Advocates for green energy last week clashed with activists seeking to preserve sensitive habitat at a hearing on a proposed solar farm in Central Washington.
The two green constituencies said they respected the views of the other side in the virtual hearing held by the Washington Energy Facility Site Evaluation Council (EFSEC) on Wednesday, but stuck by their own interests. EFSEC consists of representatives from several state agencies, who will eventually make a recommendation to Gov. Jay Inslee on whether he should approve the project.
One side supported Portland, Ore.-based Avangrid Renewables’ proposal to build the solar facility, which would produce 200 MW of electricity on almost seven square miles of highlands dubbed Badger Mountain, located about three miles east of the small Columbia River town of East Wenatchee.
Those speakers cited the need for a non-emitting renewable power source to combat global warming and for the green construction jobs that would help the local economy. Five landowners own the site and would lease the land to Avangrid.
A subsidiary of Spain-based energy giant Iberdrola, Avangrid Renewables operates roughly 70 wind and solar projects totaling about 7,000 MW across the U.S.
Opponents of the proposal cited risks to the sage grouse, which lives in the sagebrush-filled shrub-steppe habitat that borders the Avangrid solar site and is listed as endangered by Washington. Roughly 700 sage grouse live in the state, mostly in Douglas County, of which East Wenatchee is the county seat. The habitat areas surround the Avangrid site.
Climate change is also affecting these small birds, which weigh from two to nine pounds. A major part of Washington, including Douglas County, suffered a major drought this year, harming the sagebrush that the grouse need. Also, wildfires from the drying Cascade Range forests to the west have crept into Douglas County in the past two years, eliminating more sagebrush.
Sage grouse habitat once covered most of Central Washington. Now only 8% of that habitat remains in three scattered segments of which the area east of East Wenatchee is by far the biggest. Mike Livingston of EFSEC said that “Douglas County is pretty unique in its habitat for sage grouse.”
Avangrid official Scott Kringen said Wednesday that the actual site contains less than 3% shrub-steppe. “We’re trying to stay out of shrub-steppe habitat,” he said. Eighty-seven percent of the almost seven square miles is non-irrigated agricultural land.
However, opponents based their opposition on the threats to the sage grouse.
“The Sierra Club has a long history of supporting renewable energy in Washington state, but clean energy must be developed so it does not destroy the habitat of our endangered species,” Margie Van Cleve of the Washington Sierra Club said.
“There’s a chance that this project alone can remove this species from the state of Washington,” Keith Watson of Conservation Northwest said.
Mickey Fleming, lands program manager for the Chelan-Douglas Land Trust, said, “We hope you conclude this is not a proper place for solar development.”
Meanwhile, eight Central and Eastern Washington union representatives and construction workers spoke in favor of the Badger Mountain project, which they say could provide 400 jobs during its construction. They also cited needs for alternative power sources to combat global warming.
“We still need additional power generation to meet the needs of the state,” said Robert Abbott, a director at the Laborers’ International Union of North America.
Eric Thrift, a construction worker from East Wenatchee, said the project will help achieve the state’s goal of becoming almost carbon neutral by 2050. A 2020 Washington law sets carbon-reduction targets of 45% below 1990 levels by 2030, 70% by 2040 and 95% by 2050.
Ameren Illinois must still issue refunds over transmission rate errors uncovered by a central Illinois co-op, FERC ruled last week.
The commission defended its prior ruling that Ameren Illinois must correct its annual transmission revenue requirement (ER20-1237).
FERC in March said Ameren overcharged transmission customers by millions for construction-related materials and supplies by misplacing them in its books and likely misclassified about $20,000 worth of transmission operations and maintenance costs under an account meant for regulatory costs. (See FERC Finds Few Errors in Co-op’s Challenge of Ameren Illinois Rates.)
The commission was reacting to a challenge from Southwestern Electric Cooperative over Ameren’s rates. Southwestern has lodged formal rate disputes against Ameren Illinois every year since 2016, often unsuccessfully. (See Challenge to Ameren Illinois Rate Rejected Again.)
Ameren sought rehearing of FERC’s decision, arguing that it hadn’t made an error and the commission violated its rule against retroactive ratemaking when it ordered the company to correct inputs to its formula rate.
FERC disagreed that Ameren’s “incorrect reporting was minor or ministerial.” It said the misclassified materials and supplies costs led to a more than $11.5 million in rate overcharges over multiple years and said it had a duty to order Ameren to recalculate and issue refunds.
The commission said Ameren’s formula rate didn’t permit the recovery of construction-related materials and supplies but Ameren “nonetheless recovered” them “by incorrectly reporting them.”
PJM has proposed changes to a stakeholder-endorsed proposed on solar-battery hybrid resources after consulting with FERC over a future filing of the issue.
Andrew Levitt, of PJM’s market design and economics department, reviewed the RTO’s solar-battery hybrid resources issue in a second first read at last week’s Markets and Reliability Committee meeting. The proposal, which would update PJM’s governing documents and manuals to clarify several aspects of market participation by solar-battery hybrid resources, was originally endorsed at the August Market Implementation Committee meeting with 99% stakeholder support. (See “Solar-Battery Hybrid Proposal Endorsed,” PJM MIC Briefs: Aug. 11, 2021.)
Levitt said PJM had a prefiling meeting with FERC staff back in September, and they made suggestions to reconfigure the language to increase its chances for approval. Staff suggested that the term “hybrid resource” should be structured as a largely independent resource-neutral category and not specifically about solar-battery resources.
PJM reconfigured the language as staff suggested, Levitt said, styling it as a friendly amendment. He said the new proposal is “substantively and functionally almost identical” to the language endorsed at the MIC, but there was “a lot” of new tariff language.
Levitt said FERC staff recognized that, for now, certain provisions specific to solar-storage hybrids will be pursued by the RTO before other hybrid types “due to overwhelming presence of solar hybrids in PJM queue,” so it made sense to focus the language changes on solar-battery hybrids.
One stakeholder requested that PJM add an energy market must-offer clarification for wind and solar to the proposal through a “quick fix” process.
