MISO announced it has received 12 complete proposals from nine developers seeking to construct and own the Hartburg-Sabine Junction 500-kV project, the RTO’s second competitively bid transmission expansion.
MISO had been screening proposals for the Hartburg-Sabine project since it closed the request for proposals window on July 20. As a practice, the RTO does not reveal which developers may have submitted incomplete proposals. (See “MISO Reviewing Hartburg-Sabine Proposals,” MISO Informational Forum Briefs: July 24, 2018.)
| MISO
MISO said it only reviewed the proposals for completeness and has not vetted the content of the proposals.
“With the final list of complete proposals, we now begin our competitive evaluation phase, which is outlined in the MISO Tariff,” Aubrey Johnson, MISO executive director for system planning and competitive transmission, said in a statement.
MISO said it expects to announce the selected developer by Dec. 31.
The completed proposals come from Avangrid Networks; EasTex TransCo; GridLiance Heartland (with Cleco Energy); Midwest Power Transmission Arkansas; NextEra Energy Transmission Midwest; Transource Energy; Verdant Plains Electric; Xcel Energy Transmission Development Co.; and a joint bid from ITC Midcontinent Development, Hunt Transmission Services and Texas Infrastructure Holdings. MISO did not reveal which developers submitted multiple proposals.
The estimated $129-million, 500-kV line and substation project, intended to alleviate system congestion in eastern Texas, is expected to be in service by 2023. The RTO opened the submittal window in early February after MISO’s Board of Directors approved the project as part of MISO’s 2017 Transmission Expansion Plan. (See MISO Board Approves Texas Competitive Tx Project.)
WASHINGTON — ERCOT’s energy-only market survived the summer of 2018 with surprisingly modest prices and no generation shortfalls, but 2019 may be a tougher challenge, the RTO’s market monitor said Wednesday.
Beth Garza, director of ERCOT’s independent market monitoring unit, credited better-than-expected generation performance and an early summer system peak that took advantage of above-normal wind for the positive results.
Coal plant retirements reduced ERCOT’s installed reserve margin to below 11%, by far the lowest in the market’s history, leading on-peak forward prices for August to rise as high as $250/MWh. But although real-time prices briefly peaked at more than $2,000/MWh, average real-time prices in July were about $50/MWh and about $38/MWh in August, Garza said.
She acknowledged one competitive retailer was forced to surrender tens of thousands of customers to the provider of last resort when it was unable to meet collateral requirements in early summer. But disruptions were minimal, Garza told the inaugural Future Power Markets Summit, sponsored by the American Wind Energy Association and several other trade groups.
“There was certainly a high level of awareness across the market, across the state legislature, across the regulators [of the tight market], and with that high level of awareness I think came a high level of preparedness, certainly from the generators,” she said. “As it turned out … generator availability was higher than normal this summer. We also had — I think because of the timing when our system peak was — we had the … contribution from higher-than-expected wind generation this summer.”
ERCOT recorded its summer peak at 73,259 MW on July 19, while loads in August — normally the peak month — never exceeded 71,110 MW. The 2018 Long-Term Demand and Energy Forecast projected a 2018 summer peak of 72,974 MW.
Garza said generators responded to the potential for prices up to ERCOT’s $9,000/MWh cap. “Having that opportunity for our energy price to rise to very high levels creates that natural incentive for availability at the time when we need generation resources the most.”
But it won’t get any easier for ERCOT in 2019, Garza said, as its load — unlike that of other markets — continues to grow. In addition, two announced coal plant retirements will reduce capacity by more than 1 GW by the end of the year. The system has added no significant thermal capacity although there have been wind and solar additions.
“So, I think we’ll go into 2019 in a very similar state as we went through this summer,” Garza said. “And that raises all kinds of questions about outcomes … if generation availability [is] lower than expected, if wind [is] average, if load [is] a little higher.”
“The good part about this job is I get to monitor the market,” she laughed. “I don’t have to forecast the market.”
In addition to AWEA, the summit was sponsored by the American Council on Renewable Energy, the Solar Energy Industries Association, the American Public Power Association, the National Rural Electric Cooperative Association, the Large Public Power Council and the Energy Systems Integration Group, a non-profit educational association for engineers, researchers, technologists and policymakers.
[Editor’s Note: RTO Insider will have additional coverage from the conference later in Tuesday’s newsletter.]
