Michael Hanson has been in the wind energy workforce for 14 years. He started onshore, managing the operation, maintenance and repair of turbines at a number of sites before moving to the first offshore wind farm in the Western Hemisphere, the 5-MW facility off Block Island, R.I.
It takes a diverse village to run a successful wind farm, according to Hanson.
“You can cast a wide net and get good people from a variety of backgrounds,” said Hanson, operations and maintenance manager for GE Renewable Energy.
Hanson was part of a panel at the American Wind Energy Association 2020 Offshore Windpower Virtual Summit Tuesday that discussed the education and training needed to prepare the American wind energy workforce of the present and future.
Marjaneh Issapour| Farmingdale State College
Marjaneh Issapour, an electrical engineering professor and director of the Renewable Energy and Sustainability Center at Farmingdale State College in New York, said there are many different areas of expertise and credentials needed to “fully deploy the wind energy workforce in the United States.”
Issapour said about 47% of jobs in the field are entry-level, open to high school graduates or those who have completed apprenticeships or associate degrees. Another 41% require a bachelor’s degree, with only 12% requiring a master’s or doctorate.
Among the two job titles in most demand are wind technicians, representing 9% of the total, and wind engineers, representing 12%. “Wind engineer is a multidisciplinary expertise that is a cross … of mechanical, electrical and possibly civil engineering,” she said.
Nuria Soto | Avangrid Renewables
Nuria Soto, senior director of offshore operations for Avangrid Renewables, said 20 years ago there were no offshore wind technicians, and “now it’s an established industry” that is also moving very fast and also needs workers for OSW development, construction and operations.
“One of the main challenges is to ensure that the workforce is ready, and the supply chain is ready,” Soto said. “All these jobs will support the different phases of each project.”
In another panel, Mark Mitchell, director of generation projects for Dominion Energy, said the industry is generating an increasing number of jobs today.
This summer, Mitchell said, Dominion had more than 25 vessels operating with more than 400 people working on the utility’s two-turbine pilot project, now in operation, and early work on its 2.6-GW commercial-scale project.
Workers needed for the U.S. wind energy workforce | National Renewable Energy Laboratory
“We’ve got several hundred [people] working today offshore. It’s not just something in the future. It’s kind of here and now, creating many, many jobs,” Mitchell said.
Bruce Gresham | International Marine Contractors Association
Bruce Gresham of the International Marine Contractors Association said there’s “a mix of different levels of experience” needed to work on OSW facilities. Gresham added that tens of thousands of workers in the offshore oil and gas industry laid off during the COVID-19 pandemic have that kind of baseline experience.
“The younger generation is much more interested in working for the wind industry than the dirty oil industry,” he said.
Soto said Avangrid’s internships are a good opportunity to see how a project is developed and understand different roles.
Hanson said the best training from his perspective is to come from an onshore facility. OSW turbines are “the biggest, most technologically advanced in the world, and having that experience on the smaller machines, I think is second to none.”
Michael Hanson | GE Renewable Energy
That does not diminish other experience, Hanson added.
“There [are] so many different jobs that are going on within a turbine — you can come from being an electrician or technician or a mechanic or someone from the oil and gas industry, or of course from another renewable energy field or utility,” said Hanson, who also mentioned technical college and military training.
“The maintenance and construction of generators at heights in a marine environment is a new industry,” said Andy Goldsmith, a technical adviser for IMCA. “But marine construction and going to sea … is not a new industry. Lighthouses and such … have been constructed for eons, let alone the oil and gas industry, which of course started back in the [19]60s.”
The U.S. energy industry is still wrestling with the economic and social impacts of the COVID-19 pandemic that gripped the world nearly nine months ago, experts said Tuesday.
Managing the magnitude of the pandemic was the first discussion at the Energy Bar Association’s 2020 Fall Conference, held virtually Tuesday because of the pandemic. The discussion covered load impacts and economic consequences for utilities, regulatory responses, consumer-side adjustments and fuel and supply chain price changes.
Panelists included John O’Brien, executive vice president for strategy and public affairs at Washington Gas, and David DesLauriers, vice president at Charles River Associates.
Frank Graves, a principal with The Brattle Group, said the COVID-19 burden has been “uneven” across the energy industry, with different utilities and sectors experiencing contrasting impacts.
Utility companies have weathered most of the economic impacts of COVID-19, Graves said, while some businesses in the energy sector, such as small oil and gas development companies, have experienced bankruptcy. He said utility stocks have trailed the S&P 500, remaining relatively sluggish throughout the summer versus the S&P 500’s overall growth of 10%.
“Even though we’ve improved a lot, we still aren’t very close to where we would like to be,” Graves said.