Ken Foladare of Tangibl Group said he objected to the idea that the language changes were a quick fix or something PJM could do unilaterally. He said the changes should go through the proper stakeholder process.
“I’m not quite sure the people I work with are going to be on board with this so easily,” Foladare said. “It needs to be fully explained to the PJM stakeholders.”
The committee will be asked to endorse the proposal at the December MRC meeting.
Undefined Regulation Mileage Ratio Calculation
PJM presented its plan to stakeholders to get a vote on a short-term solution to the undefined regulation mileage ratio calculation while endorsing a further look at other issues in the regulation market.“
Adam Keech, PJM’s vice president of market design and economics, discussed the next steps of the undefined regulation mileage ratio proposal after a failed vote at the October MRC. (See “Regulation Mileage Ratio Fails,” PJM MRC/MC Briefs: Oct. 20, 2021.)
Stakeholders rejected two different proposals to change the undefined regulation mileage ratio calculation in Manual 28 and the tariff, sending the issue back to the MIC for more discussions. (See “RTO to Propose Review of Regulation Market,” PJM MIC Briefs: Nov. 3, 2021.)
Danielle Croop, senior lead market design specialist at PJM, presented a first read of a new problem statement and issue charge to create a new senior task force to re-evaluate the current regulation market design. Keech said the language in both documents was similar to language endorsed creating the former Regulation Market Issues Senior Task Force that last met in 2017.
Keech said the proposal was in response to stakeholder feedback at the October MRC meeting with the intention to initiate short-term fixes. Members said there were larger issues with the regulation market that needed review, and PJM was supportive of the review.
The key work activities include regulation market education, evaluating the benefits factor curve and proscribed RegA/RegD commitment percentages, and proposing any modifications to the regulation market to address issues raised in the evaluation. Keech said the review would utilize a new senior task force reporting directly to the MRC.
If the MRC endorses the task force at its December meeting, Keech said, it will take another vote on the short-term proposals from PJM and the Monitor that failed last month.
“Our hope is that by committing and moving forward with this broader review of the regulation market, that the stakeholders will reconsider the proposals that failed to pass,” Keech said.
Regulation mileage is the measurement of the amount of movement requested by the regulation control signal that a resource is following; it is calculated for the duration of the operating hour for each regulation control signal. PJM’s performance-based regulation market splits the dispatch signal in two: RegA for slower-moving, longer-running units; and RegD for faster-responding units that operate for shorter periods, including batteries. If a signal is “pegged” high or low for an entire operating hour, the corresponding mileage would be zero for that hour.
PJM has seen an increased frequency of RegA signal pegging and times the RegA signal is pegged for extended periods, highlighting a potential problem in the regulation mileage ratio calculation. The RegA mileage can be set at zero for a given hour and create a divide-by-zero error in the calculation of the mileage ratio.
PJM proposed setting the RegA mileage floor at 0.1 instead of zero, which would provide a solution for the division ratio and still maintain market design objectives while having no impact on the regulation signal design, operations or regulation market clearing.
The Monitor proposed a cap of 5.5 on the realized mileage ratio in all hours instead of 0.1, indicating the cap would eliminate the current undefined mileage ratio result that PJM is attempting to address.
Monitor Joe Bowring said he was glad PJM was taking up a broader review of the regulation market and that the IMM was prepared to discuss a compromised RegA mileage between 0.1 and 5.5. Bowring said he wanted to get a sense from stakeholders whether they were calling for the IMM to work with PJM to come up with a compromised ratio.
Susan Bruce, counsel to the PJM Industrial Customer Coalition, said the ICC would be interested in PJM and the Monitor trying to find a “midpoint” in the conversation on the ratio. Bruce said the ICC understands the “math problem” PJM has identified, but the short-term solution could be as simple as “splitting the baby” and settling on a number in the middle.
“I would still hope there could be a place of common ground found during the intervening time,” Bruce said.
Michael Zhang, senior lead engineer in PJM’s markets coordination department, reviewed a PJM proposal to improve the deployment of synchronized reserves during a spin event.
Developed from discussions in the Synchronized Reserve Deployment Task Force (SRDTF), the Operating Committee endorsed the proposal earlier this month. (See “Synchronous Reserve Endorsed,” PJM Operating Committee Briefs: Nov. 4, 2021.)
Synchronized reserve events are emergency procedures triggered by PJM to maintain grid reliability in accordance with NERC’s Resource and Demand Balancing (BAL) standards. The RTO invokes those procedures under conditions such as the simultaneous loss of multiple generating units or a sudden influx of load.
The SRDTF examined ways to secure controlled deployment of synchronized reserves throughout emergency events by using tools such as real-time security-constrained economic dispatch (RT SCED) to maintain consistent pricing and dispatch signals. The goal was to ensure BAL compliance during the recovery process and maintain a reliable transition in and out of emergency events and to define clear rules and expectations that address how PJM operators approve RT SCED cases around a synchronized reserve event.
PJM’s proposal would create an intelligent reserve deployment (IRD), a SCED case simulating the loss of the largest generation contingency on the system and for which approval of the case will trigger a spin event. The proposal calls for taking the megawatts of the largest generation contingency and adding them to the RTO forecast to simulate the unit loss. The RTO would then be allowed to flip condensers and other inflexible synchronized resources cleared for reserves to energy megawatts and procure additional reserves to meet the next largest contingency.
Zhang said some of the significant changes over the status quo in the proposal include updating the economic basepoints to replace all-call instructions and having active constraints controlled by IRD so that deployed resources don’t have negative impacts on the constraints.
PJM is looking to conduct a phased approach of IRD, with the initial phase of six to 12 months beginning in early 2022, Zhang said, possibly by March. Zhang said the phased approach will allow operators to make any fine-tuning adjustments as they gain more experience with the tool.
PJM will reconvene the SRDTF toward the conclusion of the initial phase to review performance metrics, Zhang said, soliciting stakeholder feedback, adjusting and finalizing the deployment approach and adapting to market changes.
“IRD is ready to go,” Zhang said. “It does not require any additional development. It can be turned on when ready, and it will integrate into all of our existing applications.”
