Stakeholders got a first look at the preliminary projects resulting from MISO’s yearly market congestion planning study during the July 19 PAC meeting. The RTO has so far floated three potential projects in the West of the Atchafalaya Basin (WOTAB) area straddling Texas and Louisiana:
A new $137.6 million 500-kV line and substation expansion from Hartburg to Sabine in southeastern Texas that would qualify as a market efficiency project and is expected to be in service by 2023.
A $2.8 million replacement of 26 transmission structures along the Sam Rayburn-Fork Creek-Doucette 138-kV line in southeastern Texas, expected to be complete by 2020.
Equipment upgrades valued at $500,000 for the existing Carlyss substation in southwestern Louisiana by 2020.
Arash Ghodsian, MISO manager of economic studies, said the RTO’s market congestion planning footprint diversity studies will produce final project recommendations in August. Project candidates will be submitted for approval by the Board of Directors at the end of the year. (See “Studies Could Assist in Relieving North-South Constraint,” MISO Planning Advisory Committee Briefs.)
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MTEP Siting Up for Review
MISO is also planning on updating siting guidelines for projects included in its Transmission Expansion Plan.
This year’s siting model will be slightly altered to add likely wind and solar zones. MISO will also consider zonal resource adequacy requirements when determining siting and exclude thermal unit development from non-attainment areas subject the National Ambient Air Quality Standards.
The RTO plans to further improve its siting modeling process for the 2019 cycle through a series of stakeholder workshops that will begin in September. Matt Ellis, a MISO policy studies engineer, said the overhaul will focus on the placement of new technology, including 100 MW of queued energy storage resources, future utility-scale renewables, rooftop solar — predicted to reach 10 GW by 2027 — and the addition of more electric vehicles and their demands on load.
Ellis said projects in the interconnection queue generally exhaust themselves within a three- to five-year cycle, but MISO plans for its transmission system 15 years into the future.
He also asked for stakeholders to submit ideas by Aug. 11 on how MISO’s siting process can account for new technology.
MISO will also conduct a multi-value project triennial review this year, sizing up its existing portfolio and quantifying benefits. FERC requires a full review of the approved portfolio benefit every three years.
Project manager David Lucian said the review will have no effect on cost allocation for existing projects, but findings could be used to adjust project criteria in future projects. The review includes analyses of economic benefits, generator flexibility, renewable target standards, natural gas risks and job creation.
MISO last conducted an MVP triennial review in 2014, concluding that the portfolio held a benefit-to-cost ratio ranging from 2.6 to 3.9 and should create anywhere from $13.1 billion to $49.6 billion in net benefits over the next 20 to 40 years.
The triennial review report will be filed with FERC by the end of the year, PAC Chair Cynthia Crane said. Results will also be published in the MTEP 17 report due in December.
SAN DIEGO — New electricity business and regulatory models will be needed in the U.S. to transition to a future with more distributed and renewable resources, changing customer needs and new technologies, market participants and regulators said this week.
Industry representatives and state regulators gave an overview of the changing landscape at the National Association of Regulatory Utility Commissioners Summer Policy Summit. Common themes were the growth of distributed resources, managing large amounts of new renewables and developing fresh approaches as more electricity consumers also become producers.
Pacific Gas and Electric CEO Geisha Williams said that the key is to implement renewables, distributed generation and other new technologies “and not leave anybody behind.” About 40% of the utility’s customers are low-income, and they should not have to choose between paying for electricity and other critical expenses such as health care, she said.
The model of billing energy consumers purely based on the amount of electricity they use is becoming obsolete, Williams said. “That model is fundamentally at risk at this point.”
Many electric consumers are also producers, as behind-the-meter and distributed resources grow. Retail energy sales in the future “may very well likely not be a one-size-fits-all,” she said, similar to how mobile phone users have different data plans because they have widely different needs. This could entail using a tiered approach, service and access charges and new incentives for capital investment.
It is important that regulators and lawmakers put the right policies in place to implement new technologies and practices in an affordable way, Williams said, adding that “affordability is a strategic imperative to us.”
The country’s generation and distribution systems “are really undergoing a period of very dramatic change,” Nuclear Energy Institute CEO Maria Korsnick said. She contended that nuclear, particularly small modular reactors, should play a role in maintaining clean and affordable energy.
“Small modular reactors could be game-changers in many respects,” Korsnick said, providing smaller increments of power compared with a large central station plant and giving utilities more discretion in meeting demand. Modular reactors can also bring off-grid power to remote places and cycle up and down like a natural gas plant — but with no emissions.
In Pennsylvania, distributed resources are “popping up as a result of new opportunities,” Public Utility Commissioner John Coleman said. The agricultural sector is learning that biodigesters can help manage waste products while producing electricity. The question is to how to compensate these new resources.
As for the traditional ratemaking model: “Maybe it is at risk,” Coleman said. “Maybe it is time to start thinking of some of these things in a different way.”
The Pennsylvania PUC is surveying industry on new compensation approaches and ways to incentivize investment. He noted that the majority of the state’s consumers are served by competitive suppliers and electricity rates have dropped by about 30%. Natural gas plants are also rapidly replacing coal-fired units in the state.
Other than distributed resources, utility-scale generation is also changing, according to Ohio Public Utilities Commissioner Beth Trombold. The state has a potential 8,000 MW of new gas-fired generation coming online, with four gas plants under construction, one certified and four more under review. There is about 1,200 MW of new wind and 400 MW of new solar waiting in the wings, which will greatly increase the amount of renewables in the state.
Ohio is also in the middle of a grid modernization program and asking, “What kind of regulations and technological innovation are out there to enhance the customer-utility relationship?” Trombold said.
