Tesla and other energy storage companies have urged CAISO to accelerate development of a new demand response product that is based on excess generation, but the grid operator says it must first address many concerns before including the product in any proposal.
The electric automaker and other storage proponents last week submitted comments on a draft proposal of CAISO’s Energy Storage and Distributed Energy (ESDER) Phase 2 initiative, which is unlikely to include establishment of a new proxy demand resource (PDR) that would consume load based on an ISO dispatch instruction, including providing regulation service.
| CAISO
CAISO wants to omit the load consumption product from the ESDER Phase 2 package to be presented to its Board of Governors for approval during its July meeting. (See CAISO Proposes Rules for Distributed Resources, Storage;CAISO Finalizes Rules for DR, Distributed Generation.) The ISO plans to defer the product until a third phase in order to better understand the limits of non-generator resources and other issues identified in its separate “multiple-use applications” initiative related to storage.
Increasing instances of generation oversupply and solar curtailments is creating urgency for a market mechanism that facilitates consumption of surplus power, and stakeholders have generally agreed that CAISO should not let jurisdictional rate issues interfere with development of the bidirectional PDR product capable of both consuming and producing energy.
“CAISO staff has indicated that owing to the retail billing implications of customer participation in a hypothetical load consumption product, such a product is too fraught to consider developing and implementing until such implications are addressed,” Tesla said in its comments. The company “strongly disagrees with this perspective,” provided that customers understand that their retail bills will be impacted by a decision to charge a storage device based on the billing determinants they are subject to pursuant to their retail tariff.
Tesla said that customers of the program should be able to determine for themselves whether to provide load consumption based on the difference between retail rates and wholesale pricing. Customers would find value in offsetting their retail bills through negative wholesale prices while helping California mitigate oversupply, the company contended.
While storage advocates are urging CAISO to develop a bidirectional PDR product, “a broad cross-section of stakeholders” said it should “take more time to resolve issues, consider options and coordinate with” the California Public Utilities Commission, CAISO said.
Among these concerns are the effects on retail rates, customer interest, demand charges and technical implementation issues.
Pacific Gas and Electric’s “excess supply pilot has delved into these issues and has reported that participants are concerned about rate impacts and ratcheting demand charges,” CAISO said in its revised proposal.
“Contrary to comments from the storage community, the CAISO does not view these barriers as jurisdictional in nature, but as real impediments to customer interest and robust customer participation in a bidirectional PDR product,” the ISO said.
Energy storage companies said CAISO should also work on enabling behind-the-meter storage to participate in the wholesale market via the PDR product. There is unused potential in BTM energy storage because to do so currently requires participation as a non-generator resource, said Tesla, energy storage company Stem and EV charger manufacturer eMotorWerks.
Tesla Distributed Battery Storage Power Plant | Tesla
There has also been discussion within the Load Consumption Working Group, which Tesla said CAISO staff “appears to defer to stakeholders to revive and manage.” Storage companies want the ISO to take a leadership role in the working group.
The California Energy Storage Association (CESA), which represents more than 60 companies, said it “supports rapid action” on the group performing further work and having CAISO lead it, adding that the ISO should ensure ESDER promotes nondiscriminatory access to markets.
“CAISO should focus on how to ensure resources like PDRs can show up in CAISO markets to compete to provide services,” CESA said.
A MISO plan to share generators’ hourly gas-burn estimates with select natural gas pipeline operators will require more explanation before getting federal approval, FERC staff said Tuesday.
Agency staff issued the RTO a deficiency letter in response to a proposal to share nonpublic, day-ahead gas-usage profiles with pipeline companies — which currently include Northern Natural Gas, ANR Pipeline and DTE Energy — before this winter as part of a pilot program meant to improve gas reliability (ER17-1556). (See “3 Pipeline Companies to Receive Gas Profiles Before Winter,” MISO Reliability Subcommittee Briefs.)
In filing the proposal, MISO stressed that it would share only aggregated data, while also contending that sharing nonpublic operational data was allowed under FERC Order 787. The RTO plans to execute nondisclosure agreements with relevant pipelines and utilities under the proposal.
But FERC staff were primarily concerned with a provision that would also allow MISO to share data with local distribution companies (LDCs) and intrastate pipelines in addition to interstate operators.
While the deficiency letter acknowledged that Order 787 recognized the “significant” role of LDCs and others in maintaining reliability of both interstate pipeline systems and electric transmission systems, it also noted the order “declined to provide blanket authorization for the disclosure of nonpublic, operational information” to LDCs, intrastate pipelines or gas gatherers, instead requiring a case-by-case approach. FERC staff determined that “MISO does not provide support for this aspect of its proposal” and gave the RTO 30 days to provide more supporting information to justify sharing nonpublic information with LDCs.
