantees
PJM’s Mark Sims outlined staff’s work on integrating cost-containment guarantees in its analysis of developers’ proposed transmission projects. The five-step process will standardize the cost-containment measures offered in each proposal, present them in a visual way, compare them and allow staff to choose the “most economically efficient” proposal. Sims said it will all be implemented into a comparative matrix and that stakeholders should expect to see more details about each of the five “boxes” in the coming months.
“You would expect to see this as part of the overall decision-making process,” he said. “This is our high-level concept. We are into the weeds with the [Independent Market Monitor] on several of these boxes.”
He said “the most challenging pieces right now are” figuring out how to standardize the proposals and then crunching the numbers to evaluate them. Staff sought input from a “large corporate lender” and are not anticipating lender risk being “a huge factor” in evaluation, he said.
LS Power’s Sharon Segner, who led the effort to incorporate cost guarantees into PJM’s evaluations, voiced her approval of the progress. (See “Delay Approved for Cost Containment Comparisons,” PJM MRC/MC Briefs: Aug. 23, 2018.)
“This is all sounds very good,” she said. “It is a hard assignment, and we very much appreciate what you’re doing. But this is an important discipline to establish.”
First M-3 Experience
Dominion Energy’s Ronnie Bailey briefed stakeholders on 13 violations of its system planning criteria his company plans to correct— implementing for the first time the TOs’ new process for supplemental projects, which is detailed in Tariff Attachment M-3. (See AMP Offers ‘Best We Can Do’ on PJM Tx Planning.)
In accordance with the M-3 processes, Dominion will follow up at a subsequent meeting with how it plans to address the issues.
FERC Orders on Tx in Calif.
PJM and American Municipal Power have agreed to revise their proposals for developing transmission-replacement processes to reflect FERC’s Aug. 31 rulings that Order 890’s transparency provisions do not apply to “asset management” projects that provide only “incidental” increases in transmission capacity.
The orders (EL17-45 and ER18-370, AD18-12), which rejected complaints by California regulators and others, were discussed at a special session of PJM’s Markets and Reliability Committee that met briefly after the Transmission Expansion Advisory Committee meeting. (See ‘Asset Management’ not Subject to Order 890, FERC Rules.)
PJM’s Chris O’Hara said the focus during the RTO’s stakeholder process hasn’t included maintenance.
The RTO and AMP will revise their proposals so they can be presented at an Oct. 16 meeting on the issue and prepared for consideration at the Oct. 25 MRC meeting.
“I think the goal from PJM’s perspective is we have an ongoing process and in that process, we want to provide the appropriate level of process and transparency while avoiding any unproductive litigation that may come from it,” O’Hara said.
AMP’s Lisa McAlister said including maintenance has “never been AMP’s goal.”
VALLEY FORGE, Pa. — In a rare occurrence, half a dozen residents opposed to PJM’s largest-ever congestion-reducing transmission project attended last week’s Transmission Expansion Advisory Committee to protest the RTO’s reconfirmation that the project would be beneficial to the public.
The $366.17 million project proposed by Transource Energy would consist of two separate 230-kV double-circuit lines, totaling about 42 miles, across the Maryland-Pennsylvania border — one between the Ringgold substation in Washington County, Md., and a new Rice substation in Franklin County, Pa., and another between the Conastone substation in Harford County, Md., and a new Furnace Run substation in York County, Pa. (See Line Opponents Set Sights on PJM in Public Campaign.)
PJM’s annual re-evaluation of the project’s benefit-to-cost ratio found that it had increased to 1.42 from a 1.32 evaluation published in February. The RTO’s threshold for considering such market efficiency projects is 1.25. The new evaluation included an increase in the project’s cost from its original $340.6 million estimate. PJM’s Nick Dumitriu said he spent an extensive amount of time attempting to make the analysis as comprehensive as possible and said “there are good reasons why” the ratio increased.