California Public Utilities Commission Chairman Michael Picker said that integrating renewables in the state has not been as challenging as was feared, and it is now more important to consider where they are placed.
Legislation is in the works in California to achieve a zero-carbon electricity grid by 2045 and the state recently extended its cap-and-trade program to 2030. (See California Lawmakers Extend Cap-and-Trade.)
“At this point, it’s not about getting more, it’s what you get, where you get it … and when it’s available,” Picker said of renewable generation. The state is experiencing lower electricity demand overall but higher peaks. The PUC is moving away from “silos” in terms of what kind of resources are put on the grid, but back to an integrated resource plan model, he said.
In terms of reducing greenhouse gases, more of the transportation sector must be electrified, he said. The transportation sector emits 40% of GHG in the state; gas for heating and other uses emit about 30%, while just 20% is emitted from the electricity generation.
CAISO will lean heavily on increased output from conventional generators — and a backstop of regulation reserves — to fill the void left by reduced energy production from California solar resources during next month’s solar eclipse.
The grid operator estimates that about 4,194 MW of utility-scale solar will fall off the system from the time the moon begins to pass in front of the sun (9 a.m.) to the moment of peak obscuration (10:22 a.m.) during the Aug. 21 event.
Graph shows a comparison between CAISO’s Aug. 21 eclipse load forecast compared with that for full-sun conditions. | CAISO
At the peak, grid-connected solar generation will come up about 5,600 MW short of what would be expected under full-sun conditions. Net load will surge to about 6,000 MW above normal because of diminished output from rooftop installations.
But the grid operator has been preparing its response since last year. (See With Solar Eclipse Looming, CAISO Weighs its Options.) After a winter of ample precipitation, “large and fast-moving” hydroelectric resources are being positioned for rapid response during both the loss and return of solar, according to Deane Lyon, a CAISO real-time operations shift manager.
Planners are also banking on gas-fired generators to help cover the gap.
“We’re actually working with Pacific Gas and Electric and [Southern California Gas] and coordinating with their gas control centers because, besides the hydro, the gas-fired thermal is going to have to make up for a lot of the loss of solar generation,” Lyon said Tuesday during a bimonthly Market Performance and Planning Forum.
The ISO will also procure about 900 to 1,200 MW of regulation up reserves for the three-hour period affected by the eclipse — compared with a typical procurement of 300 to 400 MW.
“That’ll help us manage as the solar goes away,” Lyon said.
Lyon noted that CAISO has been consulting with Western Energy Imbalance Market (EIM) participants to develop a “consistent policy” regarding transfer service requests (ETSRs) — or dynamic transfers across balancing areas — during the eclipse so that the ISO can take advantage of imports to the greatest extent possible.
“We got commitments from the operations folks at the EIM entities that they’re willing to keep the ETSRs wide open and fully operational for the balance of the eclipse,” Lyon said, acknowledging that the ISO does not expect a “huge” uptick in transfers given that Arizona Public Service and NV Energy will also be losing solar off their systems at about the same time.
On the flip side, the eclipse is not expected to actually undercut imports.
“APS has solar, but not PacifiCorp,” Lyon said. “We don’t expect it will have that big of an effect.”
Paula Lipka, of PG&E’s short-term electricity supply team, asked if the ISO intends to increase its procurement of flexible ramping and spinning reserves — as well as regulation.
“An increase in flex ramp procurement is being considered. As far as spinning and non-spinning reserves, we will have adequate amounts of that,” Lyon responded.
Regulation reserves are the ISO’s key concern.
“We’re trying to maintain our system balance for the duration of the sun going away and returning, which is going to be a pretty big challenge,” Lyon said.
SPP is accepting applications from industry experts to serve on an independent panel reviewing the RTO’s 2018 competitive transmission construction proposals.
The panel will review, rank and score proposals for competitive projects under FERC Order 1000. The previous two panels recommended one such project — a 22.6-mile, 115-kV line from Walkemeyer to North Liberal in southwest Kansas. However, the project was withdrawn because of decreased load projections. (See SPP Cancels First Competitive Tx Project, Citing Falling Demand Projections.)
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Interested candidates must have expertise in at least one of the following transmission-related areas:
Engineering design;
Project management and construction;
Operations;
Rate design and analysis; or
Finance.
SPP will accept applications through Sept. 1 and choose panelists later this year based on recommendations by the RTO’s Oversight Committee, which must be approved by the Board of Directors. Selected panelists will be considered contractors and will be compensated through a monthly retainer and hourly rate.
Panelist applications, instructions and more information can be found on SPP’s website or by contacting Ben Bright, the RTO’s regulatory processes manager.
MISO has introduced a three-step checklist that owners of behind-the-meter (BTM) generation can use to prove deliverability for the Planning Resource Auction, but some stakeholders are calling foul on the differing auction requirements.
The three-pronged approach will involve different sign-offs from affected load-serving entities, transmission owners and MISO. The LSE will determine whether the BTM customer can participate in the wholesale or retail market, while the TO will ascertain study requirements for access to the transmission system when the BTM generator interconnects to a non-transferred facility. The RTO will determine the resource’s deliverability or transmission service procurement in order to use the transmission system.
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“This is meant to provide some guidance on the more intricate relationship between LSEs and TOs,” MISO Manager of Resource Adequacy John Harmon said during a July 12 Resource Adequacy Subcommittee meeting. “MISO is not looking to gain new authority in this endeavor; we’re trying to stay within the bounds of our Tariff.”
Since the beginning of the year, MISO staff have been grappling with deliverability rules that would allow BTM generation in excess of a utility’s planning reserve margin requirement — but without existing transmission service — to enter the annual capacity auction. The RTO last month proposed requiring that a BTM resource submit to an optional engineering study to identify a deliverable volume of capacity eligible to be bid into a single auction. However, the study would have only temporary value. The resource would then be required to enter the same volume into the interconnection queue study process before offering capacity into any subsequent auctions. (See MISO Proposes Deliverability Rules for Behind-the-Meter Capacity.)