The U.S. Energy Information Administration forecasts that 2020 electricity consumption will drop by 2.2% relative to 2019 based on a 3.2% increase in residential sales, a 6.2% drop in commercial sales and a 5.6% drop in industrial sales.
Daily LMPs have been below past two-year averages by 10-70% in almost every month since February in every ISO/RTO, Graves said. The drop in LMPs is not solely due to COVID-19 consumption changes, he said, with lower natural gas costs — partially the result of the pandemic — likely playing a bigger role.
But the drop in LMPs will strain the viability for some coal and nuclear plants, Graves said. ERCOT prices were down 64% in September compared to the two-year historical average, while PJM and NYISO have seen declines of 33% and 32%, respectively, in the same period.
Graves highlighted the impact on regional electric loads, which declined by 7% in September compared with the previous four years, despite a return to relatively normal in mid-summer. The September decline was in line with the April (6.5%) and May (7.5%) declines at the height of the pandemic.
PJM and MISO accounted for most of the September decrease, with states in their footprints seeing among the largest surges in COVID-19 cases since mid-summer, Graves said. Warmer than normal temperatures in those regions also contributed to the decline, along with colleges and universities that have not reopened campuses.
“We haven’t been able to unpack this very much, but that’s a surprise that there’s a big drop in September when we’ve had some economic rebound over the last few months,” Graves said.
‘Devastating’
Sandra Mattavous-Frye of the D.C. Office of the People’s Counsel said the pandemic has been “the single most devastating event to impact our country” in more than a century and no sector, population or industry has gone unscathed, including the energy industry.
Mattavous-Frye said the unique nature of the pandemic provides challenges for the energy industry but affordable, safe and reliable utility service, along with strong consumer protections, remains her guiding principle as a consumer advocate.
She said three principles must be in place when dealing with the fallout from COVID-19.
First, there must be equitable cost sharing. While the financial stability of utilities must be ensured, it can’t be “business as usual” where ratepayers are expected to bear the entire cost — utilities must also carry a fair share, she said.
Second, public officials must implement enhanced and sustainable permanent consumer protections for underserved and low- to moderate-income households. Those protections must offer a comprehensive approach to service disconnections, including reasonable payment and billing plans.
Finally, industry participants should identify the short- and long-term negative impacts of the pandemic on all segments of the energy industry. She said forums like Tuesday’s event are a good start.
“I really believe it is an obligation to step outside of the box of our traditional regulatory roles with a shared commitment to overcome the challenges we are facing and explore viable options to address the problem head on,” Mattavous-Frye said.
Global Infrastructure Partners announced Tuesday it will sell generation developer and operator Competitive Power Ventures (CPV) to Tel Aviv-based OPC Energy and Israeli institutional investors. Terms were not announced.
Maryland-based CPV, which develops natural gas and renewable power generation, is one of about 40 portfolio companies owned by GIP, which invests in the energy, transport and water/waste sectors internationally.
The sale would include all of CPV’s 5.3 GW of generation in the U.S. as well as its development pipeline and asset management business, which operates more than 10.6 GW of fossil and renewable generation in nine states for 13 owner groups.
Incorporated in 2010 as the first private electricity company in Israel, OPC Energy generated about 5% of that nation’s electricity in 2018. It will own 70% of CPV and serve as general partner, with the remainder owned by three Israeli institutional investors: Clal Insurance Enterprise Holdings Ltd. Group (12.75% interest), Migdal Insurance and Financial Holdings Ltd. Group (12.75% interest) and Poalim Capital Markets (4.5% interest).
Pending regulatory approval, closing of the sale is expected in early 2021.
| Competitive Power Ventures
OPC said it plans to invest “significant capital” in CPV to fund future growth with a focus on renewable and combined-cycle gas generation. It said CPV’s leadership team will remain intact. “OPC has long recognized the potential in the U.S. electricity market,” OPC CEO Giora Almogi said in a statement.
Founded in 1990, CPV was acquired by GIP five years ago.
“We look forward to the opportunities created by our new partnership with OPC, which positions us well for our next phase of growth during a pivotal time as the U.S. transitions toward greener and lower emitting generating resources,” CPV CEO Gary Lambert said in a statement. ” … I am grateful to Global Infrastructure Partners for its confidence in CPV over the past five years, providing not only access to capital but credible execution and operations expertise that helped guide us through a significant growth period.”
Tom Rumsey, CPV’s senior vice president of external and regulatory affairs, told RTO Insider the company will continue to pursue natural gas generation investments as well as renewables.