However, Vice President of Planning Steve Herling admitted “you can never know you have all the data” for evaluating a project and that “you have to put a stake in the ground” to determine what set of information is used.
“It’s unfortunately a moving target,” he said. “We’ve had lines where the supplemental analyses [found], based on the passage of time, the need erodes.”
“How do you expect us to have trust in your figures when you’re telling us now you don’t know,” asked Patti Hankins, one of the objecting residents of Harford County. She noted that PPL told Pennsylvania regulators it could add another cable on an existing right of way that parallels the proposed route. “That’s a hard thing for us to swallow,” she said, when state officials “all understand there’s existing infrastructure that can support this” upgrade.
PJM has previously confirmed that PPL also proposed a project to address the congestion on the AP South interface, which the Transource proposal also targeted. But PPL’s proposal only upgraded a nearby substation, didn’t include utilizing the extra space it has on its existing line and failed to achieve a benefit-to-cost ratio that exceeded the 1.25 threshold, RTO officials said.
While staff acknowledged the residents’ concerns, Herling said the decision to move forward with the project is now in the hands of state regulators to determine whether it should receive necessary permits. He added that staff “will certainly support” the commissions with any analyses they request.
“We’re not in a position to essentially usurp a state’s authority and take action on determining whether or not the project should move forward,” Herling said, indicating that staff will go back to the drawing board if the project is denied. “Our audience right now are the two commissions, and … we will abide by whatever decisions Pennsylvania or Maryland require us to make.”
The states’ consumer advocates showed interest, with representatives from both agencies asking questions about PJM’s analysis process. Gary Alexander from the Maryland Office of People’s Counsel questioned the urgency of the project, asking why Transource hasn’t yet entered into contracts with suppliers.
Herling said the company is getting bids. “I don’t know what the sequence of activities will be for executing those contracts,” he said.
FERC could also throw a wrench into PJM’s analysis. The Markets and Reliability Committee endorsed Tariff revisions in August that would exclude generating units with facility study agreements (FSAs) and suspended interconnection study agreements from PJM’s base case for analyzing market efficiency projects. The RTO says including these units causes unrealistic benefit estimates for proposed transmission projects. (See “Market Efficiency,” PJM MRC/MC Briefs: Aug. 23, 2018.)
Staff acknowledged that projects may need to be re-evaluated if FERC accepts the revisions.
“I think we’re going to have to look at units on a project-by-project basis” to determine if FSAs made a difference, Herling said. “We just don’t have time to run sensitivities ahead of time.”
However, he said if FSAs were removed from the Transource evaluation, the ratio would actually increase “based on current factors.”
The math did little to reassure the residents, who said they were being forced to waste time on a process that should be an easy decision.
“From the ground, the people see that PJM is not working in the interest of the ratepayers,” Harford County resident Aimee O’Neill said. “We must simply slog through it. … You are making it a very expensive process [when it] is apparent [there is] an alternative to a greenfield project.”
Herling said the current process will continue for the Transource project, but he conceded that staff needs better engagement with states.
“They have a process, we have a process, and we need to change that moving forward,” he said.
CARMEL, Ind. — MISO last week said it might rely on a long dormant analysis to create a pricing structure to compensate resources for delivering energy to restore the system in the event of the real-time market ceasing to function.
Speaking at a Sept. 13 Market Subcommittee meeting, MISO Director of Market Services John Weissenborn said a five-year-old white paper on the subject provides good recommendations for compensating resource owners and allocating costs when portions of the system are islanded.
MISO’s Steering Committee directed the Market Subcommittee to take up the issue in July on recommendation from the Reliability Subcommittee after nearly five quiet years on the topic. (See MISO Stakeholders to Reconsider Restoration Pricing.)
The white paper proposes a framework that allows MISO to make real-time pricing adjustments for islanded areas to facilitate real-time and day-ahead market settlements while providing generators the ability to make further revenue adjustments to ensure adequate compensation for the production costs of providing energy.