Catherine Tyler of Monitoring Analytics said the IMM still has concerns with the proposal, including that it relies on resources to meet the system needs during a spin event that did not actually clear reserves. Tyler said that if reserves are going to be paid more, it’s important that they “have an obligation” and related penalties for nonresponse because they’re being counted on in a spin event.
Bruce said PJM may need a better way to address the manual deployment of synchronous reserves, but she argued that “we’re not there” in terms of IRD being the correct solution. Bruce said there are many small issues with the proposal that taken together could cause bigger problems.
“There’s more work that should be taken here in getting the details right,” Bruce said.
The committee will be asked to endorse the proposal at its meeting next month.
Carbon Pricing Senior Task Force Sunset Endorsed
Stakeholders unanimously endorsed the sunsetting of the Carbon Pricing Senior Task Force (CPSTF). A majority of stakeholders have indicated they are not ready to move forward with developing rules on leakage mitigation in carbon pricing. (See “Carbon Pricing Senior Task Force Sunset,” PJM MRC/MC Briefs: Oct. 20, 2021.)
Eric Hsia, senior manager in PJM’s applied innovation department, reviewed the recommendation to sunset the CPSTF, which was established in July 2019. The main objective of task force’s issue charge was to explore the impacts of emissions and price leakage between regions with and without carbon pricing policies, such as the Regional Greenhouse Gas Initiative states, and to develop business rules to manage leakage where appropriate.
The first stage of the task force included education on concepts like a carbon tax versus cap-and-trade programs and an introduction on leakage between states. Analysis in the first stage included studies on a range of carbon prices and potential leakage mitigation approaches.
Hsia said there are current efforts in the interconnection process, transmission policy workshops and phase 2 of the capacity market overhaul to include discussions related to decarbonization and the procurement of clean resource attributes.
Jason Barker of Exelon said it was “with reluctance” that the company was accepting the sunset motion of the task force. Barker called carbon emissions from the electricity sector an “imminent problem” that needs to be solved, and PJM stakeholders should continue to discuss the possibility of regionwide carbon pricing and the impacts on the market.
“We believe there are methods to effectively address leakage mitigation,” Barker said.
HVDCSTF Sunset Endorsed
The committee unanimously endorsed the sunsetting of the High Voltage Direct Current Senior Task Force (HVDCSTF), which was created last year to examine integrating HVDC converters as a new type of capacity resource in PJM. (See “HVDCSTF Sunset,” PJM MRC/MC Briefs: Oct. 20, 2021.)
Carl Johnson of the PJM Public Power Coalition, speaking on behalf of American Municipal Power, moved to sunset the task force. The MRC had endorsed an issue charge by Direct Connect Development in May 2020 to consider establishing HVDC converter stations’ eligibility to participate in the capacity market. (See HVDC Initiative Endorsed by PJM Stakeholders.)
The change would allow Direct Connect’s SOO Green HVDC Link — the 350-mile, 2,100-MW, 525-kV underground transmission line planned to deliver renewable energy from upper MISO to Illinois and the PJM grid — to compete in the market.
“There wasn’t a way with the currently approved or a significantly modified approach to external capacity that we could get to where [SOO Green] wanted to go without completely upending where we are with how we do pseudo-ties,” Johnson said.
Consent Agenda
The committee unanimously endorsed as part of the consent agenda several revisions to:
Attachment F: Control Center and Data Exchange Requirements of Manual 1 addressing exceptional circumstances outside of the COVID-19 pandemic. The attachment was originally developed and implemented at the start of the pandemic to provide guidance for remote operations in case of control center staff illnesses. (See “Manual 1 Changes Endorsed,” PJM Operating Committee Briefs: Oct. 7, 2021.)
the 2022 day-ahead scheduling reserve (DASR) requirement to 4.43%, slightly lower than the 2021 requirement of 4.78%. (See “Day-ahead Schedule Reserve Endorsed,” PJM Operating Committee Briefs: Nov. 4, 2021.)
Members Committee
ARR/FTR Market Task Force Proposal Endorsed
Stakeholders endorsed proposed tariff revisions to address changes related to auction revenue rights (ARRs), financial transmission rights and transparency at the Members Committee meeting.
The joint PJM-stakeholder proposal was endorsed in a sector-weighted vote of 3.73 (74.6%), surpassing the necessary 3.33 threshold. It was endorsed at last month’s MRC meeting after failing an initial vote. (See Stakeholders Endorse PJM ARR/FTR Market Changes.)
Brian Chmielewski, manager of PJM’s market simulation department, said the changes were the result of a two-year stakeholder process initiated after the GreenHat Energy default in 2018, including a six-month review by the London Economics International (LEI), a consultant enlisted by the RTO to conduct a “holistic review” of the ARR/FTR market that led to a report.
The proposal aims to recognize recommendations made in the report and address concerns raised by the Monitor and stakeholders regarding the ARR/FTR market, along with seeking to maintain the consultant’s conclusion that the existing FTR product is “reasonable and generally achieving the intended purposes” of serving as a financial equivalent to firm transmission service and to ensure “open access to firm transmission service by providing a congestion-hedging function.”
PJM’s proposal was broken into three separate areas as recommended in the LEI report, with an ARR track dealing with “equity” issues, an FTR track for “efficiency” issues and a transparency track for a “simplicity” model.
Proposed enhancements to PJM’s current ARR/FTR market design. | London Economics
Gregory Carmean, executive director of the Organization of PJM States Inc. (OPSI), highlighted a recent letter sent by OPSI to PJM asking for staff to weigh in on whether or not they felt the proposal “fully addressed” the equity, efficiency, simplicity and transparency concerns highlighted in the LEI report.
Carmean said a letter OPSI received from PJM indicated that the joint proposal “was a consensus among stakeholders and that was why the RTO was supporting it. He asked if PJM understands OPSI’s concerns so that staff can report to the Board of Managers “that we won’t have to revisit this issue again in three years.”
Chmielewski said the LEI report and the areas of recommendation were “used as guidelines” for the development of the proposal and that every recommended area in the report was “fully discussed” by stakeholders throughout the process.