Harmon said MISO is proposing to adopt the optional study avenue for two planning years until June 1, 2019. After that, resource owners will have to enter the interconnection queue.
Deliverability amounts discovered in the optional study will have a “limited applicability” and will not be used to determine deliverability in the interconnection queue process, Harmon said.
Indianapolis Power and Light’s Lin Franks asked why BTM generation should essentially be treated as “free riders” on the grid, and not supported by utility aggregators.
“I don’t know of any place where behind-the-meter generation [has] paid for transmission service. They’ve paid nothing whatsoever for access to the Bulk Electric System,” Franks said. “There are some holes.”
Harmon said BTM will only have access on an as-available basis, and that the proposal is an “interim solution” to ushering BTM generation into a more formal interconnection process.
Dynegy’s Mark Volpe asked if MISO was proposing a go-around to the rules that every other capacity resource has to abide by.
“You’ve got a gigantic comparability issue here,” Volpe said.
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Harmon pointed out that before this year, excess BTM generation was delivered undetected. “We think there’s good cause for a transition period,” Harmon said. He also added that the proposal might not be “100%” yet, but that MISO and stakeholders are striving toward the same goal.
He asked for additional stakeholder feedback on the deliverability proposal by July 26.
PRA Qualification Deferral to Become a Reality
MISO will file Tariff changes this fall to give certain capacity resources the option for additional time to qualify for the PRA.
The deferral will also be spelled out in the Business Practices Manuals and will allow certain resources to postpone completion of generator verification tests or installed capacity value calculations until after the auction. Capacity resource owners that intend to defer must inform the RTO before Feb. 15 and complete a generator verification test no later than May 31 in order to participate in the upcoming planning year.
MISO uses the verification test to determine the total capacity that a planning resource can reliably provide based on performance and availability data for summer peak conditions.
The draft BPM language states that the deferral is for untested new planning resources, existing resources “returning to operation from a catastrophic outage or suspension,” resources in the midst of increasing capability, suspended resources and resources “awaiting other miscellaneous resource approvals to achieve commercial operation.”
Analyst Scott Thompson said deferrals could also be used by intermittent capacity resources that have yet to come online at the time of the auction or generators that are completing environmental upgrades that prevent operation.
Most load-modifying resources called up for the first time in a decade during MISO’s April 4 maximum generation event failed to respond properly to scheduling instructions, officials said last week.
MISO Manager of Resource Adequacy John Harmon said 19 LMRs — demand resources and behind-the-meter generation that provide capacity — responded to meet a maximum scheduling instruction of 715 MW during the emergency in MISO South. Four LMRs failed respond at all and will face penalties under Module E of the RTO’s Tariff.
Harmon said the underperformance by some LMRs was offset by the larger-than-expected load reductions by others. The RTO was short about 25 MW of scheduling instructions in the last hour of the emergency declaration.
He stressed the importance of LMR owners providing accurate load curtailment capability to MISO every day. “It’s important that LMRs update their availability daily in the MISO communication system. Our operators rely on these each day and … are banking on the numbers when the need could arise to shed firm load,” Harmon said at a July 13 Market Subcommittee meeting.
LMRs are only required to be available for emergencies during the summer peak season and do not have to be available during non-summer months. However, the plants must notify MISO when they are unavailable through the RTO’s communication system.
In May, the RTO promised to conduct a performance evaluation of the LMRs during the event. (See “Several Factors in Spring MISO South Maximum Generation Event,” MISO Market Subcommittee Briefs.)
April 4, 2017 Max Gen Event Conditions | MISO
MISO has calculated a total penalty of about $2,000 for the four LMRs that failed to respond. The revenue from the penalties will be allocated to all market participants with load in the Entergy Arkansas local balancing authority, and on a market load ratio share basis to the Entergy New Orleans, Louisiana, Texas and Mississippi LBAs.
The RTO will assess and begin to distribute penalties this week. The generators could avoid punishment if they can identify force majeure reasons that prevented them from responding.
Harmon said MISO will review its approach to training and operations drills to improve LMR performance. It also will review its current process and Tariff to make sure LMRs are “incentivized to update availability each operating day,” he said.
“We saw a lower rate of LMRs being able to meet the load reduction that they said they could meet. That suggests to us that market participants can tighten up the precision of the information that they provide to MISO on a daily basis,” Harmon said.
Executive Director of Market Design Jeff Bladen said there might be a disconnect between what market participants can provide in load curtailment and MISO’s scheduling instructions.
“The issue is when someone tells us that they can drop from 100 MW to 10 MW, and they’re operating at 70 MW and drop to 10 MW, that’s not a 90-MW drop; that’s a 60-MW drop. Whether there’s a penalty or not, we want to operate reliably. It’s not a question of right or wrong, it’s a question of can we operate reliably,” Bladen said.
The April 4 event was driven by unseasonably high temperatures and an unusually high amount of transmission and generation outages in MISO South. It prompted the Independent Market Monitor to call for greater MISO authority in approving maintenance outages. (See MISO South Outages Worry RTO, Monitor.)
VALLEY FORGE, Pa. — PJM last week presented Operating Committee members with a proposed pro forma agreement for dynamic schedules, saying it would eliminate potential confusion and improve reliability.
Dynamic schedules are power flows into the RTO from a generator that is controlled by and located in a different grid operator’s territory. Unlike pseudo-tied units, the flows are not modeled in PJM’s systems as internal supply.