CPV Three Rivers Energy Center near Chicago is expected to go into operation in 2023. | Competitive Power Ventures
“We are very focused on reducing carbon emissions from the power sector, but policy must align with technological capability,” he said. “As we’ve seen in California, without dispatchable power to augment and facilitate the growth of renewables, reliability is difficult if not impossible to maintain. Highly efficient and operationally flexible natural gas resources are exceptional partners to today’s renewable technologies, specifically wind and solar. We have very aggressive development programs for both.”
Portfolio
CPV’s portfolio includes an 805-MW combined cycle plant in Connecticut and three combined cycle plants totaling 2,500 MW in PJM, with a fourth, the CPV Three Rivers Energy Center, a 1,250-MW combined cycle plant in Grundy County, Illinois, southwest of Chicago, under development.
CPV, GE Energy Financial Services, Osaka Gas USA, Axium Infrastructure and Harrison Street announced the financial closing on Three Rivers in August. The $1.3 billion plant is expected to commence operations in 2023.
CPV is also developing a 100-MW solar project in Pennsylvania and a 50-MW solar farm in Massachusetts.
Most of CPV’s generating capacity is in PJM. | Competitive Power Ventures
CPV attracted some undesirable attention in 2016 over its development of the Valley Energy Center, a 680-MW combined cycle plant in Orange County, N.Y., when Peter Galbraith Kelly Jr., then the company’s head of external affairs and government relations, was indicted in a federal bribery case involving two former aides of Gov. Andrew Cuomo. (See Competitive Power Ventures Lobbyist, Former Cuomo Aides Named in Bribery Indictment.)
Kelly was sentenced in October 2018 to 14 months in federal prison after pleading guilty to creating a $90,000-a-year “low-show” job at CPV for the wife of Joseph Percoco, then Cuomo’s executive deputy secretary. Percoco received a six-year sentence.
Kelly pleaded guilty to defrauding CPV by falsely claiming that Percoco had obtained state ethics approval for his wife to work at CPV. She was paid $285,000 over the course of three years through a consultant in an effort to hide the payments, according to trial testimony. Kelly also made sure that Percoco’s wife’s photograph and full name were not included in promotional materials for CPV.
A 2019 outage event in the United Kingdom highlights the need for both comprehensive underfrequency load shedding (UFLS) protection and an understanding of the impact of a “rapidly changing portfolio” of generation resources on reliability of the electric grid, according to a “lessons learned” notice from NERC.
The incident began Aug. 9, 2019, with a lightning strike on a 400-kV transmission line north of London that caused a single-phase-to-ground fault. The fault was detected and isolated, and the line was reclosed within 20 seconds. During that time, a steam turbine at the combined cycle plant in nearby Little Barford tripped offline, removing 244 MW of generation from the grid. At the same time, the Hornsea offshore wind farm, operated by Danish energy company Ørsted A/S, unexpectedly reduced output from 799 MW to 62 MW.
Parameters measured at Hornsea Onshore Station — MW and MVAR | NERC
After grid control systems reduced generator output — including 150 MW of distributed energy resources (DER) as part of the rate of change of frequency (ROCOF) scheme, an additional 350 MW of DERs tripped offline, resulting in a cumulative loss of nearly 1,500 MW of generation within one second of the fault. Within 58 seconds, frequency had declined from the European standard of 50 Hz to 49.1 Hz.
After another 33 seconds, as frequency was recovering to 49.2 Hz, a combustion turbine at the Little Barford plant — generating 210 MW — tripped offline, causing another frequency decline. As grid frequency passed below 49 Hz, more DERs tripped, and then operators at Little Barford took a second 187-MW combustion turbine offline. By this point, the cumulative generation loss stood at 1,878 MW and frequency had declined to 48.8 Hz, triggering UFLS schemes that disconnected 931 MW of load. This allowed the frequency to stabilize and begin to recover.
Frequency throughout the event | NERC
Poor Understanding of Weak Conditions
Post-event analysis found a number of issues with the performance of both Ørsted and local grid operator RWE. One of the most important was “limitations in [RWE’s] knowledge” of the Hornsea plant’s control system and “the interaction between its onshore and offshore arrangements,” which caused the loss of 727 MW of generation.
Simplified transmission map for southeast England | NERC
At the time of the transmission line fault, the wind farm was operating in a “weak” system condition due to a number of transmission facility outages already in progress. In addition, one of the undersea cables between the wind farm and land was out of service. As a result, when the voltage control algorithm called for increased output due to the line fault, an oscillation began that led to the overcurrent protection system intervening to reduce output.