“I’m confident that the package that was endorsed last month is comprehensive that increases value for everyone in the ARR/FTR market,” Chmielewski said.
Ed Tatum, vice president of transmission at American Municipal Power, voiced his support, saying that when members can come together to support a proposal, the result is better than not coming together on an issue at all.
“Not everybody’s crystal ball is clear,” Tatum said. “And not everybody’s market design takes care of what needs to be taken care of.”
Bruce said there have been divergent views as to the right approach to ARR/FTR, but the ICC is glad PJM undertook the “comprehensive review” in the wake of the GreenHat default.
“From a customer perspective, we want to make sure that our load-serving entities have the tools they need in order to help support retail contracting and service to retail customers,” Bruce said.
Consent Agenda
As part of the consent agenda, stakeholders unanimously endorsed:
the 2021 reserve requirement study results for the installed reserve margin and forecast pool requirement. The results were endorsed at last month’s Planning Committee meeting. (See “Reserve Requirement Study Results Endorsed,” PJM PC/TEAC Briefs: Oct. 5, 2021.)
revisions to Manual 15: Cost Development Guidelines, the OA and the tariff to address incremental and no-load energy offers. PJM said the Cost Development Subcommittee proposed revising the no-load cost and incremental energy offer definitions to clearly define what costs can be included, including operating costs, tax credits and emissions allowances. (See “Manual 15 Revisions Endorsed,” PJM MIC Briefs: Sept. 9, 2021.)
tariff revisions addressing behind-the-meter generation business rules on status changes. The updates were developed in special sessions of the Market Implementation Committee. (See “Manual 14G Updates Endorsed,” PJM PC/TEAC Briefs: Aug. 31, 2021.)
Activity at FERC’s Office of Enforcement returned to pre-pandemic levels last fiscal year, as the unit opened 12 new investigations and settled nine pending ones for about $5.9 million in civil penalties and $2 million in disgorgement, according to an annual report released by the commission Thursday.
The number of new investigations was identical to those opened in fiscal year 2019 and double those in fiscal year 2020, during which it relaxed some reporting and auditing requirements. (See Report: FERC Enforcement Actions down Sharply in FY20.) Fiscal year 2021 began Oct. 1, 2020.
The number of settlements increased from two in 2019 and three in 2020. And though the amount the office collected from settlements was down about 45% from 2019, it was far more than the $550,000 in 2020. The bulk of the penalties and disgorgements in 2019 came from a settlement with Dominion Energy Virginia, which paid $14 million to settle allegations that it had manipulated PJM’s energy market.
“I’m pleased to see that after a lull over the last couple years, the commission is more aggressively pursuing market manipulators,” FERC Chair Richard Glick said during the commission’s open meeting Thursday. “The message to those seeking to manipulate electric and gas markets or shirk their duties as certificate holders or licensees should be clear: The cop is back on the street, and we will aggressively pursue wrongdoing.”
The largest settlement of the year was reached in federal court (IN12-12). The commission resolved its long pending action against Competitive Energy Services and principal Richard Silkman in the U.S. District Court for Maine, with the company and Silkman agreeing in November 2020 to disgorge a total of $1.475 million to ISO-NE and the U.S. Treasury over seven years. The commission had sought a $9 million assessment in August 2013.
FERC alleged that the company fraudulently inflated client Rumford Paper’s energy load baselines in ISO-NE’s day-ahead load response program, and then offered load reductions against that inflated baseline. The alleged scheme began in 2007.
Of those settlements reached directly with FERC, the largest was a combined $2.1 in penalties and disgorgement from Algonquin Power & Utilities’ Windsor Locks gas plant in Connecticut for violating its must-offer obligations in ISO-NE markets in 2012/13 (IN21-2). (See FERC Fines Algonquin Plant $1M for Bungled Offers.)
The report also noted that Enforcement’s Division of Analytics and Surveillance conducted 10 inquires into natural gas market participants related to the February winter storm, closing seven of them and referring two to the Division of Investigations. It also conducted four inquiries into SPP and MISO market participants; it closed three of those and is still examining the last one.
FERC and NERC on Tuesday released their final report on their joint inquiry into the grid’s performance during the storm, but its scope was limited to infrastructure reliability and did not include any information on potential market manipulation or issues with market design. (See related story, FERC, NERC Release Final Texas Storm Report.)
NYISO held its first in-person stakeholder meeting Wednesday after a hiatus of 615 days, CEO Rich Dewey told the ISO’s Management Committee.
The ISO will continue to assess week-to-week and consult working group committee chairs to determine whether COVID-19 pandemic conditions warrant in-person or virtual meetings, Dewey said.
“My preference by default is we would try to do them in person, but we … definitely want to take feedback from stakeholders if people are comfortable continuing to meet in person or if people have very specific concerns given the current state of the pandemic and local infection rates, which are on the rise again, unfortunately,” Dewey said.
Executive Vice President Emilie Nelson presented the ISO’s 2021 Strategic Plan, which outlines evolving state and federal policy drivers affecting the grid operator.
NYISO’s Board of Directors met with the MC in June to review the ISO’s strategic priorities, substantially informed by input from stakeholders, Nelson said.
“There is a rapid change underway on the electric grid, [partly] due to the electrification of other sectors,” Nelson said.
The change is framed in New York by the state’s Climate Leadership and Community Protection Act and at a national level through efforts such as the substantial infrastructure spending bill and a renewed focus on clean energy legislation, she said. (See Biden Signs $1.2 Trillion Infrastructure Bill.)
“Environmental justice and greater public participation are also a prominent part of policy today with respect to reliability and market considerations for a grid in transition,” Nelson said. “The magnitude of the change requires us to acknowledge that our collective understanding will be shaped through iterative analysis and work across planning, operations and markets.”
OKs Comprehensive Mitigation Review
The Management Committee approved tariff revisions related to the ISO’s Comprehensive Mitigation Review (82.03% in favor) and recommended that the board approve the necessary filing under Section 205 of the Federal Power Act. (See “Mitigation Review Moves Forward,” NYISO Business Issues Committee Briefs: Nov. 9, 2021.)