Because PJM lacks a standard agreement for dynamic schedules, individual agreements may contain variations in language that can result in incorrect operating procedures, the RTO said.
Under PJM’s proposal, the native balancing authority would only need to acknowledge awareness of the agreement because it remains operationally responsible for the resource. Unlike pseudo-ties, dynamic schedules require tagging and are subject to curtailment under NERC’s transmission loading relief procedures, PJM’s Phil D’Antonio said.
D’Antonio said PJM hadn’t yet decided whether they would seek to make the agreement retroactively enforceable for existing schedules. The agreement will be brought to a vote at next month’s OC meeting.
PJM’s Jacqui Hugee gave the OC an update on additional Joint Operating Agreement revisionsMISO has requested relating to the pro forma pseudo-tie agreement. “For the most part, the changes are to clarify the language that is there,” she said. (See Late Agreement with MISO Forces Another Delay on Pseudo-Ties.)
Stakeholders voiced concerns about the language, but Hugee explained that PJM does not need, nor will it seek, stakeholder endorsement for the changes.
SCED Changes Implemented
PJM on Monday transitioned from a 15-minute to a 10-minute “look ahead” on its security-constrained economic dispatch (SCED) engine. The changes went into effect at 9 a.m.
PJM’s Joe Ciabattoni said the RTO will review the system’s performance after a week to ensure there are no reliability issues and evaluate whether to retain the changes. Ciabattoni said PJM does not need stakeholder approval to make the changes.
“We’re trying to better align real-time reserve levels with reserves calculated and dispatched by SCED,” he said. “Historically, we started with a 22-minute look ahead and have moved it over time to 15 minutes.”
Resilience Planning Moves Forward
PJM’s Jonathon Monken reviewed the RTO’s ongoing development of system resilience, noting that communication has expanded with related industries such as natural gas distributors. (See “Bryson Leads on Next Steps for Fuel Resiliency,” PJM OC Briefs.)
“I would expect that this will drive a lot of exercises and drills, recognizing that when we identify a vulnerability, we would much prefer to test it in an exercise environment than experience it in real life,” said Monken, senior director of systems resilience and strategic coordination.
He said that PJM is developing both internal and external roadmaps for enhancing resilience to severe weather, physical or cyber attacks or disruptions in fuel supplies. He also reviewed PJM’s Resilience Steering Committee, which includes himself and 14 other PJM staffers with responsibilities for various aspects of the plan.
John Farber of the Delaware Public Service Commission questioned using resilience as a driver for approving projects in the Regional Transmission Expansion Plan. While it was not listed on the current version of the external roadmap he presented, Monken confirmed that it is still a focus.
Farber warned that evaluation of resilience in RTEP projects wouldn’t be “as straightforward as described” and said completing quantifiable metrics by the end of 2018 is an aggressive timeline. “I would just note that the last time that PJM addressed drivers in the RTEP process … that took two and a half years. And those were, in my view anyway, difficult years,” he said.
“We certainly recognize the fact that we’re certainly not going to go faster than what the stakeholders would like it to go,” Monken said.
Ramp Rate Changes
PJM’s Cheryl Mae Velasco highlighted enhancements to its Markets Gateway online tool that will allow generators to adjust their regulation offers throughout the day instead of just once daily.
“The [web-coding] vendor had a chance to put them in,” Velasco said. “They’ve been on the backlog for quite a while.”
The announcement was met with appreciation, but also a request.
“These are items that could provide optionality in how we operate units, so to hear about it in the Operating Committee a week before [implementation] is, for me at least, problematic,” American Electric Power’s Brock Ondayko said. He asked that similar changes be brought to stakeholders’ attention “preferably” two or three months in advance.
“Once we found out [that the vendor had made the updates], we sent the communications out as soon as possible,” Velasco responded.
PJM’s Ken Seiler acknowledged Ondayko’s concern and said he would work with the RTO’s Tech Change Forum to provide earlier notice in the future.
Ciabattoni said that generators making changes to their ramp rates will not require corresponding price points in their cost-based offers.
PJM estimates a loss of up to 2,500 MW in solar output during the solar eclipse that will occur on Aug. 21. The event is expected to last about an hour.
While grid-connected and behind-the-meter systems will be impacted the same, the difference in deployed amounts means that grid-connected output is expected to drop about 500 MW, while BTM resources could drop about 2,000 MW. PJM expects it will need to increase non-solar generation by about 1,000 MW if it’s an overcast day and up to 2,500 MW if it’s sunny. Coordination will be important during the ramp up and ramp down periods.
PJM’s Joe Mulhern said the eclipse is expected in the middle of the afternoon when the sun is high and solar generation is near its peak output. If it’s a hot day, load will no doubt be near its peak as well, he said. However, a NERC analysis showed no reliability impacts are expected for the Bulk Power System.
PJM’s Glen Boyle announced that the Primary Frequency Response Senior Task Force will have its first meeting at 9 a.m. July 25, with monthly meetings to follow for at least six months. (See “PJM Defends Interest in Paying for Frequency Response,” PJM Markets and Reliability Committee Briefs.)
VALLEY FORGE, Pa. — PJM’s Lisa Morelli presented the Market Implementation Committee last week with revisions to the RTO’s proposal for handling intraday hourly offers in the energy market, delaying a scheduled vote on the plan.
The changes made to Manual 11: Energy & Ancillary Services since the first read on the proposal included a clarification that PJM’s real-time security constrained economic dispatch (SCED) uses data that are effective for the look-ahead solution interval rather than the case execution time. In response to feedback from the Independent Market Monitor, it also clarifies that a generator’s intraday opt-out election must be consistent with its fuel-cost policy.
“Resources should not be able to circumvent [market power] mitigation just by changing the relative levels of price versus cost,” Josyula said.
