FERC on Monday granted NYISO eight extra months — until year-end — to fix a “misalignment” between its market software and its Tariff rules (ER20-1470).
Section 4.4.1.2.1 of the ISO’s Services Tariff allows generators that are committed day-ahead only for non-synchronous operating reserves to modify their minimum generation bids in real-time, but the ISO recently discovered that its software does not provide the flexibility intended by that provision.
NYISO explained that its software currently is preventing all generators, even those that only receive a day-ahead schedule for non-synchronous operating reserves, from modifying their minimum generation bids in real-time.
The ISO said it expects to deploy the necessary software improvements coincident with its broader software revisions to implement fast-start pricing reforms that the commission already accepted in a February order (ER20-659).
NYISO reports 96.5% of RTD intervals had 1,800 MW or more of SENY 30-minute reserve procured. | NYISO
Granting the waiver “will allow NYISO to develop and implement software consistent with its business practices without the need to rush a software patch,” the commission said.
However, the waiver will be in effect for only the period necessary for NYISO to code software modifications, perform the necessary quality assurance testing and deploy the software consistent with its standard software development practices, the commission said.
NYISO also asked the commission to “excuse any instances of past non-compliance with the provision at issue,” adding that any such instances “cannot be corrected or reversed.”
“Upon consideration, we will exercise our discretion in addressing such matters and, given the facts and the record before us in this matter, we take no action with respect to the instances of NYISO’s past non-compliance,” the commission said.
FERC has authorized the owners of the 1,000-MW Champlain Hudson Power Express (CHPE) project to charge negotiated transmission rates to carry Canadian hydropower to New York City.
The commission’s May 29 order also granted the project developer’s request for waiver of certain reporting requirements (ER20-1214).
The $3 billion high-voltage direct current (HVDC) merchant transmission proposal has succeeded in allying two Democrats who have not always got along well — New York City Mayor Bill de Blasio and Gov. Andrew Cuomo, though each in his own way has championed clean energy. (See Cuomo Sets New York’s Green Goals for 2020.)
CHPE is owned by TDI-USA Holdings (TDI), which is in turn majority-owned by the investment firm Blackstone Group. Despite controlling $571 billion in assets, Blackstone does not own or control any existing electric transmission or distribution facilities in the markets operated by NYISO or Hydro-Québec.
Champlain Hudson Power Express project map | Champlain Hudson Power Express
Under commission precedent, merchant transmission projects differ from those of traditional public utilities in that the developers assume the full market risk of a project and have no captive customers from which to recover costs. Thus, the commission has allowed some such projects to be priced based on negotiated rates and has granted waivers of certain requirements.
FERC acknowledged CHPE’s commitment to turn over operational control of the project to NYISO, comply with all applicable reliability requirements and provide NYISO with all required information necessary for its regional transmission planning process pursuant to Order 1000. The commission also noted that CHPE will retain “an experienced third-party independent expert” to advise the company on its open solicitation and capacity allocation process in order to ensure that its solicitation process is not “unduly discriminatory and preferential.”
“We will, however, reserve judgment on whether the open solicitation and capacity allocation process once implemented are not unduly discriminatory, pending CHPE making a compliance filing within 30 days of the close of its open solicitation process,” the commission said.
The commission also granted CHPE’s request for waiver of Part 141 of the commission’s regulations, including the Form No. 1 annual reporting requirement for electric utilities, noting it has previously granted such waivers for other merchant transmission owners.
The commission also granted CHPE waiver of the full reporting requirements of Subparts B and C of Part 35 of FERC regulations, with the exception of sections 35.12(a), 35.13(b), 35.15 and 35.16.
Gov. Cuomo has recently spoken in favor of the CHPE project, prompting a swift protest from the Independent Power Producers of New York (IPPNY).
“This line is both unnecessary, given in-state developer demand, and provides no environmental benefit,” said IPPNY President and CEO Gavin J. Donohue in a statement.
IPPNY in January released a study it commissioned from Energyzt showing that “the purchase of hydropower over CHPE will not result in reduced global emissions of carbon dioxide – and may even increase overall carbon emissions.”
“Spending more than $3 billion to support the profiteering of a Canadian company on a project that will not revitalize the state’s economy and will not actually provide an environmental benefit is a mistake,” Donohue said. “Expanding New York’s own renewable energy industry will allow for guaranteed emissions reductions while creating in-state jobs.”
Shortage pricing played a crucial role in Texas wholesale market competitiveness last year, ERCOT’s Independent Market Monitor said in its annual market report.
The report from Potomac Economics showed average real-time energy prices rose by 32% in 2019, despite a 23% reduction in natural gas prices. The Monitor attributed the increase to shortage pricing in August and September, when prices reached the offer cap of $9,000/MWh for more than two hours.
ERCOT’s average all-in price for electricity highlights August spike. | ERCOT IMM
“Shortage pricing is key in ERCOT’s energy-only market because it plays a pivotal role in facilitating long-term investment and retirement decisions,” the Monitor said, the idea being that high prices during energy shortages will incent new generation.
ERCOT entered last summer with a reserve margin of 8.6%, which is up to 12.6% this summer. The Monitor said only 4.5% of the grid’s generation was unavailable during summer peak conditions, similar to 2018 but lower than the 6% during 2016 and 2017.