The second major contributor to the outage was the Little Barford combined cycle plant, which accounted for more than 640 MW of lost generation capacity. Three issues led to the plant’s shutdown. First, the steam turbine went offline during the initial fault due to a speed sensor input error. The combustion turbine subsequently tripped off after a problem with the steam bypass system led to a buildup of steam pressure, which led operators to take the second combustion turbine offline about 27 seconds later. The cause of the initial speed sensor input error has yet to be determined, but the steam bypass system has since been repaired.
The last significant loss of generation — about 500 MW — came from the shutdown of multiple DERs. Although the initial 150-MW loss was part of normal phase shift protection procedure, the additional 350 MW was unexpected. Investigators determined that some of these DERs tripped offline due to incorrect ROCOF settings, while others were found to have had their UFLS triggered at 48.9 Hz instead of the correct setting of 47 Hz.
Study Needed on Behavior of Renewables, DERs
Corrective actions recommended by RWE in the aftermath of the event included reviewing its operational criteria to “determine whether it would be appropriate to provide for higher levels of resilience in the electric system,” along with reviewing the time scale for anti-islanding protection to “reduce the risk of inadvertent tripping and disconnection of embedded generation.” The utility also recommended an industry-wide review, involving regulators, utilities and other stakeholders to establish communication protocols for future events.
NERC’s analysis focused on the implications of the widespread adoption of renewable energy and DERs on grid reliability, in particular their “increasingly complex controls” that make it difficult to “predict resource responses to network faults.” The organization noted several potential flaws in RWE and Ørsted’s procedures:
Overreliance on self-certification of the models for generating resources, including DERs;
Insufficient understanding and coordination of the interactions between onshore and offshore wind generation control systems, particularly the performance of wind farms in weak system conditions;
Inadequate coordination between transmission planners, generation and transmission owners, reliability coordinators and equipment manufacturers to accurately model their connected resources;
Outdated tools, techniques and simulation approaches to planning and operations, particularly related to weak grid conditions and inverter-based resources; and
Inadequate understanding of the impact of tripping multiple DERs on grid reliability.
To illustrate one approach to modeling DERs, NERC cited PJM’s use of publicly available data, from sources such as the Energy Information Agency and its own Generator Attribute Tracking System, combined with data requested from transmission owners. The RTO uses this information to generate behind-the-meter solar forecasts that are factored into its load forecast and to notify TOs of generation resources that may be available to help with a transmission emergency.
In addition, Thomas Bialek, the chief engineer for San Diego Gas & Electric, warned in January that the behavior of residential rooftop solar panel users is often very different than that expected by system planners. This creates “hidden loads” that can’t be accounted for in planning, he said. (See Rooftop PV’s ‘Hidden Loads’ Challenge Grid Planners.)
The NEPOOL Markets Committee last week debated 13 amendments to proposed updates to parameters for Forward Capacity Auction 16 (2025/26).
Many of the amendments, which were discussed during the last half of the committee’s Oct. 6-8 virtual meeting, challenged revenue figures proposed by Concentric Energy Advisors (CEA) and Mott MacDonald, two consulting firms hired by ISO-NE to update the FCM parameters.
Deborah Cooke, the RTO’s principal analyst for market development, presented responses to stakeholder questions about updates to the net cost of new entry (CONE) and offer review trigger prices (ORTPs).
Abby Krich and Alex Worsley of Boreas Renewables presented four amendments on behalf of RENEW Northeast, including capital costs and the investment tax credit for the ORTP calculation for offshore wind. A capacity offer below the ORTP triggers a unit-specific review by the Internal Market Monitor to verify the resource’s cost.
RENEW said the RTO’s proposal to use $5,876/kW (2019$) for the overnight capital cost of OSW and assumption of a 0% tax credit results in an ORTP of $52.46-$52.67/kW-month, which RENEW believes is double the actual cost. [Editor’s note: An earlier version of this article did not include ISO-NE’s updated figures.] RENEW has proposed using a lower overnight capital cost of $3,000/kW (2019$) and a higher tax credit of 18%.
Krich said $3,000/kW is a reasonable, middle-of-the-range estimate of expected costs for OSW projects in New England. A capital cost of up to $3,200/kW would still result in an ORTP of $0.
CEA said the RENEW analysis is “inappropriate,” and its estimated ranges should be revised upward. CEA challenged RENEW’s use of data from European and Chinese projects.
Krich told RTO Insider after the meeting that ISO-NE’s cost was accurate “8-10 years ago,” but they are no longer appropriate.
‘More Reasonable’ EAS Revenues
Ben Griffiths, an energy analyst for the Massachusetts Attorney General’s Office, offered a summary memo and presentation that outlined “a straightforward optimization model to more reasonably estimate” energy and ancillary services (EAS) revenue available to a storage device. Griffiths said the AG’s model produces “an operational schedule for storage that maximizes revenues” from participation in three of the RTO’s markets — energy, 10-minute spinning reserves and regulation — while respecting the storage device’s technical limitations.