Luna focused on how generators can elect to opt out of intraday offers. PJM’s rules require that if generators change their price-based offer, they must also change their cost-based offer, he explained. “It’ll be easier for anyone who has a fuel-cost policy to say, ‘If I don’t have it in there, my default is to opt out,’” he said. “If no one changes their fuel-cost policies to incorporate hourly offers, it’s not clear how they can be compliant with the rule that has been presented because [hourly offers] can change your cost-based offer.”
It’s unclear whether the Monitor’s differences will result in separate proposals.
“It might be separate. We’re not completely there yet to say … they are, in fact, two different things. That might be where we end up in another round of conversations,” said PJM’s Chantal Hendrzak, who chairs the MIC.
Morelli also announced that all generators, no matter if they plan to update schedules hourly or not, will need to update their schedule IDs to PJM’s new list by Nov. 1. The RTO will be posting a step-by-step guide in its Markets Gateway online tool. With the implementation of intraday offers, PJM will only accept cost-based schedules 1-9, eliminating 70 others. The number of price-based schedules is being reduced from 19 to two.
PJM Indifferent on Black Start Fuel Compensation
Before presenting proposals from Calpine and the Monitor on calculating fuel-storage compensation for black start units, PJM’s Tom Hauske made it clear the RTO is agnostic to the voting results. He was repeatedly asked for PJM’s position, and he repeatedly declined to take one. (See “Started from the Bottom, Now We’re at the MTSL,” PJM Market Implementation Committee Briefs.)
“What we’ve taken as a position is that we can live with any of the three,” he said, including the status quo among the options.
The Monitor’s proposal would calculate the unit’s compensation for fuel storage — known as minimum tank suction level (MTSL) — based on the ratio of the fuel tank’s total volume to the amount of fuel needed to fulfill the black start requirements of 16 hours of continuous operation. The proposal from Calpine’s David “Scarp” Scarpignato would compensate units based on the average annual fuel volume in the tank.
Scarp and Monitor Joe Bowring sparred for a while on the merits of Scarp’s proposal. Bowring asked why “black start should pay an even bigger piece based on whatever random amount of oil is in the tank.” PJM currently pays about $500,000 per year in compensation for black start fuel storage based on current rules that pay for the entire tank. So either proposal would reduce the costs, the sponsors say.
The conversation between Scarp and Bowring eventually devolved into a fast-food metaphor focused on how much frying oil a restaurant would need to switch menu options. At the end, Scarp asked for clarification on whether his proposal would be set for a vote as an alternative to the Monitor’s proposal. When that was confirmed, he explained that he only meant for his proposal to spur discussion and asked that it be removed.
The vote at next month’s meeting will be on the Monitor’s proposal versus the status quo. Greg Poulos, executive director of the Consumer Advocates of the PJM States, announced his membership is leaning toward the Monitor’s proposal.
Energy Efficiency Kicked to Demand Response Subcommittee
PJM staff canceled plans to begin discussions in the MIC regarding rules for energy-efficiency products entering into the capacity market after stakeholders said they could resolve the issues more quickly through the Demand Response Subcommittee first. (See “EE Problem Statement Narrowly Approved,” PJM Market Implementation Committee Briefs.)
CPower’s Bruce Campbell pushed back on the change of venue, saying it will be difficult for the subcommittee to cover DR, the energy efficiency rules and how to address the impact of state policy initiatives on the markets.
PJM’s Pete Langbein warned that the four- to six-month timeline for results indicated in the energy-efficiency issue charge is “very aggressive.”
IMM Presents Problem Statements on Transmission
Bowring presented two problem statements and issue charges related to transmission concerns on first reading. The first problem statement and issue charge focuses on transmission penalty factors, for which he said PJM has no rules.
In its dispatch model, PJM allows transmission constraints to be violated under some conditions. The violated constraints have defined penalty factors that affect LMPs to reflect the local scarcity. Bowring says the penalty factor for a violated constraint should equal the shadow price — the incremental reduction in congestion cost achieved by relieving a constraint by 1 MW. PJM, however, uses “constraint relaxation logic” to affect the shadow prices, typically causing the shadow price to be slightly below the penalty factor, Bowring says.
Other grid operators, such as MISO, have explicit rules on the topic, he said.
In a presentation on the issue at the Members Committee webinar last September, Bowring recommended that PJM explicitly state its policy on the use of transmission penalty factors: the level of the penalty factors; the line ratings to trigger their use; the allowed duration of a violation; and when the penalty factors will be used to set the shadow price.
In asking you to approve this problem statement, I’m not asking you to agree with my characterization,” he told the MIC on Wednesday. “There are no rules. It should be written down. … I don’t know how long it’s been occurring at PJM — probably since the beginning.”
Morelli said PJM is in favor of the problem statement. “In addition to adding some consistency to how some of this works, it’s also taking a look at constraint reorganization where, essentially, we don’t allow the penalty factors to set price,” she said.
The second problem statement and issue charge focuses on pricing point alignment for cross-border transactions. The current procedure allows for “scheduling energy inconsistent with power flows” that “creates harmful market inefficiencies,” according to the problem statement.
“Our underlying principle is that pricing should be consistent with physical power flows — a radical concept, I know, but it’s not currently being implemented,” Bowring said.
VALLEY FORGE, Pa. — PJM said last week that a court ruling remanding a FERC order on the RTO’s minimum offer price rule won’t have any impact until the commission addresses the decision. And it may have little practical impact even after that, PJM’s Jen Tribulski told the Market Implementation Committee on Wednesday.