“We attribute this increased availability to the effectiveness of the shortage price signals in motivating participants to increase maintenance and minimize outages during the summer peak,” the Monitor said.
The Texas Public Utility Commission in January modified ERCOT’s shortage pricing mechanism by altering the market’s operating reserve demand curve. The changes accounted for a nearly $7/MWh increase in average energy prices and a $1.9 to $2.1 billion increase in energy revenue.
The PUC has also approved the real-time co-optimization of energy and ancillary services, scheduled to be added to the market in 2024.
“This will significantly improve the real-time coordination of ERCOT’s resources, lower overall production costs and improve shortage pricing,” the Monitor said. “These improvements will be increasingly valuable as additional intermittent wind and solar resources enter the ERCOT market.”
In its report, the Monitor recommends key improvements to ERCOT’s pricing and dispatch processes:
Remove the “opt-out” option for resources receiving reliability unit commitment instructions.
Eliminate the 2% shift factor rule, and price all congestion regardless of its generation effect.
Modify the allocation of transmission costs by transitioning away from the four coincident peak (4CP) method.
Price ancillary services based on the shadow price of procuring each service.
Modify the reliability deployment adder and operating reserve adder to improve pricing during emergency response service deployments.
Implement a locational reliability deployment price adder.
Improve the mitigated offers for generating resources.
Implement transmission demand curves.
The Monitor retired six other recommendations no longer needed, including the inclusion of marginal losses in ERCOT’s LMPs. The PUC has concluded the incremental benefit of applying marginal losses was not worth the implementation cost and market disruption.
The market report was the first delivered under the guidance of Monitor Director Carrie Bivens, who promised a “timely and comprehensive” report when she was hired in April. (See Bivens Steps in as New Director of ERCOT Monitor.)
PJM stakeholders agreed Thursday to consider integrating HVDC converters as a new type of capacity resource in the RTO.
An issue charge by Direct Connect Development was endorsed by the Markets and Reliability Committee with a sector-weighted vote of 4.4 (88%), well above the 50% threshold.
Steve Frenkel, vice president of Direct Connect, presented the issue charge and problem statement, which seek to establish HVDC converter stations’ eligibility to participate in the capacity market.
Winning such a change would allow Direct Connect’s SOO Green HVDC Link — a 350-mile, 2,100-MW, 525-kV underground transmission line that would deliver renewable energy from upper MISO to Illinois and the PJM grid — to compete in the market.
“SOO Green is a merchant, non-cost-allocated project that is using innovative technology and commercial structures to match buyers and sellers,” Frenkel said.
The Project
Direct Connect is planning to install the SOO Green line underground primarily along existing rail rights of way from Mason City, Iowa, to Plano, Ill., which Frenkel said would be the first major transmission project crossing the MISO-PJM seam. Construction is expected to begin in early 2022 and be completed by 2024.
Frenkel said the converter station will be directly connected to the PJM system and able to follow dispatch instructions and deliver energy on demand from a portfolio of “firm” generation supply, mostly wind turbines.
| SOO Green
The PJM Tariff currently does not allow HVDC converters to participate in the Reliability Pricing Model market, which presents a market barrier to merchant resources seeking to sell bundled energy and capacity, he said.
While the converter station will be an internal resource within PJM able to offer comparable performance and services to other resources, Frenkel said, the RTO’s current rules do not recognize HVDC converter stations as a capacity resource.
Opposition
Calpine’s David “Scarp” Scarpignato said he was in favor of seeing the line built, but he said his company had concerns about taking on another issue charge with the amount of work already being done in the stakeholder process.
Scarp said he understood there are issues that need to be addressed, but in the HVDC issue, he said Calpine came to the “firm conclusion” that there was no problem that needed to be addressed. He said SOO Green can participate in the market through current processes, and the generators behind the line could also participate by following existing processes through pseudo-tie rules.
“We’re breaking apart the current paradigm if you do this,” Scarp said.
Frenkel said the existing Tariff does not address the market innovation his company is proposing.
“We’d appreciate the members be willing to have a conversation about how this technology can participate in the market,” Frenkel said.
Paul Sotkiewicz of E-Cubed Policy Associates, representing Elwood Energy, said the HVDC issue didn’t seem like a high-priority item to discuss. He agreed with Calpine’s assertion that there were no obstacles to SOO Green’s participation that weren’t already addressed in the Tariff.
Sotkiewicz said all stakeholders should be able to bring issues they see as problematic up for discussion. But he said the problem statement and issue charge for SOO Green was a “single company” issue.
“What I worry about is now this sets a precedent that allows all of us the ability to bring a very specific, focused issue charge to the membership,” Sotkiewicz said. “If we all did, I worry that we’d completely flood the stakeholder process and simply paralyze it and really get so far down in the weeds we can’t even see.”
Frenkel said it is a “resource class” issue.
“While SOO Green may be the first project to cross the transom and rise to the level of attention of stakeholders, we don’t see this as a single proposal,” Frenkel said. “It’s really about opening up an opportunity for a class of innovative resources.”
PJM’s plan to hire a consultant to review the RTO’s auction revenue rights (ARRs) and financial transmission rights markets appears likely to set up a conflict between load-serving entities and financial traders.