Agency staff also said that MISO’s proposal failed to expressly prohibit the use of nonpublic, operational information “to the detriment of any natural gas and/or electric market,” as an earlier, similar proposal from PJM promised. MISO’s proposed nondisclosure agreement merely prohibits the “receiving entity from illegal and non-legitimate use of the nonpublic, operational information,” FERC staff said, asking MISO to explain the omission.
Some MISO stakeholders earlier this year voiced opposition to the pilot program, saying it could affect reliability if participating gas operators make burn rate decisions relying solely on partial day-ahead data. (See MISO Stakeholders Question Electric-Gas Info Sharing.)
ITC Holdings on Tuesday offered a rare look into its Michigan control room as part of a company update that included an appeal for increased investment in transmission.
ITC Control RoomBlair
During the online “virtual tour” and accompanying web seminar, CEO Linda Blair called for a sense of “urgency” for the industry to develop new electric infrastructure.
“Now is a critical time to support investment for the years ahead,” Blair said, adding that “no meaningful interregional planning process” exists to address extra demands being placed on the grid, particularly from the growth of wind generation.
“We have to have a requirement that transmission lines have a way to come to fruition. … I think it requires action from FERC,” she said.
ITC was acquired by Canadian utility Fortis last October. Immediately following the $11.3 billion sale, Blair took over as president and CEO of the Michigan-based company.
Blair said ITC has not changed its company vision since the acquisition. “We’re a transmission-only company. We breathe, sleep and eat transmission. That’s what we do, and we do it well,” she said.
Jipping said ITC is awaiting approval by the U.S. Army Corps of Engineers on the Lake Erie Connector project, a 1,000-MW, bidirectional, underwater HVDC transmission line that will ship electricity between Ontario’s Independent Electricity System Operator and PJM territory in Erie, Pa. He expects the company to wrap up the permitting process for the $1 billion project in late summer.
ITC executives also touted the reliability of the current ITC system that spans Michigan, Iowa, Minnesota, Illinois, Missouri and Oklahoma.
Slocum
Vice President of Operations Brian Slocum said ITC’s system remained operational during Michigan’s historic March 8 wind storm and weather-related outages that affected more than 1 million people.
“Over the years, we’ve seen less unplanned outages on this wall,” Slocum said from a virtual ITC control room. But more needs to be done to improve the country’s transmission grid, which was not designed to handle so many renewable sources of generation, he said.
“Fortunately, there’s a dialogue underway” on infrastructure improvements in this country, Slocum added.
The White House late Wednesday announced that President Trump intends to nominate Richard Glick, general counsel for the Democrats on the Senate Energy and Natural Resources Committee, to replace outgoing FERC Commissioner Colette Honorable.
Glick | Avangrid Renewables
Glick has been with the committee since February 2016. Prior to that, he was a lobbyist at Avangrid Renewables, PPM Energy and PacifiCorp. Glick also served under the Clinton administration as an adviser to Energy Secretary Bill Richardson. He earned his bachelor’s from George Washington University and his J.D. from Georgetown University.
Glick’s term would end in 2022. The announcement came two days before Honorable’s term at the commission ends, leaving acting Chair Cheryl LaFleur, a Democrat, as the only commissioner. (See FERC’s Colette Honorable Says Goodbye.)
Pennsylvania Public Utility Commissioner Robert Powelson and Neil Chatterjee, energy adviser to Senate Majority Leader Mitch McConnell (R-Ky.), have already advanced out of committee and are awaiting confirmation votes by the full Senate.
Powelson and Chatterjee, both Republicans, would restore the commission’s quorum, but it is unknown when McConnell intends to schedule the votes: The Senate has been consumed by Republicans’ efforts to replace Obamacare, and reports say that Democrats have refused to consent to votes on other items while debate on the bill is ongoing.
The confirmation of the three nominees would leave only the seat vacated in February by former Chair Norman Bay, a term that would end next year.
FERC’s membership will see a nearly complete turnover if Republicans Robert Powelson and Neil Chatterjee and Democrat Richard Glick are confirmed by the Senate to join acting Chair Cheryl LaFleur. President Trump has not yet nominated a third Republican.
Numerous reports have identified Kevin McIntyre, co-head of the energy practice at law firm Jones Day, as the third Republican nominee and likely chairman, but he has not been formally named.
Glick’s nomination may be an effort to appease Democrats and enable simultaneous votes on all three nominees. If that’s the case, FERC will have to wait on a White House notorious for its slowness in officially submitting nominations and for Glick to go through the committee process.