The Block Island Wind Farm, off Rhode Island | Block Island Ferry
Griffiths added that the AG disagrees about the “reasonableness of the CEA EAS revenue estimates for battery storage resources.”
A reasonable operator using a battery for energy, reserves and regulation should be able to earn $54.87/kW-year, assuming the Forward Reserve Market (FRM) sunsets, and $59.11/kW-year, assuming the FRM is maintained, Griffiths wrote. CEA’s contrasting estimates average EAS revenue from these three markets at $45.71/kW-year with an FRM sunset and $55.26/kW-year assuming it is maintained.” (See “Support for Forward Reserve Market Sunset,” NEPOOL Markets Committee Briefs: Oct. 6-8, 2020.)
Griffiths said these revenue estimates are “conservative” and the AG’s office “fully expects that more advanced dispatch schemes could yield higher revenues.”
NEPGA Proposes Amendments on Amortization Period, Owner’s Cost
The New England Power Generators Association (NEPGA) proposed changing the amortization period for the net CONE reference unit (a GE 7HA.02 gas-fired combustion turbine) to 15 years from 20 years. NEPGA’s Bruce Anderson said the 20-year amortization period fails to reflect the risks faced by developers, which creates “a finite period concluding in economic obsolescence.” There is “no evidence that the reference unit would be able to sustain its annual cash flows in real dollar terms for 20 years,” he added.
Anderson said NYISO recently reduced its reference unit’s economic life to 17 years to recognize the potential impact of New York state law and policy. In New England, most states have renewable portfolio standards requirements that involve the procurement of energy from non-carbon-emitting resources.
Additionally, NEPGA put forth an amendment that would take a “bottom’s up approach” to the owner’s cost. NEPGA proposes $12.45 million in owner’s cost — almost five times Mott McDonald’s $2.5 million estimate, which Anderson said is “woefully inadequate” to cover the known owner’s costs, let alone any contingencies.
NEPGA said its figure takes into account initial screening studies and work sufficient to qualify for the FCA and obtain a capacity supply obligation (CSO), plus activities necessary to install the equipment, interconnect it and ensure successful commercial operation. NEPGA said it ignored costs associated with electrical interconnection, network upgrades, gas interconnection, gas pipeline upgrades, initial fuel inventory and financing costs, while Mott McDonald said its estimate captured these activities and contingencies.
At NEPGA’s request, CEA and Mott McDonald updated their dispatch to include seasonal intraday fuel price premiums ranging from 4% in summer to 20% in winter.
NEPGA had asked for time on the agenda to amend the net CONE proposal to include an intraday premium in the event CEA and Mott McDonald chose not to account for it in their updated modeling. NEPGA said it will evaluate the consultants’ proposed intraday premium accounting and could bring forward an amendment at the November committee meeting.
NESCOE Amendments Look at Reference Unit, PfP
While NEPGA sought to shorten the reference unit’s assumed life, NESCOE said it should be increased. NESCOE’s two amendments would boost the useful economic life of the reference unit to 25 years and escalate pay-for-performance (PfP) revenues to account for inflation.
NESCOE proposed that the net CONE resource should be increased to reflect the expected economic life of the reference unit and that PfP should be increased for inflation, reflecting the recalculation of the performance payment rate (PPR) every three years. There are no corresponding Tariff language revisions since these amendments are changes to input assumptions in the analysis.
Calculating net CONE using a 25-year life for the resource reflects a better balance between the physical life of these facilities and a reasonable expectation of their economic life, NESCOE said. The estimated reduction in net CONE is $0.63/kW-mo. Adjusting PPR revenues for inflation is more consistent with the treatment of other revenues with an estimated reduction in net CONE of $0.12/kW-mo., it added.
PJM stakeholders last week endorsed a “quick-fix” manual revision to correct a date reference in Manual 18 following a discussion in which some members objected to the process and suggested further talks on lingering pseudo-tie issues.
Jeff Bastian of PJM reviewed the problem statement and issue charge to correct Manual 18’s reference to the effective date for notifying pseudo-tied resource owners of their assigned locational deliverability area (LDA) prior to each delivery year. The Market Implementation Committee endorsed the measure with 78% support (149 votes) at its Oct. 7 meeting.
Bastian said under initial Capacity Performance provisions, a performance shortfall was calculated for external generation capacity resources only during performance assessment hours for when the emergency action was declared for the entire PJM region.
However, in November 2017, FERC accepted changes to be effective with the 2020/21 delivery year that would calculate a performance shortfall for external generation capacity resources for any performance assessment interval for which performance by such external resources would have helped resolve the emergency (ER17-1138). (See FERC OKs Change to MISO, PJM Pseudo-Tie Rules.)