MISO said the pricing relies on the monitoring of generator output and load served within an island. Generators within a separated area would receive an hourly restoration cost recovery calculated by multiplying the number of megawatt-hours served by either 110% of their FERC-approved rate or $100/MWh, whichever is greater. Asset owners could also file a restoration energy rate with FERC that includes start-up, fuel and variable operation and maintenance costs with FERC and submit the approved rates to MISO.
To recover from a total blackout, MISO would turn over generation control of islands to local balancing authorities (LBAs) until those areas can be turned back over for dispatch. Restoration pricing would be in effect from the first partial hour of the blackout to the last partial hour prior to re-synchronization with the grid. Until MISO establishes a firm, interconnected grid, LBAs will have control of connected market generation, though the RTO’s system will have begun generating LMPs.
Weissenborn said the issue would require a Tariff filing. He added that MISO “isn’t looking for a 14-page” standalone filing, but “something we can provide in the Tariff to capture our intent to cover this compensation if we have one of these events.”
Currently, islanded commercial pricing nodes are assigned LMPs from a functioning nearby pricing node in the footprint.
Weissenborn also said the white paper might need some updating because of its age.
“I’m not saying that we’re going to turn this thing upside down and redo it, but I do think it provides good guideposts,” he said.
It’s unclear whether MISO plans to use the same megawatt cost values in an updated version of the pricing calculation.
Weissenborn said the restoration pricing structure will not impede the restoration energy plans of LBAs already in place. In its white paper, MISO said its “strategy to restore the system to normal operation does not rely on economic commitment and dispatch but instead addresses the immediate need for energy supply needed to support stable power system operation.”
“We’re going to first think about getting the lights back on, but then we’re going to have to contemplate compensation,” Weissenborn said.
Stakeholders at the meeting asked MISO to involve the Independent Market Monitor in drafting Tariff language. Others urged the RTO to consider the extraordinary incidental costs of weather-related events, such as utilities providing lodging and meals for working employees when their homes have been destroyed.
Weissenborn said he would return to the Market Subcommittee in November for more discussion. He said MISO may convene a special stakeholder group to help create the pricing structure.
VALLEY FORGE, Pa. — PJM staff have incorporated stakeholder input into their recommendations resulting from the quadrennial review of the variable resource requirement demand curve, the RTO’s Jeff Bastian told last week’s Market Implementation Committee meeting.
Staff have decided to recommend no changes to methodologies for several figures, while reducing the cost of new entry values by several hundred dollars, Bastian said.
He said staff hadn’t come to a decision yet on whether major maintenance costs should be included in fixed or variable operations and maintenance calculations.
“We’ve got to go with one or the other. We can’t have two VRR curves,” he acknowledged.
Review of Fuel Cost Policy Rules
Stakeholders endorsed a problem statement and issue charge to review several parts of the fuel-cost policy (FCP) rules and cost-based offer procedures hashed out last year. Sponsor John Rohrbach, who represents ACES on behalf of the Southern Maryland Electric Cooperative, said he is seeking “some modest discussions” to fix “little mistakes.” The proposal was also sponsored by Old Dominion Electric Cooperative and Panda Power Funds.
Rohrbach suggested that the rules could potentially be improved to determine whether self-scheduled units and zero-marginal cost wind and solar generators need FCPs. Rohrbach also questioned whether generators should have to confirm annually that their FCPs remain compliant and suggested creating a “safe harbor” from regulatory action for “minor” FCP violations and crediting generators for self-reporting potential violations.
It would also address timing issues that can arise when units change ownership.
Transmission Constraint Relaxation Removed
Stakeholders also endorsed new language in Manual 11 allowing transmission constraint penalty factors to set shadow prices for violated constraints. The current practice of relaxing transmission constraints doesn’t let the penalty factors set prices, which results in inefficient clearing prices that don’t reflect market conditions, PJM’s Angelo Marcino explained. The proposal, developed jointly by PJM and its Independent Market Monitor and resulting from an IMM problem statement was also preferred over the status quo.