The July 7 ruling from the D.C. Circuit Court of Appeals said the commission overstepped its authority when it denied a 2012 proposal from PJM to revise its MOPR provisions but then spelled out to the RTO what it would approve. PJM’s proposal — a compromise between generators and load-serving entities — would have replaced the unit-specific MOPR exemption with two new ones and extended the mitigation period from one to three years before a unit could bid below the price floor.
Compromise Eliminated
FERC said it would accept the additional two exemptions if the unit-specific review were retained and the mitigation period remained unchanged. PJM agreed to FERC’s changes even though it eliminated the deal PJM stakeholders had made to secure stakeholder endorsement of the proposal. (See PJM MOPR Order Reversed; FERC Overstepped, Court Says.)
FERC’s ruling was vacated and remanded back to the commission, which must now write a new order for PJM. That can’t happen until the commission restores its quorum. (See related story, Trump Names Energy Lawyer McIntyre as FERC Chair.)
“The court really only ruled on the legal issue of whether FERC exceeded its authority under Section 205,” Tribulski said. “Until those rules are changed on remand, that’s our filed rate.” She acknowledged suggestions from stakeholders to revert to the previous rate or to PJM’s original proposal, but she said neither of those are appropriate because they are not what is currently approved by FERC and the court didn’t entirely vacate that approval.
PJM also isn’t planning to revise any auction results unless FERC orders a rules change. “We will wait to see what FERC does,” Tribulski said.
Gabel Associates’ Mike Borgatti asked how this might impact generators’ decision-making for filing exemptions, given that the exemptions for the 2018 Base Residual Auction must be requested by the end of this year. It will be at least until Aug. 28 that the ruling is even remanded to FERC, Tribulski said, noting a 45-day appeals period and another seven days following that for the order to become official. That also assumes the commission will have a quorum by then and be caught up on its existing backlog of filings.
‘Less than Meets the Eye’
She said there also might be “less than meets the eye here” because there haven’t been any unit-specific exemptions approved while the vacated rules have been in effect. Unit-specific exemptions are the part of PJM’s original MOPR proposal that FERC denied and recommended should be retained. “There may not be that big of an actual, practical impact,” she said.
Exelon’s Jason Barker said that as PJM is considering what parts of the ruling haven’t been vacated, the RTO needs to be aware that stakeholders still wouldn’t have had an opportunity to comment on them, which was a key part of the appeal.
“When FERC ‘imposes an entirely new rate scheme’ in response to a utility’s proposal, the utility’s customers do not have adequate notice of the proposed rate changes or an adequate opportunity to comment on the proposed changes,” the court said. “That was the case here.”
DENVER — SPP’s Z2 Task Force will likely soon be a relic of the past, but the issues with financial credits and obligations for sponsored transmission upgrades that spurred the creation of the group aren’t going away.
The Markets and Operations Policy Committee last week endorsed the task force’s request to conclude its work. Minutes later, SPP staff told the committee the RTO would have to resettle nine years of historical Z2 credits and obligations because of billing disputes, “minor” software defects and problems in calculating the present value of creditable balances.
SPP last fall identified about $200 million in revenue credits to be collected for transmission upgrades under its Tariff’s Attachment Z2, which details how to reimburse sponsors of network upgrades. The bills covered eight years of credits and obligations for 2008-2016, when staff failed to apply credits, complicating the task of trying to accurately compensate project sponsors and claw back money from members with debts for the upgrades. (See Preliminary Z2 Bills Released; Task Force Develops Options for Waiver Requests.)
SPP’s Charles Locke said the resettlement results will be similar to last year’s processing and stressed they will not produce duplicate or additional charges.
“What you pay or owe is only the difference between the original settlement and the resettlement,” he said.
However, Locke could provide few details beyond that. “Generally, the amounts will be small. I’m reluctant to say how small,” he said.
That drew pushback from members, some of whom could recall early staff estimates of $50 million for creditable transmission upgrade projects, which eventually ballooned to nearly $850 million in assigned costs. (See SPP MOPC Recommends 5-Year Timetable for Resolving $849M Z2 Bill.)
“Is there a number by what you mean by small?” asked ITC Holdings’ Marguerite Wagner. “It’s hard for me to understand what that actually means.”
“SPP assured us for years the amounts for Z2 were small, until they actually did the billing,” said Southwest Public Service’s Bill Grant. “I don’t get a lot of comfort when you say the amounts will be small. I do understand the reason, but it still tends to create regulatory issues for your members when they go back [to their commissions] and say, ‘Whoops! The calculations weren’t correct, so we’ll have to adjust it either up or down.’ It’s starting to get really painful.”
SPP COO Carl Monroe suggested that members focus on the difference between last year’s invoices and this year’s.
“What’s more important is the deltas,” he said. “We won’t know the deltas until we know the details of the resettlement. We won’t know the details until we go through the actual resettlement.”
Locke said staff intends to provide preliminary resettlement results in September, so members “at least have some indication of the numbers.” Staff will in September begin reprocessing data from March 2008, adding the months through July 2017. It hopes to post updated invoices in October to keep up with a timeline approved last year.
While chairing the Strategic Planning Committee on July 13, Golden Spread Electric Cooperative’s Mike Wise asked Locke whether the resettlement would be SPP’s last.
“We’re certainly hoping so,” Locke responded. “The last resettlement of historic data.”
In accepting the Z2 Task Force’s recommendation to let its charter expire, the MOPC also approved two recommendations from the group, with nine “no” votes (out of a potential 95 votes) and two abstentions. The first eliminated credits for non-capacity upgrades, such as substation facilities, while the second disposed of credits for short-term transmission service of less than a year.
The task force also reviewed the use of incremental long-term congestion rights (ILTCRs) as a substitute for Z2 credits — a practice by other RTOs — but was unable to reach consensus. The group said “significant concern” was expressed over SPP’s existing congestion rights processes and the “perceived lack of hedging.”