The MC also recommended that the ISO address capacity accreditation related to buyer-side mitigation (BSM) in the three different phases mentioned throughout the proceeding.
NYC transmission security margins are tight following peaker rule implementation, at 394 MW in 2025 and 115 MW in 2030. | NYISO
Phase 1 includes tariff changes for the proposed market design and will conclude with FERC acceptance; Phase 2 will discuss the procedures and details of capacity accreditation throughout 2022; and Phase 3 will focus on implementation of the capacity accreditation review.
NYISO intends to implement the updated capacity accreditation rules for the capability year that begins May 2024, said Michael DeSocio, director of market design.
In addition, assessment of financial risk of changes in future revenues is incorporated in the next demand curve reset process beginning in 2023.
The ISO is pursuing BSM reforms in time for the class year 2021 BSM evaluations. The class year study performs a detailed examination of the collective reliability impact of a group of projects, as well as a deliverability evaluation for requested capacity resource interconnection service and identifies and provides binding cost estimates for required upgrades.
2021-2030 Comprehensive Reliability Plan
The Management Committee unanimously recommended the board approve the 2021-2030 Comprehensive Reliability Plan (CRP) as presented by NYISO staff.
The ISO prepares a CRP in alternating years with the reliability needs assessment (RNA). Key updates to last year’s RNA include one to the load forecast — specifically a decrease in the Zone J peak load forecast by as much as 392 MW by 2030, said Kevin DePugh, senior manager of reliability planning.
Con Edison provided local transmission plan updates, including new 345/138 kV PAR-controlled 138 kV feeders for Rainey-Corona, Gowanus-Greenwood and Goethals–Fox Hills. A short-term reliability process solution for addressing a need arising in 2023 included changes to series reactor statuses from summer 2023 through 2030, DePugh said.
“In Zone J we actually had reliability violations until we did the updates, but that’s where we’re close to the margin right now,” DePugh said.
One stakeholder said the CRP report would look much different if it considered the more than 2,500 MW of solar, wind and hydro planned to be brought into New York City.
The state in September selected two transmission line projects to help decarbonize power in New York City, the 1,300 MW Clean Path New York project and the 1,250 MW Champlain Hudson Power Express project, from among seven projects submitted to the Clean Energy Standard Tier 4 solicitation issued in January. (See Two Transmission Projects Selected to Bring Low-carbon Power to NYC .)
“There are resources that we’re not accounting for here because they haven’t met our inclusion rules yet,” said Zachary Smith, the ISO’s vice president of system and resource planning. “There are some that could have a very positive impact, and that’s in the report itself. A lot of the conversation is around that there are a lot of unknowns, and in our opinion the unknowns tip more towards concern than optimism.”
The ISO added a “Road to 2040” section to the CRP to give long-term consideration to generation and transmission issues, DePugh said.
For generation, the study concluded that a grid with significant amounts of intermittent resources will need significant amounts of emissions-free, dispatchable resources that can run for multiple day periods, and that such resources are not yet available or currently in the NYISO interconnection queue.
In addition, more inter- and intra-zonal transmission capacity will be required to deliver a reliable system with a high level of renewables penetration. Transmission additions would not reduce the amount of dispatchable resource capacity but would decrease the volume of energy needed from them, the report said.
MMU Recommendations
The ISO’s Market Monitoring Unit, Potomac Economics, issued a memo on the CRP and presented its findings that NYISO’s markets “are well-designed and generally provide efficient investment signals,” but have room for improvement.
The first of three main recommendations concerns the locational signals provided in the capacity market.
“There are four zones in the capacity market, but naturally the details of the power system are more granular than that, so from time to time there are reliability issues at a smaller level,” said Pallas LeeVanSchaick of Potomac Economics.
To address possibly misleading market signals resulting from transmission constraints between Staten Island and New York City, for example, or between Zones G and H, the monitor recommends implementing capacity locational marginal pricing (C-LMP) to accurately reflect resource adequacy value at each location.
Other recommendations include implementing marginal capacity accreditation for all resource types; using reasonable assumptions for all resource types in transmission security analyses; and considering discounting capacity payments to resources that do not help address transmission security needs.
Asked by one stakeholder what the ISO thinks of C-LMP, Dewey said, “We’ve got concerns about how heavy a lift that is or how radical a change that is, and it just hasn’t bubbled up to meet the criteria of us thinking it’s a good idea moving forward based on the benefits.”
C-LMP is part of the set of recommendations that NYISO is considering and, while not specifically on the list for next year, it is something that the organization will include in the prioritization process going forward, Dewey said.
FERC on Thursday issued a Notice of Inquiry (NOI) seeking comment on how reactive power capability should be compensated in the face of changing conditions on the nation’s electricity grid (RM22-2).
Unlike the “real” power generated on the grid, which provides energy to end-users (and is measured in watts), “reactive” power (measured in volt-amperes reactive) is needed to support voltages that allow power to flow along transmission lines, a necessary component of system reliability.
“At times, resources must either supply or consume reactive power in order for the transmission system to maintain the voltage levels required to reliably supply real power from generation to load,” FERC staff explained in a presentation during the commission’s open meeting Thursday.
FERC Order 888, issued in 1996, ruled that the reactive supply and voltage control supplied by generators is one of six ancillary services that transmission providers must include in their open access transmission tariffs. At the time, the commission pointed to two methods that providers used for managing voltage control: either installing equipment as part of the transmission system or relying on generation resources.
“The commission concluded that the costs associated with the first approach would be recovered as part of the cost of basic transmission service and, thus, would not be a separate ancillary service. The second, using generation resources, would be considered a separate ancillary service and must be unbundled from basic transmission service,” FERC staff said.
Order 888 was issued at a time when the country’s resource mix overwhelmingly consisted of synchronous generators containing mechanical rotors that rotate in sync with system frequency and generates both real and reactive power in response to the needs of the system.