A draft of the proposed scope of work shared with stakeholders Wednesday poses nine issues for the consultant to address, one-third of which question the current market’s balance between LSEs and other market players.
“Is load systematically disadvantaged under the current mechanism?” PJM asks. “Are there aspects of the current mechanism that result in profits to non-load-serving participants without commensurate or associated benefit to load?”
The draft also questions whether the current allocation of balancing congestion to load is appropriate, noting that “much of the negative balancing congestion in PJM can be attributed to financial products available in the day-ahead market, primarily up-to-congestion transactions (UTCs).”
It also asks whether the ARR allocation methodology should be changed “in order to increase the value of ARRs to load.”
Dave Anders, PJM director of stakeholder affairs, who presented the draft to the ARR/FTR Market Task Force on Wednesday, said the RTO is seeking a consultant that has sufficient knowledge of the subject matter while also being independent enough to provide a “fresh look” at the issues.
Anders said he recognizes stakeholders have a wide variety of views regarding what the consultant should accomplish.
“We want to make sure that stakeholders view the selection of the consultant, as well as the work that they perform, as credible,” Anders said.
The draft includes an “overarching question” that asks whether the current ARR allocations and FTR auctions “constitute an appropriate mechanism in an LMP-based market by which to ensure that load receives the value of the transmission system for which it is paying through” network integration transmission service (NITS) and firm point-to-point transmission service charges.
Anders said PJM is requesting that the consultant first gain an understanding of the RTO’s ARR/FTR mechanism and FERC orders that created the structure.
The scope of work also questions:
the virtues of path-based vs. network allocations of CRRs;
whether modeling differences between day-ahead and real-time markets are a cause for concern;
whether new products should be offered, including a path-based FTR, and FTRs of different tenors (e.g., weekend-only, seven-day on-peak hours);
whether some products should be removed from the FTR auctions; and
whether FTR trading points that should be added or removed.
Susan Bruce of the PJM Industrial Customer Coalition said the independent review is something industrial customers are “welcoming with open arms.”
Bruce said her group would like to see the scope of the consultant’s review to include the role of the FTR market in generation development and understanding the role of liquidity in countering market power. “If [the FTR/ARR markets are] serving their intended purposes, then great,” she said. “If not, then let’s look under the hood a little bit more closely.”
Joe Wadsworth of Vitol said the questions concerning potential new products address practical commercial uses and were out of place in the consultant’s scope of work. “To me, it’s more of a practical commercial issue that would be driven by the experience of market participants that actually utilize the product,” Wadsworth said.
Anders said the experience of market participants and commercial use of the product is something that should be considered in any determination to change the product mix. He also said the information that consultants could provide isn’t necessarily a determination of whether a change is made.
Any changes resulting from the consultant’s review would go through the normal stakeholder process, Anders said.
The review is expected to last a couple of months, Anders said, and will be dependent on feedback received from the consultant candidates.
Anders said PJM would not reveal the list of potential consultants now but said the RTO will make its selection and define the scope of the project “informed by input from all stakeholders.”
During the task force meeting, the Independent Market Monitor outlined its proposal to directly allocate congestion revenues to LSEs.
Exelon, NextEra Resources and Public Service Enterprise Group countered with a presentation that alleged the Monitor’s proposal would hurt customers, saying it “fails to understand how congestion and FTRs are currently employed by LSEs to manage risk.”
Coal plant self-commitments saddled Midwest electricity customers with $350 million in unnecessary costs in 2018, according to a new analysis from the Union of Concerned Scientists, which is calling on regulators to rein in the practice through investigations.
“Used, But How Useful?” concludes that individual ratepayers could have saved an average of $60 if the most efficient existing resources in MISO were deployed instead of coal self-scheduling in 2018.
“We found that not every coal plant in the Midwest operated uneconomically, but the utilities that did it the most drove down market prices, effectively squeezing out cleaner, cheaper sources such as wind and solar power,” Sandra Sattler, senior energy modeler at UCS, said in a press release.
UCS said savings from eliminating the self-dispatches could have more than doubled the amount MISO claimed it saved its members that year through efficient centralized dispatch. The RTO’s 2018 value proposition estimated its efficient energy dispatch saved members anywhere from $282 million to $312 million during the year.
“We decided that having a published report on which utilities were not acting in the public interest would be useful to regulators. We hope this will be a helpful tool for commissioners trying to tackle this problem,” UCS Climate and Energy Senior Energy Analyst Joe Daniel told RTO Insider.
This isn’t the first time UCS has publicly questioned the practice of vertically integrated utilities being allowed to operate units out of merit at times when their production costs exceed the wholesale market price. UCS pressed the issue last year at the National Association of Regulatory Utility Commissioners’ annual meeting. (See Enviros, States Question Coal Self-commitments.)
Daniel said the solution isn’t as simple as just abolishing must-run designations in MISO.
“There are plenty of power plants that use the must-run designation economically,” he said. “The uneconomic commitments will continue in another loophole unless state regulators come in and stop it.”
Daniel said a good first step for regulators is to open investigatory dockets into utilities that exhibit high costs.