“Existing customers may prefer the risk of waiting on cash recovery versus getting ILTCR’s, which may have limited value in the future,” according to the task force’s recommendation to the MOPC.
“We feel like at this point in time, the task force has done what it can about whether or not there is something else we can do to reduce the burden of Z2 and replace it with something else,” the task force’s chair, Kansas City Power & Light’s Denise Buffington, told the MOPC. “After many, many, many meetings, we could not get to a decision on the underlying policy or whether to socialize those costs. Unfortunately, we are where we are.”
American Electric Power’s Richard Ross, who likes to hand out gold stars to his fellow stakeholders, said he was awarding Buffington a “Richard Ross Gold Star for Cat Herder of the Year.”
MOPC Suggests 1-MW Threshold for Network Load
It came down to a single vote, but the MOPC offered direction to the Regional Tariff Working Group on how to address “inconsistency and uncertainty” over which behind-the-meter generation qualifies as network load.
The committee directed the RTWG to use a 1-MW threshold for reporting network load and to develop a list of inclusions and exclusions. In a roll-call vote, the last member to record its vote pushed approval of the motion from 65% to 66.2% — just above the 66% necessary for passage.
For customers taking network service, SPP currently follows FERC policy that sets all load at discrete delivery points as network load, which effectively sets the threshold at 0 MW for load served by BTM resources.
“At least this gives some guidance to MOPC,” Monroe said, alluding to the difficulties the RTWG has had in tackling the issue.
“If so, then make every member of the MOPC charter members of the [RTWG’s] Billing Determinants Task Force, because that is what we spent two and a half years discussing,” said Oklahoma Gas & Electric’s David Kays, who chairs the RTWG. “If 10 members were in the room, we had 10 different exceptions. If 15 members were in the room, then we had 15 different exceptions.”
The RTWG, through the BDTF, has been working on the problem since 2014 and has haggled over two revision requests (RR158 and RR 232). The task force developed the first and defined network load to include load served by certain BTM generators at discrete delivery points, while excluding load served by other BTM generators where load is shed automatically. The second revision request was developed with input from the SPC and excluded load served by a BTM generator or group of generators totaling 1 MW or less.
Members were never able to reach consensus on the proposed Tariff language. The RTWG in June rejected RR158 and RR232.
“We spent significant time on RR232 trying to cover as many issues related to behind-the-meter generation as possible,” said BDTF Chair Heather Starnes, legal counsel for the Missouri Joint Municipal Electric Utility Commission. “Different people interpret the Tariff provisions related to network load … differently. Maybe it’s not so straightforward to some folks.”
The RTWG will bring back its list of exclusions and inclusions to the October governance meetings. Assuming clarity and approval of the network load list, Starnes said, the RTWG will then develop Tariff language once again subject to the stakeholder process.
“This is a need, an immediate need,” Wise said. “I think there may be some cross-subsidization going on because of the way the network load is actually reported. I want to make sure we have consistency across the entire footprint and where the whole load gets reported accurately, because we do have substantial costs paid by the network load. All these loads need to pay their fair share of those costs.”
Staff to Review AECI Joint Project After Cost Increase
David Kelley, SPP’s director of interregional relations, told members he would spend this week reviewing an alternative to a previously approved transmission project that recently saw a 50% cost increase.
The joint project with Associated Electric Cooperative Inc., originally estimated at $9.2 million, was endorsed by the MOPC and SPP Board of Directors in January and included in the RTO’s 2017 Integrated Transmission Planning 10-year assessment. It involves installing a new 345/161-kV transformer at AECI’s Morgan substation and an uprate of a related 161-kV line, both near Springfield, Mo.
“As luck would have it,” Kelley said, AECI notified him July 7 that it raised the project’s cost estimate to “just shy of $14 million.” Because the costs increased more than 20%, the parties can revisit the initial cost-sharing agreement.
“We had another alternative that wasn’t a seams project. It provided comparable benefits but, at the time, significantly more expenses,” Kelley said. “I’d like to spend the next few days making sure we’re still making the right decision.”
Kelley said if his revised analysis is not ready for the July 25 board meeting, he will present it during the October governance meetings.
The Morgan project would be regionally funded, as it solves congestion issues on SPP’s side of the seam, and is contingent on reaching an agreement for compensating AECI. SPP was to assume responsibility of $8.7 million of the original cost estimate. AECI will own the project and be responsible for its construction, operations and maintenance.
MWG to take Another Shot at MWP Manipulation
Members remanded back to the Market Working Group a previously rejected revision request (RR221) that addressed potential manipulation of make-whole payments (MWPs) related to mitigated energy offers and no-load offers for resources with a three-day minimum run time or greater.
RR221 would have added language that establishes a permissible percentage threshold above the mitigated offer at the time of the original commitment. Ross, the MWG’s chair, said that as structured, RR221 would force SPP to report to FERC’s Office of Enforcement deviations as little as a penny.
“Monitoring is not always clear and concise,” Ross said. “We have concerns with moving forward with that request. There’s no room for error when updating offers for fuel-price changes, and the burden of implementation is on the market participants to run the calculations. You could be one penny over the line because of a rounding error. You could violate the Tariff without any impact to the market.”
“There has to be a bright line. Yes, it’s a violation, but let’s exercise some judgment first,” he said. “It’s been my experience with manuals and protocols that … they’re nice guidance, but if you get to a circumstance where [they have] to be enforced, they don’t carry the same weight.”
Staff and members, in agreeing to send RR221 back to the MWG, said the issue was more of a market design problem.
“Let the market design experts take another shot at this,” said Midwest Energy’s Bill Dowling. “I’d prefer to see them deal with this issue one more time. Maybe there’s a way to navigate this.”