Honorable’s “departure again underscores the urgent need to re-establish a quorum at FERC,” Committee Chair Lisa Murkowski (R-Alaska) said yesterday. “Getting the agency back to the normal course of business remains a top priority for me. I will continue to push for a confirmation vote for Neil Chatterjee and Robert Powelson. … I hope my colleagues among the Senate minority will join us in enabling a quick vote for Mr. Chatterjee and Mr. Powelson.”
CARMEL, Ind. — FERC on Monday approved a proposal by PJM and MISO to create a new category of small interregional transmission projects while cautioning that the measure could see future revisions.
The proposal updates the PJM-MISO joint operating agreement with a targeted market efficiency project (TMEP) type, which applies to projects that reduce historical congestion along the RTOs’ seams.
Still, in its June 26 delegated order, FERC staff said that preliminary analysis indicates the proposal has “not been shown to be just or reasonable” and left open to the possibility that it could be subject to refund after being implemented (ER17-721). The RTOs are eligible to use the project type starting June 28.
The RTOs filed jointly last year to create TMEPs to encourage construction of cost-effective and congestion-relieving seams projects that might otherwise be overlooked because of their low cost and small size. Their proposal stipulates that TMEPs cost less than $20 million, be in service within three years of approval, and within four years of operation provide congestion relief equal to or greater than the cost of construction. Costs will be apportioned to MISO and PJM based on the percentage of congestion relief benefits accruing to each RTO.
The RTOs have so far identified $17.25 million worth of upgrades in five TMEP candidate projects, and expect those projects to deliver a 5.8:1 benefit-cost-ratio and realize $100 million in benefits within four years of going in service. (See MISO-PJM TMEP Projects Drop to Five.) Both RTOs hope to finish evaluation of TMEP candidates by September and seek respective board approvals by the end of the year.
Exelon, the Organization of MISO States, Northern Indiana Public Service Co., the Indiana Utility Regulatory Commission and ITC Mid Atlantic Development supported the proposal in comments to FERC. MISO South regulators protested the filing, claiming that the RTOs’ benefits analysis fails to take congestion hedging revenues into consideration.
Speaking on behalf of the MISO Transmission Owners sector, Ameren Senior Director of Transmission Policy Dennis Kramer said that the factoring in of congestion hedging revenues would “complicate” the TMEP study process.
“Excluding the congestion hedge costs is consistent with the TMEP goal of straightforward, efficient metrics that can be easily reproduced by stakeholders,” Kramer said in comments submitted for a June 13 FERC workshop on the TMEP issue. “Adding congestion hedges … would fundamentally change the nature of the TMEPs by changing the study from a simple analysis of historical flowgate congestion to a multifaceted deconstruction of a series of complex financial hedging instruments which differ in each RTO. Such action would counteract the RTOs’ ability to implement the quick-hit, high-value project types.”
Regional Cost Allocation
FERC must still also act on separate proposals by MISO and PJM regarding how they plan to allocate their portion of TMEP costs regionally.
MISO plans to pursue a bifurcated cost allocation, using a local transmission pricing zone when the constraint exists on lines belonging to one or more MISO transmission owners. For constraints wholly within PJM, MISO is seeking a postage stamp allocation for the entire MISO Midwest region.
However, MISO missed its targeted April filing deadline to complete a regional cost allocation because it needed more time to develop the process with stakeholders. Spokesman Mark Adrian Brown said the RTO will submit an allocation proposal “as soon as possible.”
PJM in April filed a regional cost allocation proposal that would assign TMEP costs to zones and merchant transmission facilities “that are shown to have experienced net positive congestion over the two historical years prior to the TMEP study period” (ER17-1406).
Recently, I attended a solar power event hosted by Solar Energy Industry Associates (SEIA) and Smart Electric Power Alliance (SEPA). The event was well attended by industry thought leaders, manufacturers, solar companies and even legislators. Of course, being a solar event, most of the speakers lauded the benefits of solar: how it’s better for the environment, how the price of solar continues to decrease, how photovoltaic panels continue to improve and how the industry has made it easier to integrate solar into more communities. If you were not from this planet, you would question why everyone does not have solar. It sounds like the best thing since sliced bread.
Brinker
In the words of Lee Corso, the colorful ESPN football analyst, “Not so fast, my friend.”
Others might have a completely different take on solar and distributed energy resources altogether. Ironically, this event was held in Atlanta, which is also where NERC is headquartered. NERC has raised some concerns about DER. In fact, I wrote an article about it. NERC is not alone in its concerns. According to a study issued by Accenture, many utility executives see DER as the biggest stress on grid reliability. Nearly 60% of the executives surveyed expressed concerns.