Hot and humid weather some 5 degrees higher than forecast and 1,600 MW of unplanned generator outages sent ISO-NE power prices soaring last Monday and led the RTO to purchase emergency energy from New York and Canada.
Temperatures hit 96 degrees Fahrenheit in Boston on Sept. 3 with a dew point of 73 as load peaked at 22,956 MW, almost 2,400 MW above the initial forecast of 20,590 MW. The bulk power system saw a five-minute peak of 23,106 MW at 5:50 p.m., according to a Sept. 7 article published on the RTO’s website.
Real-time energy prices rose to $2,454.57/MWh between 4 and 5 p.m., and reserve prices peaked at about $2,500/MWh at times between 3 and 6 p.m.
| ISO-NE
Similar weather conditions, with a heat index at or near 100, were forecast for the following Tuesday. Load peaked at about 23,000 MW, in line with forecasts, and no alerts were issued. Boston peaked at 85 degrees.
When the dew point is above 70, every 1-degree increase can cause load to rise by about 500 MW, with rising temperatures causing similar effects on load.
The RTO implemented Master/Local Control Center Procedure No. 2 (M/LCC 2) at 3:15 p.m. Monday, declaring an Abnormal Conditions Alert and directing generators and transmission owners to stop or postpone any maintenance activities that could jeopardize system reliability.
Fifteen minutes later, the RTO implemented Operating Procedure 4, Actions 1 and 2. Action 1 declares a Power Caution, saying available capacity resources are insufficient to meet anticipated demand plus operating reserve requirements. Action 1 also allows the RTO to begin depletion of 30-minute operating reserves. Action 2 declares a Level 1 energy emergency alert.
At 4 p.m., system operators issued a Power Watch and implemented two other actions of OP4, asking market participants to reduce energy consumption at their own facilities and arranging for purchase of emergency capacity and energy from neighboring systems.
All of the alerts were lifted by 9 p.m.
ISO-NE spokeswoman Marcia Blomberg told RTO Insider that the Labor Day heat resulted in “higher-than-expected demand, as well as some generator outages” and that the RTO purchased emergency power from New Brunswick and New York for a short time. “While we implemented Action 4 of OP4, declaring a Power Watch, we didn’t issue a request for voluntary conservation. We were monitoring the system and could have issued an appeal if conditions had deteriorated.
Emergency purchases from NYISO totaled 251 MW from 5 to 5:30 p.m. and 100 MW in the following half-hour, while emergency purchases from New Brunswick totaled 150 MW from 4:20 to 5:14 p.m. and 229 MW from then until 6 p.m.
“However, conditions improved rapidly as demand began to decline in the late afternoon and offline generators were able to come online quickly,” Blomberg added.
ISO-NE’s operations shift supervisor or one of its six local control center system operators can declare an abnormal condition under several scenarios, including a forecasted or actual deficiency of operating reserves. The local control centers, which are run by transmission owners, are generally responsible for transmission facilities rated 69 kV and below.
The RTO reported “underperforming resources will be penalized at a rate of $2,000/MWh for failing to meet their obligation during energy shortfalls, while resources that overperform (including resources with no obligation) will receive $2,000/MWh of additional revenue.”
The performance payment rate will increase to $5,455/MWh over the next six years.
Responding to stakeholder demands to resolve a yearlong dispute, PJM’s Stu Bresler has sent a letter outlining his requirements for accepting the Independent Market Monitor’s opportunity cost calculator.
The public pronouncement of PJM’s terms was unexpected but welcomed. “I’m surprised that PJM has apparently decided to negotiate this publicly,” Monitor Joe Bowring said. “We will respond.” Bowring declined to address whether PJM’s terms were acceptable and detailed enough.
For more than a year, PJM and its Monitor have been unable to agree on a single calculator for opportunity costs included in generation offers. PJM argues that FERC Order 719, issued in October 2010, allows the Monitor to provide input on cost determinations but that “PJM retains the ultimate decision-making authority.” From then until “the latter part of 2016,” both calculators produced consistent results, Bresler said in his letter, but have since diverged substantially.
PJM says it can’t endorse the Monitor’s calculator until staff understand how and why it produces different results. For that reason, PJM announced in August it would only accept opportunity cost calculations using its calculator.
The Monitor argues that it has continued to enhance its calculator while PJM hasn’t changed its methodology since 2010.