“That way there’s a frank discussion between regulators, utilities and intervenors,” Daniel said. “The regulators have an obligation to disallow imprudent costs. … Running power plants that are expensive when there’s lower-cost energy available on the open market is imprudent. … If a commission would scrutinize and disallow tens of millions in imprudent costs, I am confident that the utility’s reaction would be to figure out how to solve the problem themselves. Smart utilities won’t let it get to that point. Smart utilities will see that commissions are taking things seriously and be proactive.”
When the Minnesota Public Utilities Commission opened a docket last year to investigate Xcel Energy’s self-scheduling of coal plants, Daniel said, the utility quickly proposed converting its coal plants to seasonal and economic use. Missouri and Indiana have also opened investigatory dockets into utility self-commitments. (See Ind. Regulators Scrutinize Duke Self-commitments.)
Biggest Offenders
According to the UCS report, Xcel subsidiary Northern States Power uneconomically ran its Allen S. King and Sherburne Country coal plants at a $56.9 million loss in 2018. If the utility had opted for more efficient generation in the MISO market, the average residential ratepayer could have saved $54 that year, UCS said.
UCS named Cleco Power the worst offender, saying it uneconomically generated electricity from its Dolet Hills and Brame Energy Center coal plants at a $123.3 million loss in 2018, costing Louisiana ratepayers an average of $184 over the year compared with more economic electricity available in the market.
Dolet Hills co-owners Cleco and Southwestern Electric Power Co. have indicated they may retire the plant as early as 2021. Earlier this year, the utilities agreed to retire the plant by 2026 as part of a deal reached with the Sierra Club. The conservation group has claimed that closing the plant would save ratepayers more than $60 million per year.
Dolet Hills power plant | Cleco Power
Cleco spokesperson Jennifer Cahill pointed out that the company and SWEPCO pledged beginning last year to only operate Dolet Hills in the demand-heavy summer months, or when requested by MISO.
“Furthermore, Cleco Power intends to seek regulatory approval to retire the Dolet Hills Power Station and the nearby mine that supplies the plant with coal. The closing dates for the power station and mine will be subject to discussions with stakeholders, including the Louisiana Public Service Commission and regional transmission organizations,” Cahill said in an email to RTO Insider.
DTE Energy’s five coal plants uneconomically generated power at a $94.7 million loss in 2018, costing individual ratepayers an extra $61, UCS also reported.
UCS said MISO’s greatest potential for savings “generally appear where the worst actors operated: Xcel Energy in Zone 1, Cleco in Zone 9, and DTE and Consumers Energy in Zone 7.”
The report also said coal self-commitments in MISO suppressed market clearing prices by 2.4% — or 63 cents/MWh — in 2018. The group also noted the self-commitments suppress independent power producers’ revenue in “all MISO transmission zones.”
“By exploiting gaps in regulatory oversight and loopholes in wholesale market rules, rate-regulated utilities are cutting ahead in the merit-order line. Rate regulation, coupled with a lack of scrutiny when it comes to cost recovery, has enabled these utilities to lose money in the market without incurring actual losses on their balance sheets,” UCS wrote, adding that in many parts of the U.S., the cost to buy and burn coal “exceeds the market price in most hours of the year.”
Self-commitment ‘Loopholes’
UCS said it makes economic sense for coal plants to respond to market price signals and begin operating more infrequently, allowing lower-cost natural gas and renewables to fill the gap. But the group characterized existing state regulatory frameworks and rate cases as “loopholes” that allow unchecked self-commitment decisions to persist.
“It is doubtful that changes to this practice will materialize if regulated utilities are continually allowed to recover fuel costs, without scrutiny or incentives to improve operations,” UCS said. “Utilities will throw up strawman excuses for why their coal plants are so uneconomic, but it is not incumbent on the regulator to innovate on behalf of the utility. Rather, utility companies are obligated to come up with a solution, and regulators should either approve or disapprove of the companies’ proposals.”
Daniel said residential ratepayer costs are more important than ever, with many staying at home more often because of the ongoing coronavirus pandemic.
And he said new resource additions to achieve UCS’ saving estimates are unnecessary.
“You could safely operate the grid with lower-cost existing resources that already exist. You should use what you have as efficiently as possible. And that’s not what happening. Utilities are preferentially selecting coal-powered plants at the expense of customers,” Daniel said.
To arrive at the millions in potential savings, UCS used modeling software that accounts for MISO system limitations, transmission constraints and power plants’ ramping times and capabilities, Daniel said.
He acknowledged that MISO aggregates the number of uneconomic coal commitments in its footprint but doesn’t call out specific generators or utilities like UCS’ latest analysis.
“What really differentiates this research is we used a production cost model and the same software MISO does to come up with these numbers,” Daniel said.
Given the continued uncertainty of future in-person meetings, ERCOT stakeholders last week endorsed several bylaw amendments and rule changes to improve electronic meetings and votes.
As if to hammer the point home, the changes were among 15 voting items in an email vote that did not become official for two days. ERCOT rules currently require two full business days to allow stakeholders to return their votes.
Vickie Leady, ERCOT’s assistant general counsel, told the Technical Advisory Committee on Wednesday that the grid operator’s bylaws “never contemplated a situation with the scale and duration” in which stakeholders “could not safely convene together in one place.”
“It’s creating a risk to ERCOT,” Leady said.
ERCOT closed its facilities to most outside visitors and canceled in-person meetings in early March. Meetings have been conducted virtually ever since.