Adding to the complexity of this debate is the efforts by many states and cities to “go green.” California just passed legislation requiring the state to be 100% renewable by 2045. Other states are certain to follow California’s lead. Many, like North Carolina, already have ambitious renewable goals. Recently the Atlanta City Council approved a measure aimed at making Atlanta 100% renewable by 2035. So, who is right?
Recent studies have suggested that DERs are not a threat to the grid and may even help the grid to be more reliable. CAISO — in collaboration with the National Renewable Energy Laboratory, First Solar and Southern Co. — used a 300-MW solar facility to conduct a study that determined that “solar photovoltaic resources can provide ancillary services in a way comparable to or even better than conventional generation resources.” General Electric has stated, “The days of relying on synchronous generation for everything are over.” And who could argue against the technological advances that have been made in the industry such as plant-level controllers and virtual oscillator controls, which are designed to respond to changes in load, frequency and voltage similar to conventional generation? I highly suggest reading the article “Can Smarter Solar Inverters Save the Grid?” found here.
Distributed Energy Resources | Clean Coalition
The DER industry will point to these studies, articles and advancements and say, “Move on, there is nothing to see here.” However, (insert Lee Corso quote here), there is ample evidence to show that we are not quite there yet.
On Aug. 16, 2016, there was a significant event resulting in the loss of nearly 1,200 MW of PV generation. In short, a fire caused a fault that resulted in three facilities ceasing output instead of riding through the fault. DER detractors will point to events like this to show that instead of providing support to the grid, DER actually hurt the grid when needed at the most critical time. NERC and the Western Electricity Coordinating Council conducted a study of the event and published a report. (See CAISO Boosts Reserves After August Event Report.) The 2016 Australia blackout has been attributed to its reliance on wind power. Another concern of NERC is that with so many DER projects in the works, it cannot adequately account for and plan for these additional megawatts. Planning is essential to grid reliability. So where do we go from here?
Although I claim to be a subject matter expert (I have stayed at a Holiday Inn Express before), I do not claim to have all of the answers. However, with legislators mandating renewable energy usage and renewable energy becoming cheaper with each passing year, we have to adequately plan for this new normal. To that end, it is critical that the various stakeholders — DER industry, regulators, legislators and utilities — work together to effectively and strategically integrate renewables into the grid while also providing the reliability that is necessary. We cannot afford legislative mandates like the one in Hawaii that had to be rewritten because of unintended consequences. We also cannot afford the installation of solar farms that cannot respond appropriately to disturbances on the grid, like the August 2016 Southern California event. We cannot afford burdensome regulation that overreaches. We can afford to have thought leaders at companies such as First Solar, Southern and Duke Energy; government agencies like FERC, NERC, NREL and the Energy Department; industry associations like SEIA, SEPA and the Institute of Electrical and Electronics Engineers; and state legislators work together and create strategic policies that ensure that we all succeed in this new normal.
Is DER a threat to the grid? Not if we all work together to ensure that it is not.
Terry Brinker, who has 23 years of experience leading, facilitating and implementing improvements in power plant operations, control room operations, compliance and regulatory matters, is the president of Reliable Energy Advisors. Terry previously served in leadership roles during a five-year stint at NERC, where he served as senior manager of standards information and personnel certification, manager of registration services, and senior event investigator.
WILMINGTON, Del. — Stakeholders endorsed by acclamation several manual revisions and other operational changes:
Manual 14A: Generation and Transmission Interconnection Process. Revisions to the manual and the Tariff were developed to allocate reinforcement costs of less than $5 million to all projects in a queue that add load to the violation causing the need for the reinforcement. Also removes alternate queue screening, allowing projects to be evaluated for impacts once the point of interconnection has been established. (See “Should I Stay or Should I Go? PJM Still Searching for Resolution to Interconnection Queue Issues,” PJM Planning and Tx Expansion Advisory Committees Briefs.)
Manual 20: PJM Resource Adequacy Analysis. Revisions developed to address changes to modeling of zonal and global locational deliverability areas for capacity emergency transfer objective calculations. (See “ISO-NE out of this ‘World,’ According to PJM Reserve Requirement Study,” PJM Planning Committee/TEAC Briefs.)
Manual 28: Operating Agreement Accounting. Revisions conform with FERC order in docket ER16-121-001 requiring allocation of balancing congestion and real-time market-to-market payments to real-time load plus exports on a pro rata basis RTO-wide. (See “FERC Finds PJM ARR/FTR Market Design Flawed; Rejects Proposed Fix” and “FTR Revisions Continue Forward,” PJM Market Implementation Committee Briefs.)