PJM staff have asked to understand the calculator’s inner workings, but Bowring has been reluctant to fully throw back the curtain, arguing that PJM staff haven’t specifically detailed their requests and that the underlying computer code is proprietary intellectual property.
Generators say the dispute has left them in a bind, fearing a referral to FERC enforcement for using an unapproved number.
At the Aug. 23 Markets and Reliability Committee meeting, generators attempted to force a resolution by threatening Tariff revisions that would require PJM to accept the Monitor’s calculator. (See Stakeholder Proposal Aimed at Ending PJM-IMM Dispute.)
Bresler’s letter details three requests to the Monitor:
the design requirement specification documents for the Monitor’s calculator, including descriptions of steps taken to calculate adders and accompanying mathematical formulas.
alternatively, the calculator’s output from pre-defined sample inputs and parameters so PJM can compare the results with its calculator’s output using the same inputs.
a commitment to notify PJM of any changes to the calculator and to rerun the comparative analyses afterward.
Bresler, PJM’s senior vice president of operations and markets, shot down an earlier suggestion from Bowring that they allow a third-party auditor to compare the calculators, saying it was less efficient and more expensive than his solutions. He gave Bowring a Sept. 10 deadline to respond to the proposal.
The Members Committee is set to vote on the proposed Tariff revisions on Sept. 27, barring an agreement before then.
Order 890’s transparency provisions do not apply to “asset management” projects that provide only “incidental” increases in transmission capacity, FERC ruled in two orders Friday.
The commission rejected complaints by California regulators and others who contend Pacific Gas and Electric and Southern California Edison are violating Order 890’s transparency provisions because much of their transmission planning is done without stakeholder input or review.
The California Public Utilities Commission, Northern California Power Agency, the city and county of San Francisco, the State Water Contractors and the Transmission Agency of Northern California filed the complaint against PG&E in February 2017.
The agencies complained that PG&E offered no stakeholder or external review on almost 80% of its transmission capital projects, including substation upgrades, replacement of deteriorating transmission equipment, system reliability and automation, and technology infrastructure.
| PG&E
But the commission said such activities were generally not subject to Order 890 because they provide no more than incidental increases in transmission capacity — such as replacing a 1940s-vintage transformer with modern equipment “which could be of a higher capacity if the PTO [participating transmission owner] has standardized transformer sizes across its system to allow for sparing should the transformer fail” (EL17-45).
“While Order No. 890 does not explicitly define the scope of ‘transmission planning,’ the commission adopted the transmission planning requirements in Order No. 890 to remedy opportunities for undue discrimination in expansion of the transmission grid,” FERC said. “Based on the information in the record, we find that the specific asset management projects and activities at issue here [are designed to] maintain [PG&E’s] existing electric transmission system and meet regulatory compliance requirements.”
The commission acknowledged asset management could result in significant transmission capacity increases, “for example, where a PTO determines that it can address a CAISO-identified transmission need by expanding the scope of an asset management project or activity to result in a capacity increase.”
“Accordingly, the incremental portion of the asset management project or activity would be subject to the transmission planning requirements of Order No. 890 and would have to be submitted for consideration in CAISO’s [transmission planning process] through the request window. If CAISO did not approve the incremental work, then the PTO should not expand the scope of the original asset management project or activity without that work being subject to consideration through an Order No. 890-compliant transmission planning process.”
The commission also said it “strongly encourage[s] PG&E to continue its efforts to work with complainants and other stakeholders to develop a process to share and review information with interested parties regarding asset management projects and activities that are not considered through the” CAISO transmission planning process.
SoCal Edison Review Process OK’d
FERC used the same reasoning in rejecting the PUC’s request for a show-cause order finding that Order 890 governs transmission owners’ planning for self-approved projects.
Instead, the commission approved SCE’s tariff change creating a process for sharing information with stakeholders about its asset management projects not subject to Order 890 (ER18-370, AD18-12).
The commission said the transmission maintenance and compliance review process “offers transparency and the opportunity for stakeholders to have input into the development of SoCal Edison’s transmission rates.” It ordered SCE to make a compliance filing within 30 days adding provisions the company proposed in response to protesters’ concerns.