PJM Manual 18 changes made to conform with the accepted provisions incorrectly specified the provisions as being effective with the 2021/22 delivery year, Bastian said.
Carl Johnson of the PJM Public Power Coalition said he recognizes what PJM was trying to accomplish with the change and why it would be done in the quick-fix process. Johnson said he represents some members who were involved in the FERC docket on the issue who still have concerns they feel are unresolved and would like to see PJM address them in a new problem statement and issue charge.
Johnson said the PPC would like to address some of the issues that FERC said were out of scope for the proceeding but should be raised in the stakeholder process. He cited questions about pseudo-tied resources’ obligations, how they receive pricing and penalties that may be imposed on an external resource. (See FERC Sets Hearings in PJM Hydro Pseudo-Tie Spat.)
Steve Lieberman, assistant vice president of transmission and PJM affairs for American Municipal Power (AMP), said he agreed with Johnson about opening a stakeholder process to examine unresolved issues. AMP was one of the entities that challenged PJM’s requirements for pseudo-tied generators. (See FERC Sides With PJM on Pseudo-Tie Challenges.)
Lieberman said he was concerned by PJM’s use of the quick-fix process to make the change because it affects a specified delivery year that has already started.
“It just strikes me as a little unsettling that we would be making a change after the start of a delivery year,” Lieberman said. “I just don’t like seeing us go down the path of making changes that specify a specific start time that’s already passed.”
Bastian said the Tariff correctly lists the 2020/21 delivery year as the effective date, superseding the manual language. Bastian said the idea was to make the two documents consistent and eliminate the discrepancy.
Sharon Midgley of Exelon said her company is supportive of PJM’s quick-fix and didn’t think it was appropriate to hold up a conforming change to a manual to discuss other issues. Midgley said Exelon would support stakeholders continuing a discussion and bringing forward a new problem statement and issue charge.
Behind-the-meter Generation
Members unanimously endorsed clarifications to the behind-the-meter generation (BTMG) business rules for units changing status from netting against load to participating in PJM markets.
Terri Esterly of PJM reviewed the problem statement and issue charge addressing the clarifications, saying a BTMG unit can be designated as a capacity resource or energy resource in the wholesale markets or be designated as BTMG netting against load on a unit-specific or partial-unit basis. Any BTMG unit seeking to be designated in whole or in part as a wholesale resource must submit an interconnection request.
BTMG rules were developed beginning in 2003 within the Behind-the-Meter Generation Working Group, Esterly said, and there has been limited review of the rules governing them since their development. Esterly said the OC in 2019 endorsed clarifying updates to BTMG business rules focused solely on the reporting, netting and operational requirements of non-retail BTMG.
Esterly said the Tariff and Manual 14D updates are needed because of the increased development of distributed energy resources and load-serving entity requests for adjustments to network service peak load and obligation peak load to reflect new BTMG.
The key work activities include providing education on existing BTMG business rules on status changes in the Tariff and Manual 14D. Work also will include reviewing and identifying business rules related to status changes that would benefit from clarification or additional detail or that may conflict with existing rules.
Stakeholders are expected to work on the issue for four months.
Midgley asked how the BTMG effort lines up with PJM’s compliance activities associated with FERC Order 2222 and what steps the RTO will take to make sure there are no conflicts between what stakeholders develop in the BTMG effort versus what is developed for Order 2222. (See FERC Opens RTO Markets to DER Aggregation.)
Esterly said the BTMG effort is to clarify existing rules but additional changes may be needed because of Order 2222.
Real-time Values Market Rules
Laura Walter, senior lead economist, provided an update on the work completed during the MIC special sessions on real-time values market rules and reviewed the proposed packages from the solutions matrix.
The special sessions have been taking place since January, after stakeholders endorsed an issue charge at the December Markets and Reliability Committee meeting. (See “Real-time Values,” PJM MRC Briefs: Dec. 19, 2019.) The problem statement said observations indicated real-time values were being used to consistently override unit-specific parameter limits or approved parameter limited exceptions.
The original intent of RTVs was to provide a way for generation operators to communicate current operating capability to PJM if their resources couldn’t meet their unit-specific parameter limits or approved exceptions, Walter said. Generators opting to use RTVs forfeit operating reserve credits and make-whole payments.
In a nonbinding poll conducted in August, 55% of stakeholders said they supported the PJM package, and 10% gave support for the IMM package, while 71% said they were happy with the status quo.
Walter said market participants that repeatedly fail to reflect actual operating conditions in their submitted operating parameters could be referred to FERC for enforcement. The package also calls for adding real-time values to the Tariff. Currently, real-time values are mentioned only in the manual, Walter said.