Marcino said PJM won’t be making changes to market-to-market transmission paths until MISO and NYISO have upgraded their systems, which he said isn’t likely until at least next April.
Exelon’s Sharon Midgley thanked the Monitor and PJM for providing analysis on market impacts that helped her company become comfortable with the proposal.
The Monitor previously determined that in 2017, the revisions would have increased net load payments by $13.5 million, or 0.06%, and increased net generation credits by $10.1 million, or 0.04%. (See “Transmission Constraint Penalty Factor,” PJM Market Implementation Committee Briefs: Aug. 8, 2018.)
Automating Offer Confirmation
PJM’s Susan Kenney detailed the RTO’s plan to automate verification of price-based offers above $1,000/MWh to ensure they don’t exceed the reference cost-based offer on price-based segments.
Kenney said the price-based offers will be capped at $1,000/MWh unless they have the same megawatt blocks, use of a bid slope and fuel type as the referenced cost-based schedule, along with lower start-up offers, no-load offers and incremental energy curve prices per segment. Additionally, the price-based schedule must be updated whenever the cost-based schedule is decreased.
The requirements concerned Gary Greiner of Public Service Electric and Gas, who questioned whether the proposed changes came about as the result of challenges and time delays associated with the new bid verification process or simply for administrative ease.
“I like the flexibility of being able to bid our units in the most creative way we can,” he said, adding that PSE&G wouldn’t support the changes if their only goal is convenience.
Credit Debate
PJM’s Hal Loomis presented a proposal to allow market participants to provide surety bonds as credit for all activity except financial transmission rights portfolios. Surety bonds have different legal language but are “a parallel” to letters of credit the RTO already accepts as collateral, CFO Suzanne Daugherty explained.
However, Monitor Joe Bowring was concerned that surety bonds rely on rating agencies. When staff indicated ratings agencies are reliable, Bowring responded that the agencies’ involvement in the 2008 financial crash “might indicate that’s not quite accurate.”
Daugherty responded that the agencies have undertaken many changes since then. In response to a question from Bowring, she said staff compared best practices with other regional grid operators but didn’t go beyond that to ask other exchanges. She said surety bond issuers used to be too inflexible for energy market needs — requiring an itemized list of claims they might have to pay — but have since become much more “comfortable” with the industry’s needs.
Another “key difference,” she said, is that surety bond issuers, which have a right to investigate and request documentation before paying claims, now generally must pay within 30 days. They previously had no time limit.
PJM’s experience with letters of credit is that they are paid within two days without any investigation, she said, because the banks usually have other collateral. But she said staff does not anticipate a “daunting difference between the two.”
A proposal developed by the PJM Credit Subcommittee would have a $10 million cap per issuer for each member and a $50 million aggregate cap per issuer.
Exelon’s alternate proposal would allow using surety bonds for all credit requirements with a $20 million cap per issuer for each member and a $100 million aggregate cap per issuer. ERCOT and NYISO allow use of surety bonds with lower caps, Exelon’s Midgley said, but higher caps are necessary in PJM because its peak load is twice that of ERCOT’s.
“We see this as a cost-saving opportunity for members” that will also allow diversification, Midgley said. Since both proposals structure surety bonds like letters of credit, Exelon’s proposal would allow surety bonds to be applicable to all market activity, consistent with letters of credit. PJM staff said the proposal was acceptable.
MISO declared a maximum generation alert at noon Monday, saying tight reserve levels amid forced outages, hotter-than-expected temperatures and higher-than-forecasted load could prompt emergency procedures.
The action followed a string of notices and alerts over the weekend. On Saturday, the RTO ordered conservative operations for its entire footprint until midnight Wednesday.