Legal staff proposed widening the definition of “urgent matters” to include when it would be “difficult or impossible” for a quorum of directors or subcommittee members to physically convene in one location. The changes would allow teleconference meetings and actions that, if otherwise delayed, “may result in operational (including, but not limited to those activities and functions affecting the ERCOT market or system), regulatory, legal, organizational or governance risk.”
Staff made other changes to the bylaws to closely align with the Texas Open Meetings Act and Texas Business Organizations Code’s teleconference technology methods.
The changes will now go before the Board of Directors during its June 9 teleconference. If approved, the board would issue a call on June 10 for a special meeting to vote on the bylaw changes by July 2. The changes would then be filed with the Texas Public Utility Commission by July 31 for its approval.
The TAC also approved several changes to its rules allowing for roll call votes. Chair Bob Helton, with ENGIE, said the committee would be using consent agendas to compensate for the extra time taken by email votes.
Corpus Christi Tx Project Gets OK
The TAC unanimously approved a $219 million transmission project, previously approved by the Regional Planning Group, that addresses more than 1 GW of future industrial load growth on the north shore of Corpus Christi Bay expected by 2024.
As recommended by staff following an independent review of AEP Texas’ proposal, the Corpus Christi North Shore RPG Project will comprise 36 miles of 345-kV lines, 8 miles of new and upgraded 138-kV lines, two new 345-kV substations and three 345/138-kV transformers.
Cheniere’s Corpus Christi LNG plant under construction | Cheniere Energy
LNG plants account for more than half of the additional load. Cheniere Energy has developed an LNG export terminal in Corpus Christi’s harbor. Two trains are currently in operation, with a third planned to come online in the first half of 2021.
ERCOT’s review concluded that its recommended option does not cause new or additional congestion. Staff determined the 138-kV upgrade met economic planning criteria and added it to the project.
AEP’s Richard Ross said the company “supports and is comfortable at this point in time” with ERCOT’s recommendation.
ERS Payments up 1.6% to $48.2M
Staff shared ERCOT’s annual report on its emergency response service but received no questions from members. The report is required annually by the PUC (27706).
According to the report, demand response and behind-the-meter generation received $48.2 million in capacity payments during the program year for curtailing load or sending power to the grid, a 1.6% increase from the $47.5 million for the previous time period.
ERCOT deployed ERS twice last year during August’s two energy emergency alerts. The two deployments lasted a total of 95 minutes.
Members Disagree over Change to ERS’ Return
The TAC on Friday took up a second email vote to consider the only Nodal Protocol revision request (NPRR1006) that did not clear the email vote.
In a vote that closes at 5 p.m. Tuesday, committee members will weigh NPRR1006’s approval as amended by comments from Direct Energy.
The NPRR had received only four votes (Lower Colorado River Authority, South Texas Electric Cooperative, Exelon and Reliant Energy Retail Services), with 20 members opposing and two abstaining.
The change would return ERS resources in a linear curve over a four-and-a-half-hour period following recall, instead of 10 hours. It also changes the process for annually updating the parameter by removing a real-time deployment price adder from the real-time ancillary service imbalance payment or charge.
Direct Energy expressed concern over the unintended consequences of the price adder’s elimination from the equation. The company urged interested parties to file their proposed changes in a separate NPRR “to facilitate the quick movement of the original intent of this NPRR through the approval process.”
Direct Energy’s Sandy Morris said stakeholders have not had the time or analysis to understand the full implications of the proposed change. Should the matter be separated, she wrote, “it could possibly continue through the proper channels of analysis and debate and still be implemented at the same time as … NPRR1006.”
The committee’s email vote unanimously approved eight other NPRRs, a change to the Nodal Operating Guide, an Other Binding Document revision request (OBDRR) and two system change requests (SCRs):
NPRR933: adds specific timing requirements for retail electric providers and non-opt-in entities to notify ERCOT of the DR and price-response programs they offer to customers, the level of participation in those programs and the deployment events associated with those programs.
NPRR975: clarifies that load forecast models will be used to select the seven-day load forecast based on expected weather and requires ERCOT operations to explain its selection, improving transparency for market participants.
NPRR987: includes the contribution of energy storage resources (ESRs) to physical responsive capability and real-time online reserve capacity in the ancillary service imbalance calculation.
NPRR989: establishes ESRs’ technical requirements for voltage support service (including reactive power capability) and primary frequency response.
NPRR1018: clarifies several provisions regarding the termination and suspension of a qualified scheduling entity (QSE) and the ability of a load-serving entity or resource entity to act as a “virtual” or “emergency” QSE.
NPRR1019: addresses switchable generation resources (SWGRs) moving from a non-ERCOT control area to the ERCOT control area by creating a proxy energy offer curve with a price floor of $4,500/MWh for each RUC-committed SWGR and including a lost revenue cost component to the switchable generation cost guarantee.
NPRR1021: shortens the default uplift invoice’s issuance timeline from 180 days to 90 days and allows ERCOT to use the best available settlement data when calculating each counterparty’s share of the default uplift.
NPRR1022: modifies how QSEs and congestion revenue right account holders (CRRAHs) submit banking information changes to ERCOT by removing the ability to submit the information with a Notice of Change of Information via email or fax. The NPRR creates a new form, Notice of Change of Banking Information, that a QSE/CRRAH must execute and submit through the market information system’s certified area.