FERC has granted PJM’s request to delay its annual Base Residual Auction, from May to Aug. 14-28, 2019, after recently extending filing deadlines for its paper hearing on the RTO’s capacity construct (ER18-2222).
| AdobeStock
The initial and reply testimony deadlines were extended to Oct. 2, 2018, and Nov. 6, 2018, respectively, at the request of the Organization of PJM States Inc. (OPSI). FERC ordered the hearing after rejecting both proposals PJM offered in its “jump ball” filing and ruling that the RTO’s existing capacity construct isn’t just and reasonable. FERC instead suggested a fixed resource requirement (FRR) hybrid.
PJM asked for the delay because the extended comment deadlines indicated that FERC would be unlikely to issue a ruling on the hearing by Jan. 4, 2019, the date that PJM previously said would accommodate holding the BRA as planned in May while still including whatever revisions FERC orders.
Several PJM stakeholders have proposed revisions to the capacity auction. PJM recently unveiled to stakeholders and nondecisional FERC staff its proposal, which it dubbed the Resource-specific Carve Out (ReCO). It would start with a subsidized generation resource exiting the capacity market with a corresponding amount of load rather than the FRR’s inverse of a designated amount of load exiting the capacity market with a corresponding resource. (See PJM Unveils Capacity Proposal.)
On Aug. 29, the commission issued a procedural order granting itself more time to consider motions requesting rehearing of its order recommending the capacity market changes (EL16-49, et al.).
FERC on Friday accepted revisions to PJM’s long-term financial transmission rights auctions to correct current processes that might overstate available system capacity and harm auction revenue rights holders (ER18-1968).
The current process allows long-term FTR market participants to obtain the rights to congestion on transmission paths before the owners of the underlying ARRs.
Following each annual FTR auction, PJM conducts a long-term FTR auction for the three planning years immediately following the planning year during which the long-term FTR auction is conducted. Offered for sale is the residual system capability after the annual ARR allocations and the annual FTR auction. In determining the residual capability, PJM assumes that all allocated ARRs are self-scheduled into FTRs, which are modeled as fixed injections and withdrawals in the long-term FTR auction.
Cleared auction volume (MW) as a percent of total FTR cleared volume by calendar month | Monitoring Analytics
Under the new rules, PJM will revise how it compiles the paths available in the auction by conducting an additional, offline annual allocation of ARRs prior to the opening of each round of the long-term FTR auction. The procedure will use the same topology as the annual ARR allocation except that all transmission outages will be returned to service and PJM will perform its simultaneous feasibility test to determine the set of ARRs to be preserved for the long-term FTR auction. (See “Stakeholders Approve Manual, Operational Changes,” PJM MRC/MC Briefs: June 21, 2018.)
FERC also granted PJM’s request to eliminate the three-year long-term FTR product. The auction currently offers FTRs separately for each of the subsequent three planning years, as well as for all three years combined. Historically, bidding for the three-year product is low and eliminating it will increase the efficiency of PJM’s FTR software, the RTO said.
The commission also granted PJM’s Sept. 3 effective date in order to implement the changes in the next round of its long-term FTR auction commencing Sept. 4.
RTO Insider filed a complaint Friday asking FERC to overturn the New England Power Pool’s ban on press coverage of its meetings or terminate the group’s role and direct ISO-NE to adopt an open stakeholder process similar to those used by other RTOs.
The Section 206 complaint (EL18-196) comes two weeks after NEPOOL submitted a proposal to FERC seeking to codify an unwritten policy of banning news reporters and the public from attending the group’s stakeholder meetings . (See NEPOOL Files Press Ban with FERC.) New England is the only one of the seven U.S. regions served by RTOs or ISOs where the press and public are prohibited from attending stakeholder meetings.
NEPOOL’s proposed amendments to the NEPOOL Agreement would add a definition of “press” and bar anyone working as a journalist from becoming a NEPOOL member or alternate for a participant. The group drafted the revisions after RTO Insider reporter Michael Kuser, who lives in Vermont, applied for membership in NEPOOL’s Participants Committee as an end-user customer in March.
Chilling Discussion?
In its filing, NEPOOL contended that allowing press to become a participant “would adversely impact the power pool’s ability to continue to foster candid discussions and negotiations in its stakeholder meetings.” Absent those discussions among its members, ISO-NE and state officials, NEPOOL “would be limited in its ability to narrow or resolve complex issues within the NEPOOL stakeholder process,” the group said.
It cited concerns that press attendance at meetings “could encourage public posturing, pre-scripted statements and reduced willingness or ability by members to freely explore ideas or solutions.”