Load hit 112,907 MW at Monday’s 4 p.m. peak. Real-time LMPs ranged from $22/MWh in Minnesota to $82/MWh in Michigan.
MISO peak load and pricing on Sept. 17 | MISO
Last week, MISO said it had prepared for summertime conditions in September, in keeping with trends over the last three years. At the time, some stakeholders expressed doubt over the 19% probability the RTO gave itself of entering emergency procedures at least once this fall, with some saying the chance of an emergency was greater. (See MISO Sees Small Chance of Fall Emergency Procedures.)
Beginning on Saturday, MISO requested that generation and transmission owners defer or cancel all nonessential maintenance outages, asking that utilities reach out to coordinate returns to service.
In a Sept. 15 tweet, MISO said it was monitoring conditions in a hotter-than-usual MISO South, where Entergy issued public appeals to conserve energy on behalf of the RTO. Entergy said it was experiencing a “critical” shortage of electricity. MISO’s declaration of a maximum generation event requires members to make public conservation appeals and allows the RTO to make emergency power purchases to avoid load shedding.
“We appreciate our customers’ help in meeting power needs during this time by turning off all non-essential lighting, appliances and electronics as well as raising thermostats to 78 degrees. If possible, reduce use of water heaters, electric ovens, washing machines and dryers,” Entergy asked. The company eventually terminated the appeal for conservation at 6:30 p.m., hours earlier than MISO’s original prediction of 11 p.m.
19% Chance
At the Sept. 13 Market Subcommittee meeting, MISO officials said they had sufficient resources to cope with unseasonably warm conditions again this fall.
The RTO estimated a 19% chance that it would invoke emergency operating procedures to call on load-modifying resources (LMRs) this fall. Those resources are not obligated to respond when called upon after Sept. 1. MISO expects to have about 11.8 GW of available LMRs, based on availability forecasts provided by resource owners.
The RTO forecast a 110- to 120-GW peak load for September and said it prepared for loads more in line with summer conditions. The National Oceanic and Atmospheric Administration predicts above-normal fall temperatures for the MISO region.
“September generally aligns more closely with summer system conditions, at least for the last few years,” said Jeanna Furnish, MISO manager of outage coordination.
Furnish said MISO has so far this month experienced loads topping out at 114 GW, within about 1 GW of peak fall loads over the last three years.
For the last four years, MISO’s actual fall peak load has trended about 5 to 9 GW higher than load-serving entities have forecasted in 50/50 probability forecasts.
Furnish said MISO expects a 10- to 15-GW increase in planned outages from the end of September to the end of October, when load is projected to be lower. Navigating the outages will be “challenging, but manageable,” similar to the RTO’s experience in recent years.
After some stakeholders expressed confusion over the 19% statistic, MISO Executive Director of Market Development Jeff Bladen clarified that the RTO is not saying it will spend 20% of the fall in emergency operating procedures.
“There’s a 20% chance that we will go into emergency operating procedures at least once this fall,” he explained.
Some stakeholders wondered if MISO’s prediction was optimistic. Minnesota Public Utilities Commission staff member Hwikwon Ham pointed out NOAA predictions of a 40 to 60% chance of a major storm forming in the Gulf of Mexico last week.
During the meeting, stakeholders also received an emailed capacity advisory notice for a possible shortage on Sept. 17 owing to outages and residual weather conditions from Hurricane Florence. MISO rolled out the new notification system in August for situations when its all-in capacity is forecast to be less than 5% above operating needs. (See “New Notification System,” MISO Moving to Combat Shifting Resource Availability.)
CARMEL, Ind. — MISO plans to hold a final Order 841 workshop on Oct. 10 to complete its collection of stakeholder opinions on its storage participation model, which will include an agreement for distribution-level storage but leave storage dispatch optimization to a later filing.
Here’s what the RTO has decided thus far.