NOGRR204: together with NPRR989, codifies concepts described in the Battery Energy Storage Task Force key topics and concepts No. 4 (KTC-4) and establishes ESR technical requirements.
OBDRR017: aligns language within the operating reserve demand curve’s methodology for calculating the real-time reserve price adder with protocol revisions under NPRR987 and changes the real-time operating reserve calculation to consider an ESR’s state of charge when calculating the resource’s contribution to the online operating reserves.
SCR807: increases the CRRAHs’ total CRR transaction limit by 33% to 400,000 market transactions during CRR auctions.
SCR809: updates the validation rules imposed on ERCOT’s external telemetry and used in the resource limit calculator.
Participants at a joint meeting of the New England Power Pool Markets and Reliability committees were encouraged to look west, think big, consider NYISO’s example in planning for a grid in transition and keep the bigger picture in mind to avoid getting bogged down in irrelevant details.
Advanced Energy Economy (AEE) submitted a paper recommending that ISO-NE and NEPOOL consider borrowing from NYISO’s effort, which identified as its central proposition: “how the wholesale markets in New York can continue to provide the pricing and investment signals necessary to reflect system needs and to incent resources capable of resolving those needs.”
New England’s study “should similarly address the transition to the future grid, not just the end state,” AEE said.
NYISO in December 2019 issued its Grid in Transition report to map the planning for a grid increasingly dominated by a slew of clean energy resources, a transition driven primarily by state policy. The ISO this year is devoting at least one day a month for stakeholders to discuss reliability and market issues related to the challenge of integrating renewable resources. (See NYISO Focus Turns to Grid ‘Transition’.)
Change in New York supply, 1990-2040 | NYISO
“Importantly, discussion of these potential market reforms is not being held up while The Brattle Group completes a longer-term quantitative analysis as part of a related but separate process that kicked off earlier this year,” AEE said.
Brattle representatives in May presented NYISO stakeholders with an interim report on New York’s evolution to a zero-emission power system, modeling operations and investment in scenarios of increasing electrification for the years 2024, 2030 and 2040. They are considering feedback before presenting the final study results in June. (See NYISO Examines ‘Evolution’ to Zero Emissions.)
Focus on Task
New England States Committee on Electricity Senior Counsel Ben D’Antonio presented NESCOE staff’s preliminary thinking on the transition study that NEPOOL expressed interest in conducting. The presentation was to focus stakeholders on prior and ongoing studies to help define what study areas remain.
In response to a stakeholder question about possible gaps in current market rules, NESCOE Director of Analysis Jeff Bentz clarified the states’ collective aim.
“We didn’t want to be in a place where we are with ESI [Energy Security Improvements], where we have this market construct problem and we’re all forced to do it in a hurry,” Bentz said. “The idea here was, can we look at where we think we’re going to be 10 years from now and then try to determine whether the market construct we have today will work in that future state, and if not, what market construct will we need?” (See ISO-NE Sending 2 Energy Security Plans to FERC.)
[Note: Although NEPOOL rules prohibit quoting speakers at meetings, those quoted in this article approved their remarks afterward to clarify their presentations.]
Bentz added that “by knowing where we need to be in the future, it could inform the best transition path.”
Pete Fuller of Autumn Lane Energy agreed that NEPOOL and the RTO need to focus on a “broad-brush” effort.
NESCOE points out the gap in current studies between business-as-usual versus mitigation scenarios through 2050 for New England. | NESCAUM
The goal isn’t to hit a precise target, such as “intercepting an asteroid in a particular time and place,” but to establish a market framework to move the system in the right direction, said Fuller, who presented recommendations with the endorsement of NEPOOL members NRG Energy and Sunrun.
“I’m concerned that we could get ourselves caught in some highly detailed analysis … and missing the big picture here,” Fuller said.
“I think we can make a number of assumptions about what is the transmission topology and that it will resolve itself over time as offshore wind gets developed and integrated, as new resources enter, as electrification happens and flows change, as energy storage comes and so forth,” Fuller said. “That all can largely be left to be worked out by parallel, different processes, not this one.”
Giving policymakers comprehensive economic comparisons of various levels of decarbonization? Determining whether the region needs a higher-voltage bulk network, potentially including offshore cables, to integrate the future resource mix? Evaluating the technical potential and viability of hydrogen electrolysis and storage, CCS, modular nuclear and any number of other new technologies?
“That’s not our task here,” Fuller said.
The task, according to Fuller, is to focus on two key questions: “Will our current market designs support a reliable low-carbon resource mix? And if not, what should we do about it?”
Future is Now
Other stakeholders said that New England has already effectively started the future grid planning process, as Brattle last September issued a study on what the region must do to achieve at least an 80% reduction in greenhouse gas emissions by 2050.
Xiaochuan Luo, ISO-NE technical manager for business architecture and technology, presented a slidedeck covering the RTO’s current capabilities for modeling and tools addressing various time horizons.
“If the Future Grid study would benefit from these capabilities, the ISO offers them to assist in that effort,” Luo said. “If there is a gap between our modeling processes and tools and those deemed necessary for the Future Grid studies, the ISO will work with stakeholders on the best way to address such gaps.”