FERC Commissioner Neil Chatterjee spoke at NEPOOL’s December Participants Committee meeting at the Colonnade Hotel in Boston. | NEPOOL
NEPOOL’s case for maintaining privacy pivots on the argument that it does not function in the same manner as other RTOs. Its filing notes that “unlike other regional transmission organizations in which stakeholders are assembled by and at the direction of the particular RTO, NEPOOL is and always has been an independent, separately organized stakeholder body.”
To support its claims, the power pool’s filing included the testimony of Robert Stein, principal consultant at Signal Hill consulting group, who said he has participated in the NEPOOL stakeholder process since beginning his career in the power industry in 1971.
Stein testified that the power pool’s meetings have always been “nonpublic,” and expressed concern that the press’ presence would change the “tenor and tone” of NEPOOL meetings “in a very unhelpful way.”
“Over the years I have both observed and participated in discussions at meetings where positions were taken and changed in our non-public setting,” he said. “This would be much less likely if members are concerned that those positions, as they may evolve during the NEPOOL process, could appear in press reports and need to be defended publicly. There are many examples, such as in diplomacy and labor negotiations, where the ability to negotiate outside the public spotlight is important if not essential.”
‘No Apparent Basis’
RTO Insider responded that Stein “has no apparent basis for this speculation” given his testimony that NEPOOL meetings have always been nonpublic and that he has worked his entire career in New England.
RTO Insider estimated it has covered 900 stakeholder meetings in the other six RTOs/ISOs since 2013 and said its reporters can recall fewer than 10 instances of a stakeholder representative reading from a prepared speech.
RTO Insider’s Aug. 31 complaint contended that nonpublic meetings violate the public interest and the missions stated in ISO-NE’s and NEPOOL’s governing documents.
It also contested NEPOOL’s assertion that it is a private organization, saying that FERC precedent “hardwires the NEPOOL stakeholder process into the regulatory process by requiring its use.” It noted that ISO-NE’s Participants Agreement with NEPOOL requires the RTO “to present proposals for changes to market rules, operating procedures, manuals, reliability standards, general tariff provisions, or non-[transmission owner] [open access transmission tariff] provisions for governance participant consideration and NEPOOL participant vote.”
NEPOOL conducted 253 votes on 56 meeting days in 2017. All the meetings were closed to the public and press. | NEPOOL
RTO Insider pointed to another special privilege enjoyed by NEPOOL: its so-called “jump ball” filing rights at FERC. In cases when ISO-NE submits a market rules proposal that differs from one approved by the Participants Committee on a 60% vote, that provision entitles NEPOOL to file a competing proposal that the commission can adopt in full.
“This is an extraordinary right because it negates the right an RTO/ISO would otherwise have for its [Federal Power Act] Section 205 filing to be accepted if just and reasonable (or not unjust and unreasonable), rather than having to demonstrate that its filing is superior to alternatives,” RTO Insider contended.
The publisher also contended that, given NEPOOL’s role in transmission planning, failure to provide openness and transparency violates FERC Order 890. Banning the press and public from meetings also discriminates against smaller entities and potential new entrants to the New England market, the complaint said.
The publisher noted that ISO-NE, through NEPOOL, is the only RTO/ISO in the country that bars the press and public from its stakeholder process. “NEPOOL is well aware of this uniqueness, but nowhere in its 15-page transmittal letter in support of formalizing its press ban does it attempt to explain why ISO-NE/NEPOOL are fundamentally different from all the other RTO/ISOs,” the complaint said. “Nowhere does NEPOOL explain why secrecy is critical for it and it alone.”
RTO Insider said that if the power pool can justify its press ban as a “private” entity desiring secrecy, “its special powers and privileges should be transferred to an open stakeholder process within ISO-NE, and the ISO-NE resources devoted to NEPOOL (currently $2.6 million annually) should be devoted to an open stakeholder process within ISO-NE.”
NEPOOL Docket
RTO Insider also will file the complaint as a protest in the docket opened by NEPOOL (ER18-2208).
No one else has thus far filed substantive comments, although Consolidated Edison, Avangrid, Public Citizen and New Hampshire Consumer Advocate D. Maurice Kreis have filed motions to intervene. FERC extended the deadline for comments in that docket by 10 days to Sept. 14.
“Somehow the nation’s other six RTOs manage to make difficult policy choices without a secret governance body for stakeholders,” Kreis said in a June 25 blog post on InDepthNH.org.