Pro Forma for Distribution-connected Storage
MISO’s draft pro forma agreement for storage connected at the distribution level requires storage:
Be registered and modeled in MISO;
Secure agreements with distribution facilities so energy can be delivered to the MISO transmission system;
Be able to receive MISO operating instructions; and
Provide MISO with facility measurements and settlement meter data.
The agreement also specifies that MISO will make sure a storage resource owner isn’t charged twice for energy when it pays retail rates for wholesale charging. MISO said it will exclude the charging energy from wholesale rates in its settlements.
During a Sept. 13 Market Subcommittee meeting, Coalition of Midwest Power Producers CEO Mark Volpe asked if the agreement opens an avenue for distribution-connected storage assets to avoid MISO’s interconnection queue.
“This is not a way to circumvent the interconnection queue,” Director of Market Design Kevin Vannoy said.
“So you’re saying that distribution-level storage must go through the interconnection queue?” Volpe asked.
“I don’t have a definitive answer for that,” Vannoy responded.
Consumers Energy’s Jeff Beattie pointed out that many qualifying facilities that utilities must purchase power from under the Public Utility Regulatory Policies Act are connected at the distribution level.
Canned Corn
The Energy Storage Association’s Rao Konidena, formerly a MISO adviser, brought a can of corn with him to the MSC podium.
Storage, he said, is like a can of corn.
“We know what’s in there; we know how it’s used,” he said. MISO’s remaining piece is finalizing storage rules for an asset whose purpose is already understood. He said storage owners should be able to toggle hourly between offering energy and ancillary services and have the option to self-dispatch.
Konidena said storage asset owners must be able to enter offline mode without fear of being cited for physical withholding. “We need to have enough clarity to know that asset owners will not be penalized as they come back online,” he said.
No Optimization Yet
MISO is not ready to optimize storage resources’ energy schedules in the day-ahead or real-time markets. That means the RTO won’t pick the best and most economic hours for a battery or other storage resource to charge or discharge.
MISO said it will commit and dispatch storage respecting minimum and maximum charge limits and any self-scheduled offers. But it said its unit commitment calculations cannot be easily changed to optimize storage in charge/discharge or continuous modes across multiple periods.
Vannoy said participation must be accommodated per Order 841, but MISO should not have to change existing market services to accommodate storage. He also said FERC’s order has already suggested that storage resources will represent their energy limitations through offer prices.
“We don’t see it as a requirement of 841 that we change our optimization calculation,” Vannoy said. “We’re taking this into our research and development, and it will become more important as storage becomes more prevalent. But right now, we’re not prepared given the timeline, nor is it required in our mind.”
Storage Capacity
Meanwhile, MISO is moving forward on a multistep capacity determination process for storage resources.
The process involves a test verifying the storage facility’s capacity and its transmission deliverability. The resource must provide quarterly reports to MISO’s generating availability data system (required for storage resources 10 MW and up). The RTO will use the data to calculate an equivalent forced outage rate, installed capacity and unforced capacity for the resource.
Storage resources that are designed with limited output availability will also have to submit a day-ahead must-offer for at least four continuous hours covering the two hours before the peak, the peak hour and the hour following the peak hour. MISO forecasts its daily peak hour seven days in advance.
“It’s not really unique to storage capacity resources,” Senior Adviser of Capacity Market Administration Rick Kim said of the proposed accreditation process during a Sept. 12 Resource Adequacy Subcommittee meeting.
But Customized Energy Solutions’ David Sapper said the storage must-offer rule for use-limited resources might be too restrictive for an RTO that is trying to place more emphasis on supply flexibility in an environment where a peak risk can occur in during several different hours, not just the summer peak hour that MISO currently plans around. (See MISO Looks to Members for Load Forecasting Ideas.)
“It ignores the operational characteristics of storage,” Sapper said.
Vannoy pointed out that the use-limited description is an optional designation, left up to the owners of storage resources. He said even use-limited storage resources are free to offer for 24 continuous hours.