The RTO is accepting stakeholder proposals for what kinds of analysis should be performed in the future grid study and associated analysis assumptions this year, with agenda topics and timing to be submitted to the MC secretary by June 12 for the next meeting.
More than 130 New Yorkers gathered in an online forum Thursday for a “people’s hearing” organized by nearly a dozen environmental groups to protest the possibility of National Grid increasing the state’s supply of natural gas by adding vaporizing capacity, trucking in compressed natural gas and other measures.
Michaela Ciovacco, NYCP
“This people’s hearing marks an unprecedented coming together of campaigns and minds to tackle getting off fracked gas and moving to renewables, first by focusing on the upcoming June 11 decision by the [New York] Public Service Commission on National Grid’s plan to meet downstate energy demand,” said Michaela Ciovacco of New Yorkers for Clean Power (NYCP).
The group helped organize the event as a member of Renewable Heat Now, along with Sane Energy Project, Alliance for a Green Economy, Mothers Out Front, Sierra Club, Food & Water Action, NY Renews, Stop the Williams Pipeline Coalition, Heatsmart Tompkins and No North Brooklyn Pipeline.
New Jersey and New York regulators two weeks earlier denied permits for the Williams pipeline, also known as the Northeast Supply Enhancement (NESE) project, which would have carried natural gas from Pennsylvania across New York Harbor into the Rockaways, Queens.
“Neither the utility nor the Public Service Commission have scheduled a public hearing, so that’s why we came together,” Ciovacco said.
The organizers claimed that any increase in fossil fuel usage would violate the spirit and the letter of the state’s Climate Leadership and Community Protection Act, signed into law last July. It mandates that 70% of the state’s electricity come from renewable resources by 2030 and that generation be 100% carbon-free by 2040. (See Cuomo Sets New York’s Green Goals for 2020.)
More than 130 people gathered online May 28 for a “people’s hearing” on National Grid’s plans to supply natural gas to downstate New York.
Conflicting State Policies
National Grid spokesperson Karen Young told RTO Insider that a May 8 press release detailed how the company has been fulfilling its 2019 agreement with the PSC to propose long-term solutions for downstate gas supply and demand.
The company’s “no-infrastructure” option includes reducing gas demand through incremental energy efficiency measures, demand response and electrification.
The company this past winter and spring held six public meetings attended by more than 800 people, and altogether more than 7,500 public comments have been filed with the PSC.
National Grid non-gas proposal | National Grid
National Grid found itself at odds with Gov. Andrew Cuomo last November when he criticized a company moratorium on new gas hook-ups that the company attributed to supply concerns. Cuomo issued a letter demanding that its gas subsidiaries connect all customers for whom it had denied service under the moratorium or he would seek “to revoke National Grid’s certificate to operate its downstate gas franchise.” (See National Grid Vows to Expand NY Gas Service.)
PSC Chair John B. Rhodes on Oct. 11 had signed an order forcing National Grid subsidiaries Brooklyn Union Gas (KEDNY) and KeySpan Gas East (KEDLI) to connect 1,100 of 3,300 customers that had been denied natural gas service connections (Case 19-G-0678). KEDNY has approximately 1.2 million customers, and KEDLI has 590,000 customers on Long Island.
Jackie Weisberg, Brooklyn resident
Brooklyn resident Jackie Weisberg addressed her comments during the online protest to Cuomo: “I oppose the National Grid fracked gas proposal because these pipelines are like the COVID-19 virus. They are insidiously infecting our communities. Selling us the so-called benefits of fracked gas is not what we need now, or ever. They have no business continuing the work in North Brooklyn [on the Metropolitan Natural Gas Reliability Project], and they are opposed in Connecticut and elsewhere.”
Young said “the Metropolitan Natural Gas Reliability Project is a system integrity project, it’s not one of the long-term capacity solutions — it does not bring additional supply to New York.”
Eyes of the PSC
In its Nov. 26, 2019, agreement with National Grid, the PSC mandated that an independent monitor submit quarterly reports to keep it apprised of the company’s progress in finding ways to provide gas service to all its customers in downstate New York.
The monitor’s third report, filed May 26, said that it attended all the public meetings and afterward began “monitoring the key executive meetings conducted internally at National Grid to address its compliance.”
In assessing the company’s development of long-term solutions, the report said it reviewed implementation of energy efficiency and demand response and “makes no formal findings or recommendations but provides observations regarding National Grid’s progress and positions.”
The monitor highlighted National Grid in April having hired Ernst & Young to review the company’s “development of natural gas demand scenarios and the identification and selection of options to meet demand.”
National Grid’s analysis turns on a design day standard, currently a 24-hour period with an average temperature of 0 degrees Fahrenheit in Central Park. The last design day was in 1934, and many public comments questioned the suitability of that standard today, the monitor said.
“To illustrate the point, National Grid has determined that the 24-hour period with the coldest average temperature in Central Park over the last 30 years was approximately 4 degrees F and took place in 1994,” the report said.
The monitor faulted National Grid for being too conservative on the one hand and too extreme on the other for assuming the increased reliance on compressed natural gas trucking through 2035, despite the practice raising “risk, cost and reliability questions.”