As FERC staff noted Thursday, in 1999, the commission issued an opinion approving American Electric Power’s method for separately allocating the costs for synchronous generators between providing real power and reactive power capability, including operations and maintenance costs associated with each function.
“Subsequently, the commission recommended that all resources located in regions that base reactive power capability compensation on a resource’s individual costs and that have actual cost data and support documentation should use the AEP methodology when seeking to recover reactive power capability costs pursuant to individual cost-based revenue requirements,” staff noted.
But FERC’s recommendation did not constitute a mandate, and regions have adopted differing approaches to compensating generators for reactive power, with PJM, MISO and certain non-RTO regions generally relying on the AEP methodology, while ISO-NE and NYISO compensate based on a fixed rate multiplied by a resource’s tested reactive capability. CAISO, SPP and other non-organized markets do not compensate at all for reactive capability, FERC staff pointed out.
Existing arrangements for compensating reactive power remained sufficient until “a general shift away” from cost-of-service rates in the electric industry and the increased adoption of nonsynchronous — or inverter-based — renewable and energy storage resources, FERC staff said. Those resources do not use mechanical rotors that rotate in sync with the grid and must have their inverters configured to provide reactive power capability, among other services.
According to FERC staff, “the AEP methodology was designed based on the physical attributes of synchronous resources owned by a public utility that utilized the commission’s Uniform System of Accounts and annually submitted a FERC Form No. 1,” the annual financial and operating report submitted by regulated utilities.
But the commission is now finding that most of the reactive power rate schedule filings it receives are made by owners of non-synchronous resources exempted from the Uniform System of Accounts and Form 1, although they’re still subject to other reporting requirements. FERC staff said that in the last six years, the commission has processed at least 260 reactive power proceedings in PJM and 125 such proceedings in MISO.
“These factors have contributed to customers and the commission facing challenges in evaluating proposed reactive power rate schedules submitted pursuant to Section 205 of the Federal Power Act,” FERC staff said. “Therefore, the commission is seeking comment on various aspects of AEP methodology-based compensation; potential alternative methodologies; and reactive power capability compensation through transmission rates for resources that interconnect at the distribution level.”
“When I first arrived at FERC, I really didn’t have an idea we would be doing so many reactive power cases,” Chairman Richard Glick said during the commission’s open meeting Thursday. He noted that of the 395 total cases, the commission has sent 135 of them to its administrative law judges for settlement and hearing procedures. “I suspect there’s a better, more efficient way, and that is what this Notice of Inquiry is going to look into, among other issues.”
Commissioner James Danly thanked Glick for the NOI, saying “we’ve spent an inordinate amount of time on these cases without having a generic approach to them.”
“This is an important way to find efficiencies in the trenches and relieve staff to do other import work,” Commissioner Allison Clements agreed.
Comments on the NOI are due 60 days after its publication in the Federal Register.
MISO said this week that its members will need to nearly double its current 140 GW of generating capacity within the next 20 years to meet state carbon-reduction targets while also maintaining reliability.
The findings come from a draft of the RTO’s first 20-year regional resource assessment, which staff plans to make an annual undertaking.
Broken down, MISO anticipates the necessary 140 GW will consist of 68% wind, solar, and solar and storage combinations; 11% standalone battery storage and demand-side resources; and 21% natural gas and other thermal resources.
The projections would nearly double the 146 GW of total available capacity MISO said it had on hand for this past summer. The RTO said the additions could have renewables supplying 40% of energy while halving current carbon emissions by 2040 on a footprint-wide basis.
By 2030 alone, the grid operator estimates that it will need 75 GW worth of new resources.
Capacity expansion necessary to meet renewable and decarbonization goals | MISO
“In 10 years, 20 years, the resource mix is going to look very different,” engineer Aditya Jayam Prabhakar said Wednesday during a workshop to discuss the report. “A lot of renewable resources will be added in the future.”
MISO said that its members’ publicly announced generation plans account for less than half of what’s needed by 2040 to meet load and decarbonization goals.
The grid operator said members’ decarbonization goals can be met through 2034 with their current portfolios and publicly known generation additions. After that, MISO said it’s unclear how members will stick to their goals.
Jayam Prabhakar said many members have 80% or more carbon-reduction goals by 2030.
Some stakeholders have challenged the need for MISO to produce long-term regional resource assessments, saying information contained in the reports could get misused in state dockets to contest utilities’ integrated resource plans. RTO leadership appeared at the Organization of MISO States’ annual meeting to garner support for sharing its resource-planning expectations. (See LSEs, Southern Regulators Pan MISO Resource Assessment, OMS Registers its Concern over Supply Insecurity.)
Jayam Prabhakar said MISO’s findings should not be used in investment decisions or formal proceedings.
“That’s not the purpose or intent of this,” he said. “This is not a plan as to how members should achieve their [emissions] goals.”
The assessment is for stakeholders to “collectively have an idea of what’s going on around us” and maintain reliability, Jayam Prabhakar said. He said the assessment reinforces staff’s recent conclusion that its daily peaks will shift to later in the evening and its system-wide annual peaks will start occurring in winter rather than in summer. (See MISO Wraps 1 Renewable Study, Promises More Research.)
Jayam Prabhakar said the 2022 iteration of the assessment will change as members’ resource plans evolve with more aggressive decarbonization goals. “The changes are coming; the announcements are happening at a rapid pace. … There’s so much change,” he said.
Going forward, MISO will survey its members early in the year to collect future generation data, Jayam Prabhakar said. He said MISO plans to publish an assessment report in the fourth quarter of each year.
MISO said it partnered with Applied Energy Group to scour publicly available data on resource decisions. Next year, staff said they will reach out to members directly to inquire about their resource planning.
The U.S. House of Representatives on Friday passed the Build Back Better bill, the $1.75-trillion budget reconciliation package that is key to advancing President Joe Biden’s social and climate agenda.
The 220-213 vote came four days after Biden signed a bipartisan infrastructure bill and followed the release of a report from the Congressional Budget Office estimating that the bill would add $367 billion to the federal deficit from 2022-2031. One Democrat, Rep. Jared Golden of Maine, joined Republicans in opposition.