MISO plans to introduce draft Tariff language for storage capacity credit at next month’s MSC, Kim said.
PJM saw its frequency drop to 59.903 Hz at 3:49 p.m. as its area control error fell 2,942 MW below its target. The RTO said the incident resulted from multiple unit trips, non-approved real-time security-constrained economic dispatch (RTSCED) cases, a drop in Eastern Interconnect frequency and poor synchronized reserve response.
Staff made recommendations for all but one of the causes. Removing ambiguity in operating procedures regarding parameter-limited schedules would address units called online that didn’t respond. Analyzing unit-tripping trends would help determine why multiple units tripped. Creating a procedure that helps dispatchers decide whether RTSCED data is valid based on system conditions would address why the RTSCED cases weren’t approved during the incident.
PJM also plans to stop approving time error corrections during emergency procedures or frequency excursions, which it said can exacerbate problems.
“It takes several hours at a lower frequency to get that time error back; there’s kind of an inherent risk whenever [you] go off 60 Hz,” PJM’s Donnie Bielak said. He added that simply scheduling time error corrections at night also isn’t a good idea because it would push units into minimum-generation operations that don’t allow them full flexibility to respond to other system changes.
Bielak said an unexplained drop in frequency across the entire Eastern Interconnection accounted for half of the problem.
“We’re certainly looking to get to the bottom of that,” he said.
PJM’s Jim Snow presented the RTO’s preliminary project budget for 2019, which anticipates spending approximately $42 million on capital expenditures. The vast majority — approximately $39 million — will go to existing assets, including applications, systems reliability, replacements, facilities and infrastructure.
In response to a stakeholder question, Snow said about $4.4 million in projects were considered but deferred, including hardware replacements, enhancing existing monitoring tools, automating the Regional Transmission Expansion Plan and other corporate reports, implementing soak time by adding generator ramp time to day-ahead markets, and implementing a tool to register energy efficiency and non-retail behind-the-meter generation.
“This is part of a larger process,” Snow said.
At a separate presentation before the Planning Committee later in the week, Snow confirmed that the budget can be revised to address any issues that arise that require commitments from PJM.
“I would tell you if FERC issued an order, we would go back and reprioritize,” he said.
The response satisfied Greg Poulos, the executive director of the Consumer Advocates of the PJM States.
“I want to make sure there’s enough resources allocated to the Planning Committee to make sure they can get their job done,” he said.
PJM’s Christina Catalano introduced two changes to reactive transfer interfaces, which the RTO uses to control voltage contingencies associated with high transfers during transmission outages.
The Central Pennsylvania interface, which includes the Lackawanna-Hopatcong, Sunbury-Juniata and Susquehanna-Wescosville 500-kV lines, was modeled to accommodate an increase in gas-fired generation in the region and planned maintenance outages on the 500-kV system. One such outage is planned for Oct. 16-20.
Catalano said staff anticipate the interface only becoming significant during the outage in case a second transmission line goes out. PJM’s Paul McGlynn said “additional contingency would go beyond any criteria we have.”
In the Western Interface, staff are adding the new Vinco substation near Conemaugh on the 500-kV line to Hunterstown. It will become effective when the Vinco substation is energized, which is expected on Oct. 16. Because of its proximity to the Conemaugh substation, staff expect minimal impact.
MISO recently announced that its Value Proposition provided annual quantitative benefits of $3.3 billion to its members during 2017. In the past, MISO has announced similar levels of overall monetary benefits attributable to its Value Proposition; however, over the years, based on the business decisions of numerous merchant-owned generation companies in MISO, including the non-regulated generation arm of several utilities, the overall value MISO membership provides the independent power producers is undoubtedly questionable at best.