“Based on forecast figures provided by National Grid to the monitor, several more middle-ground approaches … indicate possible opportunities to move forward that are less stark than simply choosing between NESE or the no-infrastructure options,” the monitor said.
It also said that the company is not fully accounting for the reduced demand impact from the current pandemic, despite its own reporting that the reduced demand added a year to the predicted time when demand will exceed supply, to the winter of 2022/23.
The 2020 MISO Transmission Expansion Plan (MTEP 20) is shaping up to become one of the RTO’s most expensive ever.
Being developed virtually with stakeholders because of COVID-19 measures, the plan so far contains 510 proposed projects at a combined $4.06 billion, the priciest since MISO’s 2011 multi-value project portfolio. If approved by the RTO’s Board of Directors in December, MTEP 20 will best last year’s plan, which rang in with 480 projects at $4 billion. (See MISO Board OKs $4 Billion MTEP 19.)
Broken down, the transmission investment contains:
149 reliability-related projects at nearly $1.1 billion;
133 age- and condition-related upgrades at $1.05 billion;
77 baseline reliability projects at $783 million;
88 generator interconnection projects at $512 million;
55 projects necessary to accommodate load growth at $606 million; and
eight projects to be built for other local needs at $26 million.
Of those, MISO South accounts for 47 project proposals valued at $750 million.
Stakeholders at subregional planning meetings last week wondered whether some load-growth projects may be scaled back or withdrawn as the catastrophic economic impact of the COVID-19 pandemic continues to play out.
MISO Senior Manager of Expansion Planning Edin Habibovic said transmission owners might revise some projects based on COVID-19 effects, adding that the RTO will have more information on individual load-growth projects during a final round of subregional planning meetings in August. He said discussions over why some load-growth projects drop out likely won’t be disclosed publicly.
Ameren Illinois and Entergy Texas have so far submitted some of the costliest MTEP 20 projects, with the former planning four projects between $74 million and $91 million for reliability and age and condition needs, while the latter is tendering three projects between $65 million and $77 million in response to load growth in its territory.
MTEP 20 project investment by region | MISO
MISO said it will test one of Ameren’s reliability project submissions — the 345-kV New Holland NW-Neoga South line rebuild in central Illinois — for economic benefits that might allow it to be cost-shared as a market efficiency project.
Altogether, Ameren proposed 152 new projects at an estimated $1.4 billion in its Illinois and Missouri service areas.
Some stakeholders asked why Ameren was suddenly making such big investments in transmission.
MISO expansion planning team member Scott Goodwin said Ameren is this year using a three- to five-year outlook on transmission projects instead of an annual planning horizon. Senior Manager of Expansion Planning Thompson Adu also said MISO has been coordinating with Ameren on issues that require transmission upgrades.
“We make sure we agree with the projects and justifications that they have given to us,” Adu said.
Stakeholders also asked if MISO performs any research to confirm the necessity of TOs’ age and condition projects.
Adu said TOs must justify those projects to MISO, but not all of them provide photos or engineering analyses.
No Midwest-South Tx Solution this Year
MTEP 20 will not contain a long-awaited transmission upgrade to secure more transfer capability on the Midwest-South subregional transmission constraint, stakeholders also learned.
David Severson, a MISO economic studies engineer, said that while there were a “couple promising project candidates,” the RTO will not recommend any Midwest-South transmission projects to the board this year.
Last year, MISO received and screened 35 project ideas to reduce dependence on its Midwest-South transfer constraint. Nine projects passed an initial screening, with three of those showing the required 1:1 or better cost-benefit ratio. (See MISO Floats New Option for Midwest-South Constraint.)
Missouri Public Service Commission economist Adam McKinnie asked why MISO planners don’t submit one of the three project finalists for consideration in the 2020 cycle of the RTO’s and coordinated system plan with SPP, developed to identify potential interregional economic transmission projects.
“I’m waiting for a good reason to hold off on a good solution for another year,” McKinnie said. The transfer limit study has been ongoing since the MTEP 19 cycle.
“We can use the project candidates for a really good starting point in the future,” Severson said. “Further study efforts under an expanded scope would be better served under MTEP 21 future assumptions and models.” MISO is currently redoing its 20-year futures assumptions to factor increased renewable generation and zero-carbon goals in time for the 2021 cycle of transmission planning.
Some stakeholders have criticized the study, saying that MISO focused too narrowly on only increasing the existing contract path capacity and not on a potentially more beneficial increase in physical transfer capability located somewhere else between the Midwest and South regions.
North Study Extends into 2021
Meanwhile, results are pending on MISO’s other special MTEP 20 study on the North Region economic transfer. The study evaluates transfer limitations caused by non-thermal constraints between the renewable-rich northwestern portions of the footprint and load centers in the Upper Midwest. MISO said it’s studying wind generation transfers from the Dakotas, Minnesota and Iowa to Wisconsin and Illinois.
That study will also extend into MTEP 21. MISO economic planner Ryan Hay said that while the study is largely academic, possible transmission projects could be identified and submitted in MTEP 21.
MISO has said the study is the first of its kind and will serve to develop a template for identifying and incorporating non-thermal transmission limits into its production cost analyses. Currently, MISO’s typical economic studies don’t consider non-thermal operational limits. (See MWEX Study Could Elicit New Tx Planning for MISO.)