Manual 39: Nuclear Plant Interface Coordination. Revisions clarify that nuclear operators must communicate any limiting conditions affecting interface requirements following notification of a grid-side event. The revisions, which include limits on the operability of offsite power sources, are intended to ensure that PJM and the transmission owner local control center have situational awareness of nuclear plant conditions.
Members Committee
Stakeholders Endorse Consent Agenda
Stakeholders endorsed by acclamation the committee’s consent agenda, which included Operating Agreement and Tariff changes:
Operating Agreement and Tariff revisions requiring solar generators to provide meteorological and forced outage data — previously only required from wind generators — in compliance with FERC Order 764. (See “Solar Forecast Is Coming,” PJM Planning and Tx Expansion Advisory Committees Briefs.)
Operating Agreement and Tariff revisions creating a method for compensating pseudo-tied generators and dynamic schedules, which are not eligible to submit meter correction data, as permitted for internal generators and tie lines. (See “Meter Correction Initiative OK’d,” PJM Market Implementation Committee Briefs.)
Operating Agreement and Tariff revisions related to annual revenue requirements for new black start units. Sets deadlines for the submittal and review of new black start units’ capital, variable and fuel storage costs; policies for allocating costs to network service customers and point-to-point reservations. (See “New Black Start Units Will Have New Annual Revenue Requirements,” PJM Markets and Reliability Committee Briefs.)
Stakeholders Endorse Third Phase of PJM’s Uplift Solution Despite Opposition
Members strongly endorsed the third phase of PJM’s plan to address uplift, despite opposition from financial stakeholders.
Attorney Ruta Skucas, who represents the Financial Marketers Coalition, reiterated her clients’ opposition to the proposal, which she said will substantially reduce up-to-congestion transactions. The proposal limits increment offers and decrement bids to “locations where the settlement of physical energy occurs,” where they compete directly with physical assets or trading hubs, and where traders can take forward positions. Up-to-congestion transactions would be limited to hubs, zones and interfaces — locations that are large aggregates. (See PJM MRC OKs Uplift Solution over Financial Marketers’ Opposition.)
The proposal was endorsed with 4.16 in favor in a sector-weighted vote, surpassing the 3.335 threshold.
PJM’s Dave Anders explained that the RTO hasn’t filed any of the endorsed uplift proposals yet because the dockets are likely be challenged, which means they will have to wait until FERC has a quorum again. Another consideration is avoiding the period between November and March of next year, when PJM plans to make its filing on five-minute settlements, he said.
“To the extent that we can get something filed with FERC and get approval by FERC before that to allow implementation before November, we would do that,” he said. “If FERC would be not in a position to approve for then, we’d be looking for implementation afterwards.”
The third phase of the solution isn’t impacted by five-minute settlements, so it will likely be filed separately, CFO Suzanne Daugherty explained.
Independent Market Monitor Joe Bowring urged filing as soon as possible. “The fact that there’s no quorum doesn’t mean that they’re not creating a queue, and it’s better to be at the front of the queue than at the back of the queue,” he said.
Members Celebrate Ott’s Birthday
Stakeholders celebrated the birthday of PJM CEO Andy Ott with a personalized cake.
In other news, Anders announced the RTO now has 1,008 members.
WILMINGTON, Del. — PJM again deferred a vote on the grid operator’s proposed pseudo-tie pro formaagreement last week after stakeholders complained that revisions were not made public until the night before the Markets and Reliability Committee meeting.
“While I agree you’ve read the documents [during presentations at previous meetings], I don’t agree that you’ve read the same documents … so, in a sense, they’re multiple first reads,” American Municipal Power’s Steve Lieberman said. “People are trying to keep up with the speed at which you’re making changes, but it’s difficult.”
CFO Suzanne Daugherty, who chairs the MRC, agreed to the delay. She said the late changes reflected language PJM and MISO had agreed to just two days prior to the meeting.
PJM had postponed a vote on the agreement at the May MRC meeting, citing ongoing negotiations with MISO, which had been reluctant to sign PJM’s proposal. (See “Pseudo-Tie Discussion Postponed to Continue Negotiations with MISO,” PJM Markets and Reliability Committee Briefs.)
PJM’s Jacqui Hugee said the RTO resolved its issues with MISO by incorporating language into their Joint Operating Agreement obviating the need for the grid operators to agree to each other’s pseudo-tie rules. MISO has filed its own agreement at FERC and isn’t requesting approval from other grid operators or balancing authorities, she said. Other balancing authorities, including Duke Energy, the Tennessee Valley Authority and SPP, have been willing to sign PJM’s agreement.