The CBO figures have been contested by the Democrats and Biden, who insisted in a statement that the bill is fiscally responsible, fully paid for and would reduce the deficit “over the long term.”
A central point of contention between the CBO and White House is how much the cost of the bill will be offset by increased taxes and more rigorous tax enforcement on wealthier Americans and corporations. The CBO estimate of $207 billion fell far short of the $400 billion figure cited by Treasury Secretary Janet Yellen in a statement released Thursday.
The bill contains $555 billion in spending to help the U.S. achieve Biden’s goals of a decarbonized electric power system by 2035 and a net-zero economy by 2050. It is in addition to about $50 billion in climate and energy related spending included in the $1.2 trillion infrastructure bill.
It would be the federal government’s largest investment ever to address climate change, dwarfing the $80 billion included in the 2009 economic stimulus enacted under former President Barack Obama.
According to a White House fact sheet, Build Back Better’s energy spending includes:
$320 billion for 10-year federal tax credits for a range of clean energy technologies, including residential and utility-scale solar, storage, transmission and cleantech manufacturing.
$105 billion in “resilience investments” and incentives to address extreme weather — wildfires, droughts and hurricanes — and legacy pollution in communities. The money would also fund a Civilian Climate Corps, which would employ tens of thousands of people to fight climate change through projects such as reforestation and wetland restoration.
$110 billion in investment and incentives to support the build-out of clean energy supply chains and manufacturing.
$20 billion for federal government procurement of “next-gen technologies,” such as long-duration storage, advanced nuclear reactors and low-carbon construction materials.
With House passage, the bill now heads to the Senate, where Sen. John Barrasso (R-Wyo.), ranking member of the Senate Committee on Energy and Natural Resources, said it will meet “a buzz saw of resistance.” In a statement released Friday, Barrasso framed the bill as an attack on Wyoming’s fossil fuel communities and families.
“Senate Republicans are united in our efforts to plunge a stake through the heart of this Democrat disaster,” he said.
With Republicans opposed to it, the bill’s fate rests with two moderate Democrats, Sen. Joe Manchin (D-W. Va.) and Sen. Krysten Sinema (D-Ariz.), both of whose votes will be needed to reach 50 and a tiebreaker by Vice President Kamala Harris.
In an interview Thursday with The Washington Post, Sinema said the House version of the reconciliation package did not match the Build Back Better framework that had been agreed with the White House in October, so further work would be needed. The House bill includes several provisions that may not survive the Senate, including a paid-leave program, an increase in the $10,000 cap on the deduction for state and local taxes and immigration provisions.
Manchin did not immediately release any statement following passage of the bill on Friday but has previously raised concerns about its potential impact on the already high rates of inflation Americans are experiencing. Last week, Manchin expressed opposition to a $4,500 federal tax credit for union-made electric vehicles, saying it was “not American.”
Robust Investments
Clean energy advocates and other energy industry trade groups quickly issued a flurry of statements on Friday supporting the bill and urging Senate passage.
Gregory Wetstone, CEO of the American Council on Renewable Energy, said the 10-year time frame for clean energy tax credits “finally moves the country beyond years of on-again, off-again renewable tax credits.”
The bill will provide “a stable, predictable and long-term clean energy tax platform that will spur critically important investment in renewable power, energy storage and advanced grid technologies. This is America’s last best chance to take timely action to address the global climate crisis, and it is imperative we rapidly accelerate the renewable energy transition,” Wetstone said.
Similarly, Jim Matheson, CEO of the National Rural Electric Cooperative Association called out provisions that will allow tax-exempt co-ops and municipal utilities to access clean energy incentives through a direct pay mechanism. The bill also includes $10 billion to help co-ops offset the costs of closing coal plants and investing in clean alternatives, he said.
Such measures are, Matheson said, “appropriate recognition of the need to level the playing field for not-for-profit cooperatives, reduce costs and open new doors for innovation.”
The bill’s support for offshore wind and building up clean energy supply chains earned praise from Liz Burdock, CEO of the Business Network for Offshore Wind.
“Fully harnessing the incredible potential offered by offshore wind requires a concentrated national industrial strategy that lays out clear clean energy goals, supports manufacturers and small businesses, builds up a workforce, and rebuilds our ports,” Burdock said. “The Build Back Better Act takes significant steps towards this strategy by providing the long-term support that will spark major investments in new factories manufacturing the blades, foundations and towers that will build the industry.”
The Carbon Capture Coalition also applauded House passage of the bill, with External Affairs Manager Madelyn Morris calling it “a package flush with robust investments in clean energy technologies.”
“If enacted, the package, in combination with the groundbreaking carbon management provisions included in the recently enacted Infrastructure Investment and Jobs Act, could deliver an estimated 13-fold increase in deployment of carbon management technologies and between 210 and 250 million metric tons of annual emissions reductions by 2035,” Morrison said.
The Clean Energy States Alliance, a national association of state agencies, is urging states that will have access to considerable power from offshore wind turbines to consider allowing industry to dedicate some of that electricity to produce renewable, or “green,” hydrogen.
In a report issued in October and promoted recently in a webinar, CESA examined what European governments and companies are already considering and then looks at the feasibility of doing the same in the U.S.
Europe, with an already mature offshore wind industry and a commitment to decarbonize its economy, is looking seriously at replacing natural gas with hydrogen.
And offshore wind power, according to CESA and in other discussions, is being considered as the best source to power large electrolyzers that strip hydrogen out of water. The price of offshore wind is already falling and expected to further decline as larger projects proliferate, the report notes.
Wind projects in Europe, for example, are now transitioning to turbines that generate 12 MW, especially those very large projects being built or planned further offshore. Future projects will be measured in gigawatts. These developments are leading to economies of scale, lowering the price per megawatt-hour.
Another factor that further lowers prices is that turbines operate at a higher capacity factor; that is, they are able to operate at a higher percentage of time on any given day, generating more total power.
Finally, it appears that offshore power projects are expected to proliferate globally.