The IMM proposal includes removing minimum run time from the list of eligible parameters with RTV submissions. It also said units that choose to run longer can self-schedule beyond the minimum run time, with PJM operator notification.
The proposal also prevents withholding by using longer minimum run time, Walter said. Any penalties collected are to be allocated to daily real-time load.
The MIC will vote on the PJM and IMM packages at the November meeting with a first read scheduled for the December MRC meeting.
Manual 15 Review
Stakeholders unanimously endorsed revisions to Manual 15 as part of the biennial review. Gabrielle Genuario of PJM reviewed updates to Manual 15, including reformatting and rewording in sections 2.6.1 and 2.6.8 to provide more clarity.
The revisions will be voted on at the Oct. 29 MRC meeting and the Nov. 19 MC meeting.
The changes include an added reference to the day-ahead and real-time sections in Section 2.2: Definition of Locational Marginal Price and updated “LMP verification” to “price verification” throughout Section 2.10: Verification Procedure as verification includes review of real-time and ancillary service prices.
Stakeholders will vote on the proposed updates at the November MIC meeting.
Transmission congestion around New York City could increase after the first 6,000 MW of offshore wind is interconnected without coordinated planning, NYISO told state officials Friday.
The state hopes to develop 9,000 MW of offshore wind (OSW) by 2035.
Having offshore wind energy interconnect to load centers in the city and on Long Island “certainly helps offset some of the transmission constraints that you might experience; but nevertheless, to meet a total 9,000-MW goal of offshore wind, there absolutely will be transmission constraints,” said NYISO Vice President for System and Resource Planning Zach Smith at a technical conference hosted by the state’s Department of Public Service and the New York State Energy Research and Development Authority (NYSERDA).
This NYISO map shows renewable generation that would be curtailed because of insufficient bulk and local transmission capability to deliver the power. | NYISO
The conference was intended to inform a study to be completed by year-end on an investment plan to be established by the Public Service Commission for distribution and local transmission upgrades and a second plan for bulk system transmission investments (Case No. 20-E-0197). (See NYPSC Launches Grid Study,Extends Solar Funding.)
Offshore wind is central to compliance with the Climate Leadership and Community Protection Act (CLCPA, A8429), which mandates that 70% of electric power in New York come from renewable resources by 2030 and that electricity generation be 100% carbon-free by 2040.
Smith noted that in the 2019 Congestion Assessment and Resource Integration Study (CARIS), published in July, the ISO only modeled 6,000 MW of OSW for the 70%-by-2030 scenario. As generation increases up to 9,000 MW, transmission constraints around the city and Long Island will worsen, he said. (See Bulk Tx, 115-kV Upgrades Needed for NY 70×30 Goal.)
“There could even be a tipping point, where as you increase beyond that 6,000 MW, it could get much worse than what we’ve identified,” Smith said. “We assumed projects be interconnected according to what’s been proposed in the NYISO interconnection queue. [It’s possible] projects might interconnect much differently than what we assumed in our study, and if they do, then the results will change.
“We believe in general that our results are valid in terms of being indicative of constraints, but when you really dive into the details … those individual transmission constraints really are driven by some of the assumptions on points of interconnection, and that is particularly true with regard to offshore wind,” he said.
HVDC Gains Favor
Technology providers and independent transmission developers also presented the conference with their ideas on how New York’s grid could evolve, including the prospect of more high-voltage direct current (HVDC).
Ben Marshall, HVDC Centre | NYDPS
Ben Marshall of the National HVDC Centre in Scotland said the capacity of HVDC in Great Britain will grow from 8 GW today to an estimated 45 GW by 2028 and is expanding in other parts of Europe as well, especially in conjunction with offshore wind interconnections.
Electronic devices that measure the system and take actions increasingly dictate the performance of the grid, Marshall said. Decisions around constraints operate across seconds, decisions around frequency operate across second- to half-second periods and decisions around voltage control are made across hundreds of milliseconds, Marshall said.
“Control systems are making decisions within tens of microseconds; they’re operating very quickly, very flexibly, and it’s important that they operate correctly,” he said.
Marshall also pointed to the emerging risks of having system controls be digital rather than analog: “If I look under the hood of an older car, I know what I’m seeing with the carburetor, but in a new one, all I see is plastic … which is similar to what’s going on with the proprietary control systems, so you need either to counter that effect or to contain it.”
Elizabeth Griffin, Con Edison | NYDPS
Elizabeth Griffin of Con Edison Transmission said DC technology will be a critical tool to maximize the state’s transmission investments.