Wind Integration Study’s Recommendations Move On
The MOPC unanimously approved staff study recommendations for how much wind energy the SPP system can reliably absorb. The RTO has routinely broken the 50% penetration level for wind and has said it can go even higher. (See SPP Eyes 75% Wind Penetration Levels.)
SPP set a record for North American RTOs in April when wind energy served 54.47% of its load — 58.67% with the addition of solar and hydro. The RTO had 15.7 GW of installed wind capacity when the study began last year and currently projects 17.2 GW by the end of 2017.
Casey Cathey, SPP’s manager of operations analysis and support, said wind has exceeded 50% penetration several times and exceeded that mark for hours at a time.
“We’re meeting all NERC standards, but there are things out there we can continually improve on,” he said.
Last year’s Variable Generation Integration Study (VIS) stressed the transmission system to a point of instability, identifying reliability impacts during high-wind and low-load scenarios. Staff analyzed 45% and 60% wind penetration levels and examined transient stability, frequency response, voltage stability and a targeted five-minute ramping.
The VIS recommends seven solutions and improvements to increase reliability, including the installation of online transient-stability and voltage-stability analysis tools. Staff has estimated the software will cost a combined $3.2 million.
Members OK Re-baselining Out-of-Bandwidth Projects
Members unanimously approved re-baselining four out-of-bandwidth projects, three of which were a combined $95.5 million less than original estimates once project owners lowered material, engineering and construction costs through more accurate data.
One estimate, an OG&E 500/161-kV transformer project, went from $15.1 million to $25.6 million because of an increase in internal costs, unforeseen site work and the need to keep the 161-kV lines energized throughout the project.
All four projects were regionally funded, with operating voltages of greater than 100 kV and cost estimates of more than $20 million. (The OG&E project was a legacy project.) They became eligible for re-baselining when their updated cost estimates exceeded the +/-20% variance bandwidth after receiving notifications to construct.
MOPC Approves 9 Revision Requests
The MOPC approved a modified two-year-old revision request (RR82) that ensures combined cycle units do not lose eligibility for start-up cost MWPs because of a physical or environmental limitation, avoiding outage deviation penalties in the process.
RR82 adds a previously discussed increase in the MWPs’ grace period for commitments from one hour to two. The revision’s implementation date was scheduled for this August to allow SPP to complete development of software that allows market participants to register and submit separate offers for combined cycle units’ multiple configurations.
Final approval of the revision request is contingent upon the Regional Tariff Working Group’s endorsement of Tariff language changes. RR82 was approved by the MOPC and board in October 2015, but staff identified the additional changes while developing the FERC filing letter.
The committee approved eight other revision requests as part of its consent agenda, which passed unanimously:
MWG-RR185: Clarifies which SPP criteria document (Planning Criteria or Operating Criteria) is referenced when used in the market protocols and the Tariff’s Attachment AE, and correctly directs users to the specific document.
MWG–RR210: Changes the process for testing a contingency reserve deployment (CRD) by adding a deployment test instruction issued in conjunction with the out-of-merit energy dispatch, allowing sufficient time to review test results and provide accurate data. Also changes SPP’s communication of the CRD’s test results from 60 minutes to within one business day. Should a resource retest be requested, SPP agrees to complete the test within two business days, subject to its assessment of system stability.
MWG-RR222: Includes a multiconfiguration combined cycle resource’s (MCR) committed and actual configuration for each interval in a bill determinant report, allowing MCRs to shadow the configuration SPP is using to settle these resources.
MWG-RR225: Cleans up confusing and misleading Tariff language on incremental long-term congestion rights (ILTCRs) that could construe ILTCRs as load-serving entities or non-LSEs.
MWG–RR226: Changes settlement location pairs that have potential for unconstrained flow to electrically equivalent settlement locations during the auction revenue rights process, to comply with a FERC order (ER17-310). SPP will post the settlement locations before the annual ARR allocation process, along with the system topology and other data.
MWG-RR229: Satisfies FERC Order 831’s requirements on energy offer caps by using actual costs for make-whole payments on offers above $1,000/MWh. According to the order, costs underlying a resource’s cost-based incremental energy offer above $1,000/MWh must be verified before that offer can be used to calculate LMPs.
ORWG-RR228: Clarifies existing planning criteria language for system operating limits to reduce the potential of misinterpretation by entities complying with NERC reliability standards.
RTWG-RR233: Ensures that eligible network customers will not be billed twice for the same delivery. Customers will also not be assessed charges against a specific use of a single owner’s facilities that do not receive the benefit those charges provide to other transmission owners under the Tariff. The Southwestern Power Administration (SPA) and SPP have entered into a contract (Attachment AD) that provides for SPP to offer transmission service on SPA’s facilities, including network integration transmission service (NITS), and allows SPA to participate in the RTO’s transmission planning. SPA also voluntarily contributes to Schedule 11 representative of the grandfathered transmission service agreements (GFAs) it has in place for non-federal uses of its transmission facilities. SPA and SPP are transitioning customers with GFAs to NITS under the Tariff, creating implications for new customers who also receive federal hydropower deliveries.
The consent agenda also included:
Modifications to the revamped revision process, adding the Integrated Transmission Planning Manual and certain technical documents to the approval process. (See “Changes Proposed for Revision Process,” SPP Markets and Operations Policy Committee Briefs.)
A waiver request to FERC restating settlement prices for transmission congestion rights (TCRs) at Omaha Public Power District’s Fort Calhoun nuclear plant site. The plant was retired Dec. 1, 2016, but incorrect modeling of shift factors from Dec. 1 to Dec. 14, 2016, resulted in the marginal congestion component being overstated and the TCR settlements sourcing at the location being understated.