“Whether [the unit is being tied] into PJM or into MISO, the same rules are going to apply,” she said.
Some stakeholders, including Independent Market Monitor Joe Bowring, remained concerned about language that suggested that the native balancing authority (BA) would control redispatch of pseudo-tied resources in certain situations, including non-emergencies.
Hugee said the language complied with NERC standards. Mike Bryson, PJM’s vice president of operations, explained that the RTO would maintain control during performance assessment hours and resources would be rewarded or penalized like any other resource under Capacity Performance requirements. In other situations, the native BA would set certain operating limits, scenarios that are also addressed in PJM’s existing market-to-market flowgate procedures, he said.
“If PJM is experiencing an emergency and MISO is experiencing an emergency at the same time, MISO — according to NERC standards — has the authority to dispatch that resource because it’s in their balancing authority. So what will happen is that resource will probably be penalized because they’re not available to PJM during that performance assessment hour, assuming PJM would have called on them,” Hugee said. “Everybody knows that’s a risk they take before they pseudo-tie.”
“That means that a pseudo-tied unit is not really equivalent to an internal unit, which is what the issue has been all along,” Bowring responded. “I could certainly imagine someone arguing that they shouldn’t have to pay a penalty because they were following NERC procedures and following dispatch instructions.”
“They can argue it, but we have a provision that says if you are a Capacity Performance resource and you’re not there when we call on you, you’re going to get a penalty,” Hugee said. “The same Capacity Performance rules apply to everybody, whether you’re physically internal or you’re tying into PJM from another balancing authority.”
PJM also incorporated in the agreement a provision allowing it to suspend a resource. If the RTO intends to cancel an agreement, it likely won’t want the tied unit operating during the 60-day notice period for cancellation, Hugee said. She also introduced an accompanying agreement for dynamic scheduling but said that will be brought for vote at a later meeting.
AMP’s Lisa McAlister asked how the agreement will affect collecting congestion charges from the resource to the RTO border and if it resolves the double-charge issue. Hugee said that topic isn’t being addressed in the current agreement and that it will be filed in concert with MISO as JOA revisions in a separate docket at FERC. PJM believes the congestion charge filing is likely to be challenged as there are already five pending complaints on the issue, Hugee said. The RTO hopes the filing on agreements will not be challenged and may win commission approval even without a quorum.
Hugee said that, while the Tariff and JOA revisions for the agreement will require separate dockets, PJM wants to file all of them contemporaneously and have them reference each other.
“The plan is to file one big packet because I’d like to resolve everything at once, and it makes sense to do it that way,” she said. “We [would] … explain to FERC that it’s very important that all of these things get approved [together] … so that we can alleviate that concern about getting out of sync of one getting approved and the other not getting approved.”
Hugee said that if the agreement needs to be “tweaked” for individual units, she would ensure it remains in accordance with the JOA.
Carl Johnson, representing the PJM Public Power Coalition, was the first to suggest deferring the vote. He said he couldn’t vote in favor of the package at the meeting because some of his members hadn’t yet reviewed the current version of some of the documents, but that he “probably could get to a point where we could support it” by the MRC’s July meeting. Lieberman said AMP also couldn’t vote in favor of the changes at the meeting. He said it is still attempting to figure out how PJM handled the revisions it had recommended, which it couldn’t find in the current versions.
Hugee said PJM and MISO have committed to filing the agreement with FERC by July 27, the same day as the next MRC meeting.
“Maybe we’ll have to ask them for a couple of days,” Daugherty said, then announced that PJM would be deferring the vote until the July MRC and Members Committee meetings.
WILMINGTON, Del. — An informational update on PJM’s Transmission Replacement Processes Senior Task Force at the end of the Markets and Reliability Committee meeting last week turned into a hotly contested debate and impromptu vote.
The result was that the task force is still on target to resume on July 28. It has been on hiatus since an MRC vote in September, about a month after PJM and Transmission Owners received an order to show cause from FERC to determine whether the TOs are complying with their local transmission planning obligations for supplemental projects under Order 890. The hiatus, requested to focus on responding to the show cause order, was extended until July at the February MRC. (See FERC Orders PJM TOs to Change Rules on Supplemental Projects.)
In his presentation, PJM’s Fran Barrett noted the “predominate desire” of TOs to continue the suspension of the task force and transmission customers’ “uniform desire” to lift resume task force meetings.
The TOs filed their initial response to the show cause order on Oct. 25 and followed up with responses to comments on its filing a month later. The TOs insisted their Operating Agreement already complies with Order 890 but proposed a Tariff amendment providing additional detail regarding the process for planning supplemental projects (EL16-71).