The gradual exodus of merchant generation out of MISO began in 2009 when FirstEnergy announced it would leave MISO and consolidate all its assets from their wholly owned subsidiaries American Transmission Systems Inc. and the non-regulated generation fleet of FirstEnergy Solutions into PJM. Anthony J. Alexander, president and CEO of FirstEnergy at the time, stated, “Aligning all of our transmission assets with PJM will provide customers with the benefits of a more fully developed retail choice market and enhanced long-term planning that supports construction of new generation when and where it is needed.” Quickly following suit, Duke Energy announced in May 2010 that its Ohio and Kentucky utility subsidiaries would quit MISO and join PJM. An industry analyst observed that “Duke’s motives were clear, and the move was widely ascribed as a bid to cash in on the substantial revenues available in PJM’s capacity market, the Reliability Pricing Model (RPM), which had proven much more lucrative than MISO’s much less formal monthly voluntary capacity auction. FirstEnergy already had sought the same advantages.”
| Coalition of Midwest Power Producers
After the Ohio companies left MISO, in a surprising turn of events during 2012, unable to find a buyer after a long-term power purchase agreement had expired, Dominion Resources announced it would shut down their 574-MW Kewaunee nuclear reactor located in Wisconsin. What made this decision somewhat puzzling at the time was EPA’s focus on clean air regulations; however, Dominion had made the decision to forge ahead with decommissioning its environmentally friendly nuclear facility. The following year, St. Louis-based Ameren announced the sale of its entire non-regulated generation portfolio located in downstate Illinois to Dynegy (recently merged with Vistra Energy) to focus on its rate-regulated electric, natural gas and transmission operations and remove $825 million in debt from its balance sheet. Dynegy paid no cash in acquiring all of Ameren Energy Resources coal units totaling 4,119 MW — only assuming the debt.
In 2014, Tenaska Capital Management, owner of a highly efficient, natural gas-fueled combined cycle facility New Covert merchant power plant in Michigan, announced plans to directly interconnect the 1,100-MW plant with PJM in June 2016. Tenaska invested millions in the construction of a new substation, a 345-kV transmission line and significant transmission system upgrades to literally build their way out of MISO. New Covert had cleared capacity in PJM’s RPM auction in May 2013 and May 2014. Tenaska Senior Vice President Brad Heisey stated, “PJM is a good fit for merchant wholesale generators such as New Covert. It has a balanced, forward-looking capacity market that should provide certainty for covering the facility’s fixed costs.” The same year, Calpine sold their Mankato Power Plant, a 375-MW natural gas-fired, combined cycle power plant located in Minnesota, to Southern Co. subsidiary Southern Power for $395.5 million plus working capital. Calpine President and CEO Thad Hill said, “Mankato is a modern, efficient and well-performing plant under long-term contract to the local utility with an expansion in advanced development. This sale is another step in our capital allocation plan to divest plants in non-core regions when we see an attractive value opportunity.” Another major MISO merchant player, NRG Energy, recently announced its intention to sell its entire 3,555-MW South Central business to Cleco Corporate Holdings for $1 billion.
The slow death of merchant generation in MISO has been pervasive with more than 25,000 MW exiting MISO over the last decade. The strategic motivation behind several of these companies’ business decisions is very clear: monetize assets in MISO to optimize their generation portfolios for participation in the better designed eastern U.S. capacity markets. None of the companies have folded their tents and gone out of business! They can operate successfully and turn a profit in markets other than MISO. These companies decided better opportunities could be found by deploying their capital resources elsewhere. This chain of events is not a coincidence, and in our next column, we will analyze the underlying circumstances behind these business decisions forcing the independent power producers to leave MISO.
Mark J. Volpe is the President & CEO of the Coalition of Midwest Power Producers (COMPP), a newly formed non-profit trade association focused on the continued evolution of fully robust wholesale energy and capacity markets in MISO. He is the former Senior Director of Regulatory Affairs for Dynegy Inc. and continues to serve as chairman of the Independent Power Producer sector on MISO’s Advisory Committee working actively within the stakeholder process at MISO and PJM advocating on energy and capacity market design issues.