“The installed capacity of offshore wind is expected to quadruple globally over the next decade, growing from a cumulative installed capacity of around 50 GW in 2021 to 225 GW in 2030,” the report notes. “Approximately 50% of total offshore wind capacity in the world will be in Europe in 2030; Asia will account for roughly 40% of global installed capacity, and the U.S. for the remaining 10%.”
Warren Leon, (left) executive director of CESA and moderator in a CESA-produced hydrogen webinar questioned whether there are downsides to using wind energy to produce hydrogen from water. Val Stori, a CESA project director, said electrolyzers that use power to break apart the hydrogen and oxygen atoms in water are inefficient, meaning most of the energy used to make hydrogen is lost. Lee Wilkinson, a UK-based consultant, said European nations want to replace natural gas with hydrogen for industrial uses. But to be competitive, wind energy used to make hydrogen must be significantly lower priced that it is now, he said. | Clean Energy States Alliance
Lee Wilkinson, a senior consultant at UK-based BVG Associates and a consultant on the CESA study, summed it up this way: “A key reason why Europe is looking at hydrogen is that many people see it as a good replacement for natural gas. As soon as you say … we want to use hydrogen in our energy system, now you’ve got to find the best places to get it. And for many European countries, that’s wind.
“Europe has very good offshore wind resources that they have begun to capitalize on. So there’s a link between hydrogen and offshore wind, where Europe can start to make a connection on how [to] decarbonize more of its energy system.
“There are a few more subtleties to that. The first one is to get the cost of hydrogen down [and] keep the costs low, it’s best to produce hydrogen at scale. One benefit of offshore wind is that it is very good at being deployed at scale. Many wind farm has been deployed today in excess of 1 GW.
“Compared to other sources of renewable electricity like onshore wind and solar, you can get larger economies of scale if you power up your hydrogen production with offshore wind,” he said.
Big oil companies are also moving into offshore wind, he said, further building momentum for hydrogen production, as it somewhat resembles fossil fuels.
But a U.S. leap to hydrogen may not be as easy as it might initially appear. Not only did European offshore wind begin two decades ago, many European nations are already committed to decarbonizing their economies.
“One of the reasons we wrote this report is we wanted to advise U.S. policymakers, particularly states, as to what and how they should be thinking about hydrogen. There are some really big differences between where Europe is and where the U.S. is,” said Val Stori, CESA project director and author of the report.
“And I think one of the big ones is that Europe and the European states have legally binding targets to achieve carbon emission reductions. Significant ones, net-zero ones: 55% by 2030, compared to 1990 at the EU level.
“So … some of the most ambitious decarbonization targets in the world are in place in Europe. In addition, you have an offshore wind energy industry that is mature and is growing and costs are declining rapidly. So 70 GW of offshore wind projects are expected to come online in Europe by 2028 and 300 GW by 2050. That’s huge compared to where we are in the U.S.”
Getting the price of offshore wind down is based on another factor, said Stori: Today’s electrolyzers are inefficient. “That means a large portion of the renewable energy that we’re pouring in to make green hydrogen is lost upwards of 82%” across the full cycle of production and use, she said.
Noting that U.S. offshore wind is in its infancy, the report concluded that powering electrolyzers with wind energy is a use that probably should be considered in the future rather than immediately.
“It may ultimately make sense to use some of the offshore wind output in the United States for green hydrogen production. However, offshore wind in the U.S. is at a much earlier stage of development than offshore wind in Europe. For at least the next decade, the output from U.S. wind farms will be fully needed for electricity production that displaces fossil-fuel generation. That electricity will be especially valuable because the wind farms will be relatively close to major load centers,” the report concludes.
FERC on Thursday modified and upheld its July dismissal of a complaint by Hecate Energy that NYISO and Central Hudson Gas and Electric delayed the company’s 20-MW solar project in Greene County, N.Y., burdening it with $10 million in unnecessary system upgrade costs (EL21-49).
The commission said it continued to find Hecate has not met its burden under Section 206 of the Federal Power Act to show that the respondents violated the tariff or the FPA by failing to use reasonable efforts to process the project’s interconnection request.
“The reasonable efforts standard requires ‘efforts that are timely and consistent with Good Utility Practice and are otherwise substantially equivalent to those a party would use to protect its own interests.’ It does not require best or optimum efforts,” the commission said.
FERC in July dismissed the developer’s allegation that NYISO and the utility failed to use reasonable efforts in processing the interconnection request for the Greene County 3 project and violated the FPA by applying an “inclusion practice,” which was used to determine the firmness of an interconnecting project but is not delineated in the tariff regarding queue position. (See FERC Denies Solar Queue Complaint against NYISO, Central Hudson.)
In September, FERC denied Hecate’s request to rehear the order but said it would address the company’s concerns in a future order — the one issued Thursday.
“Hecate continues to downplay the various features that made the project atypical and contributed to the lengthier than typical study process,” the commission said in its latest order.
For example, FERC said Hecate asserted that the project has always been 20 MW. While that statement was true on Jan. 10, 2017, the date of the interconnection request that ultimately sparked the complaint, it does not portray the full picture the commission found. As NYISO explained, and Hecate corroborated, prior to Hecate’s submission of the project’s interconnection request, the company submitted an interconnection request for a 50-MW facility, which was subsequently withdrawn and split into three separate projects, one of which represents the original the project, the commission said.
The commission said it continued to find that the amount of time between the date the interconnection request and when respondents executed the facilities agreement was reasonable “given the complexities of the project.”
The commission also noted that Hecate’s request for relief was premature.
“As the project now will enter the subsequent Class Year, where it will be restudied, the possibility remains that the cost or amount of system upgrade facilities assigned to the project will change as the upgrade costs may be allocated to several projects,” the commission wrote.
Nor did FERC agree with Hecate’s contention that Central Hudson’s inclusion practice ”unfairly delayed its place in the queue.”
NYISO’s tariff “provides sufficient notice that transmission owners will update NYISO regarding facilities that should be included in the Base Case for NYISO’s studies of interconnection requests,” and the “‘rule of reason’ does not require the ‘inclusion practice’ to be explicitly set forth in the tariff,” the commission found.