Kreis told RTO Insider that he found the argument that press attendance will have a chilling effect on NEPOOL stakeholder discussions “to be cosmically unpersuasive.”
“I don’t get to go to a lot of NEPOOL meetings. Having third-party summaries of meetings [from the press] is going to help me do my job,” he said.
FERC last week approved a reduced return on equity for Pioneer Transmission’s portion of a recently completed 765-kV line in Indiana.
The commission’s Aug. 30 order reduces Pioneer’s ROE to 10.82% from the 12.54% approved in 2009, which included a 150-basis-point (bp) adder as a new interregional project (ER18-1159).
Pioneer, a joint venture of American Electric Power and Duke Energy, will use the ROE in its formula rates to recover costs for it and Northern Indiana Public Service Co.’s 65-mile, 765-kV Greentown-to-Reynolds line.
Pioneer in March proposed to adopt MISO’s 10.32% base ROE for transmission owners, with a 50-bp adder for RTO participation and the 150-bp adder for new transmission.
FERC allowed the base ROE and adder for RTO participation but denied the 150-bp adder because the current project does not include PJM.
Regional Processes
The Pioneer Project was intended as a single, $1 billion, 240-mile project across MISO and PJM to address “a critical shortage of high voltage transmission” in Indiana and help transport new wind generation from the state’s southwest to its central and northern regions.
At the time the project was proposed a decade ago, the MISO-PJM interregional planning process did not have “a tariff mechanism in place for evaluating and approving an interregional project such as the Pioneer Project that provided benefits to both RTOs,” according to Pioneer.
The company said it broke the project into smaller segments to be reviewed under PJM’s and MISO’s separate regional processes after encountering difficulties getting the RTOs to approve the line as an interregional project.
Pioneer and NIPSCO took up a $347 million Greentown-Reynolds line, which was approved in MISO’s 2011 multi-value project portfolio. This June, the MISO Board of Directors voted to add Pioneer as a MISO TO, and Pioneer has handed over operational control of the completed line.
FERC said the 150-bp adder would not go into effect “unless and until the project is approved by the regional transmission planning processes of [PJM and MISO] and there is a commission-approved cost allocation methodology in place.”
FERC said because the line had been broken into regional segments, it could not meet the condition that the Pioneer Project be included in both the PJM and MISO transmission plans. Pioneer had argued that the condition was no longer applicable or should be waived because the project “continues to be a large-scale transmission project and the first 765-kV transmission facilities in MISO’s service area.”
In its Aug. 30 order, FERC said Pioneer was free to apply for the new transmission incentive again once it could satisfy the requirement.
“Our denial of the 150-basis-point ROE adder is without prejudice. If Pioneer satisfies the commission’s previously stated conditions, then Pioneer may make a Section 205 filing to seek to prospectively implement the full 150-basis-point ROE incentive that the commission previously granted,” FERC said, adding that it “continues to value transmission rate incentives as a tool to encourage investment in new transmission.”
“In that vein, we encourage Pioneer to continue its efforts to complete the Pioneer Project,” the commission said.
NYISO’s Management Committee agreed Wednesday to relax its minimum 20-MW constraint reliability margin value in its initiative to price transmission constraints on 115-kV facilities.
The ISO’s Tariff currently requires at least 20 MW be set for any non-zero constraint reliability margin value used in the day-ahead and real-time markets
David Edelson, NYISO manager of operations performance and analysis, noted as an example that a 20-MW CRM equals 13% of the rating for 115-kV lines with post-contingency limits of 150 MW, limiting them to 130 MW in dispatch.
115-kV transmission line | Exponential Engineering
By contrast, for a 345-kV circuit with a 1,550-MW post-contingency rating, a 20-MW CRM represents only about 1% of the line rating.
Edelson said the ISO wants to limit CRMs to no more than 10% of a facility’s rating to allow for the continued pricing of transmission constraints on lower-voltage lines.
NYISO wants to change the Tariff to permit CRMs of less than 20 MW until it can implement enhancements under its constraint-specific transmission shortage pricing project. The ISO said the timing of that project is subject to stakeholders’ prioritization and scheduling.
The ISO would publish on its website a list of transmission facilities and interfaces assigned a CRM other than 20 MW.
The rule change will be presented to the Board of Directors for approval in September. The committee approved the proposal unanimously by a show of hands.