FERC assured the order would be finalized by January, according to Barrett. But the commission didn’t rule on the TOs’ response before losing its quorum in February.
“We’re locked in the horns of an MRC-directed process versus a FERC-directed process, and we’re looking for guidance for how to take that forward,” he said.
Chris O’Hara, PJM deputy general counsel, stressed that the RTO doesn’t have approval authority over TO supplemental projects. “PJM is ready to engage on these topics. However, that engagement might be more productive after FERC takes action on” the situation, he said.
Representatives of several TOs — including Public Service Enterprise Group’s Alex Stern, PPL’s Frank “Chip” Richardson, Exelon’s Gloria Godson and Duquesne Light’s Tonja Wicks — all advised that they would attend task force meetings once the hiatus has ended, but they likely will not be able to make many decisions until the FERC action is resolved. The circumstances that precipitated suspending the task force in the first place haven’t changed, they said.
Godson motioned to continue the hiatus, and Stern offered a friendly amendment to extend it until FERC rules on the issue and reconsider options if nothing has changed by December. “I don’t think our attorneys would sanction our involvement under a show cause order,” Stern said.
Carl Johnson of the PJM Public Power Coalition said he appreciated the “intellectual honesty,” but that he would oppose the motion because there are other issues on which the task force could be productive. Susan Bruce, representing the PJM Industrial Customer Coalition, and American Municipal Power’s Lisa McAlister also opposed the proposal.
“AMP thinks there’s valuable work to be done [before] a FERC order,” McAlister said. “We’re getting a piecemeal change process that’s the result of, frankly, AMP being a very squeaky wheel. … We don’t think that’s the best procedural way for making these changes.”
American Electric Power’s Dana Horton said there are plenty of other issues to focus on at PJM that aren’t under the auspices of a show-cause order. He supported extending the hiatus so stakeholders don’t have to waste time on unproductive discussions. “We don’t want to expend resources to just look at each other,” he said.
The motion to extend the hiatus failed with 1.79 in favor in a sector-weighted vote that had a 3.335 threshold for passage.
WILMINGTON, Del. — The PJM Markets and Reliability Committee on Thursday endorsed a plan to change compensation in the RTO’s regulation market, despite howls from some market participants that units would be shouldered with more work while receiving less pay.
PJM’s Eric Hsia said the changes resulted from staff observation that the RegD, fast-responding signal would sometimes move in the opposite direction of the area control error, exacerbating the frequency regulation problem.
Additionally, many resources were self-scheduling into the market, which amplified the response to the signal, he said. Howard Haas, the Independent Market Monitor’s chief economist, later added that the current market design incentivizes self-scheduling to receive surplus payments.
PJM and the Monitor developed a package of revisions to the market that received 75% approval from the Regulation Market Issues Senior Task Force. The package would, among other revisions, replace the “mileage ratio” portion of the regulation performance credit, which proponents say doesn’t correctly compensate RegD and causes load to overpay for the service. Hsia noted that discrepancy also contributed to the oversupply issue.
In connection with the task force, PJM produced a new regulation signal and requirements that were implemented on Jan. 9. (See “New Regulation Rules Improving ACE Control,” PJM Operating Committee Briefs.)
Transitioning to the revised signals could drive the value of RegD compensation to zero, Hsia said, so the package includes a minimum “regulation rate of technical substitution” (RRTS) value of 0.65 for the first 12 months of implementation and 0.5 for the following 12 months. The RRTS terminology would replace the previous “benefit factor.”
“Really, what we’re trying to do there is ensure that there is going to be compensation even though there will be oversupply,” he said.
Tom Rutigliano, representing the Energy Storage Association, argued that PJM’s plan omits necessary changes. He urged stakeholders to defer voting on the package until it includes greater detail on regulation providers’ obligations, how resources’ physical limitations will be incorporated into the signals and how the metric that replaces the mileage ratio will be calculated.
“We feel the Tariff language seeking endorsement today is unacceptably vague on several key market features,” he said.
The revised regulation signal changed a longstanding, material market rule that the RegD product energy neutral, Rutigliano said. Making the change without revising the Tariff bypasses FERC review in violation of the Federal Power Act, he said. Ten unaffiliated organizations built about 285 MW of storage designed to charge and discharge equally in a 15-minute time frame, he said, but the new signal implemented on Jan. 9 has no firm energy limit and substantially changes performance requirements. Analysts at ICF say the neutrality requirement means that during steep ramp-up or ramp-down hours, RegD resources alone will not be adequate; thus RegA resources will set the market clearing price.
“This is an entire industry that received clear guidance [on] their performance obligations, invested hundreds of millions of dollars in single-purpose machines to meet those obligations and, frankly, had the rug pulled out from under them,” he said. “We are asking that no participant in this market should have that happen to them without getting their day at FERC.”
Hsia had noted earlier that PJM has been working with market participants to address some issues created by the new signal. He said instances of resources being asked to follow a signal for more than 15 minutes dropped to just two in the first half of June. No resources were asked to follow a signal for more than 30 minutes.
The package of revisions will also change how regulation payments are calculated, all without being codified in the Tariff. Rutigliano called this an “unprecedented” situation “where you have what is essentially an administrative pricing curve, and that curve is left entirely to the RTO’s discretion.”
Speaking on behalf of client Beacon Power, Gabel Associates’ Gabbi Hudis said the revisions “have those resources performing additional work while receiving significantly less compensation than the RegA resources.”
“I can appreciate the desire to get this right,” said Gabel Associates’ Mike Borgatti, representing client NextEra Energy. The rule changes are “significant” for some market participants, he said, and neglecting to include them in the Tariff set “an unhealthy precedent.” Additionally, FERC’s lack of quorum means it’s unlikely that delaying the vote a few months will significantly impact how soon the commission will consider the issue, he said.
Haas said all of Rutigliano’ s concerns were discussed by the RMISTF and that FERC orders established the RTO’s authority to make changes to the regulation signal and the rate-of-substitution curve.
“What we’re seeing here in terms of the PJM/IMM proposal is the result of all of those discussions, and those discussions led to ‘we need to fix this issue,’” he said. “We can hold off and continue to talk about this forever, or we can take this proposal to the commission. ESA wants this issue to be in front of the commission. Allowing the PJM/IMM proposal to go forward will allow [that] to happen. … I think that’s the appropriate place to take this.”
Susan Bruce, representing the PJM Industrial Customer Coalition, agreed that the decision should now be in FERC’s hands. “These issues are now before FERC, and we would like to move the PJM/IMM package to allow that to occur because, in our view, currently customers are overpaying relative to the benefit that they’re receiving, so we want to make sure that that doesn’t continue,” she said.
“Something isn’t right about what we’re paying for regulation right now,” the PJM Public Power Coalition’s Carl Johnson said in agreement. “If we do defer [a vote], we risk just taking even longer before we get to a solution on the market side.”
Calpine’s David “Scarp” Scarpignato added that the current processes also harm resources that provide the traditional, slower RegA service. Exelon’s Jason Barker also voiced support for the revisions package.
Proponents of the deferral attempted to negotiate for a specific deadline for making a FERC filing, but Bruce and Johnson were skeptical that additional, more-focused debate — “this time, for reals,” as Bruce put it, invoking youth slang — would produce any better results.
“It’s hard to know whether or not there’s the prospect of consensus,” she said. “It seems like that conversation’s happened, and there’s not consensus. I’m not sure what more could be done to get there in the next two months.”
Many other provisions that affect resources aren’t included in the Tariff to that level of detail, Scarp said, but that’s a separate conversation that goes beyond regulation rules.
“I don’t think all stakeholders are in agreement that all of this should even go in the Tariff,” Scarp said. “If we put every similar provision in the Tariff, instead of being 6-inches-thick, it would be 6-feet-thick.”
Bob O’Connell of Panda Power Funds warned that moving the language into the Tariff instead of the Operating Agreement would shift control away from stakeholders to PJM. He later proposed developing a manual specific to the regulation market that aggregates in one place the market rules currently embedded in multiple manuals.
“If that is what the stakeholders want, I encourage you to move forward with the motion to defer,” he said. “If you don’t want that, if you want to continue to retain some voice in the process other than just an advisory voice, I recommend that you move forward with the RMISTF package and figure out a different way to address how to get the changes you’d like to see changed worked into the Tariff.”
Borgatti made the motion to defer the vote, but it failed, receiving 1.61 in favor in a sector-weighted vote that had a threshold of 3.335 for passage.
John Horstmann of Dayton Power & Light reiterated disapproval with the revisions package that he’s expressed previously, calling it “the final nail in the coffin” for anyone who built to the 15-minute standard.
“It’s very disappointing that this can occur basically unilaterally,” he said. “If we build you [PJM] a one-hour battery today, could the same thing happen a year or two down the road that you want a two-hour battery? Unfortunately, the signal it sends … is that PJM’s a pretty risky place to do business because you really don’t have a lot of rights when it comes to rule changes. … I’ve heard an awful lot of reasons why this is such a wonderful process that got us to this point, but largely, the small number [of] owners that are hugely impacted have been pretty much stonewalled through the process.”
Stakeholders approved the revisions package with a 3.89 sector-weighted vote.