“Based on currently proposed projects, it appears that DC will be the future for projects to bring renewables downstate via a potential Tier IV REC [renewable energy credit] procurement, as well for the upcoming offshore wind procurements, just given the distance of the current leaseholds from potential interconnection points,” Griffin said.
DC also has several advantages over AC that make it particularly well-suited for New York’s emerging transmission needs. “DC allows for the maximum utilization of transmission capacity – in the same right of way you can flow more power over DC – as well as for a level of control that is not available on AC lines,” she said. “DC also allows for long distance underground and underwater transmission options that we think will help improve community acceptance by avoiding the need to install additional transmission towers.”
Regulators need to determine how to manage transmission, and particularly how NYISO will operate intrastate DC lines that are integrated with the existing New York Control Area network to maximize its advantages, Griffin said.
Shared infrastructure can maximize the benefits and minimize the environmental impacts of transmission, “which can be particularly beneficial for offshore wind and for aggregating renewables to bring them into New York City,” Griffin said. “Unfortunately, the substations themselves, particularly in Zone J, are often very constrained due to limited real estate, limited physical space within the substation and limited electric capacity. When an open bay at a substation is used to connect less than the maximum capacity potential for that substation, the ability to connect additional volumes without physically expanding the substation may be lost.”
Creating access to the existing transmission grid will require significant additional underground transmission infrastructure that would be best developed with expansion in mind and shared among transmission projects, she said.
“Well-planned and coordinated transmission can make sure that these limited interconnection points are used to provide the maximum benefit and capacity to the system,” Griffin said. “A separate offshore grid will be better for customers in terms of grid reliability, flexibility and total cost effectiveness when compared to the individual generator lead-line approach that has been pursued to date and was appropriate for the initial projects.”
Pancaking and Cost Savings
Transmission developer Anbaric Development Partners determined that 1,500 MW of load was typical of 3 a.m. on any Sunday on Long Island and that therefore there will always be more wind than load. So early on, it started to think about where to put this energy.
Howard Kosel, Anbaric | NYDPS
The company found 23 points of interconnection (POI) in the city and on Long Island, which screening reduced to about a dozen. Some of the POIs were in good locations but needed to be upgraded to increase their injection capability, said Anbaric Partner and Project Manager Howard Kosel.
“We set a criterion of $1 million per megawatt, and we capped it at $50 million, because we had to set the bar somewhere,” Kosel said. “As we started to grow to get to the 9,000 MW, we were [learning about] the impact the particular POI had on the next POI … it became obvious that upgrading POIs required careful sequencing so as to prevent pancaking, whereby the next POI loses transfer capacity … [and] we saw that we could save upgrade costs of $500 million to $1.2 billion.”
Offshore wind’s intermittency will be complemented by solar and wind energy from northern, central and western New York state, where three public policy transmission projects are now underway under FERC Order 1000.
Innovation is a key benefit for those projects, said Lawrence Willick, senior vice president for project development at LS Power Development, which is partnering with the New York Power Authority on a 345-kV transmission project to relieve congestion at the Central East interface.
Fernando Gallinas Victoriano, business development manager for Avangrid Networks, said that integrating 9 GW of offshore wind requires “a planned, coordinated approach” for New York City and Long Island.
Paul Haering, NY Transco | NYDPS
“The HVDC technology could be used over existing cables and rights of way, or even through new greenfields, in order to facilitate larger transfer capacity in the system, and with lower implementation periods,” Victoriano said. “Incremental transfer capacity with neighboring systems will bring significant reliability benefits to New York.”
Paul Haering, vice president of capital investments at NY Transco, said that technology and innovation will be critical to achieving the state’s clean energy goals, and that the long time it takes to build transmission “is why we need to act quickly.”
NY Transco was created to develop and own high-voltage electric transmission facilities in New York, and comprises the transmission subsidiaries of Avangrid, Con Edison, National Grid and Central Hudson Electric and Gas.
PJM stakeholders last week unanimously endorsed an installed reserve margin (IRM) of 14.4%, down from 14.8% required in 2019, along with new winter weekly reserve targets.
During the Oct. 6 Planning Committee meeting, PJM’s Patricio Rocha Garrido reviewed the 2020 Reserve Requirement Study (RRS) results, which determined the IRM and forecast pool requirement (FPR) for 2021/22 through 2023/24 and establishes the initial IRM and FPR for 2024/25. The results are based on the 2020 capacity model, load model and capacity benefit of ties (CBOT).
The 2020 capacity model is putting downward pressure on the IRM, Garrido said, with the average effective equivalent demand forced outage rate (EEFORd) of 5.78%, compared to 6.03% in the 2019 RRS. Garrido said the lower average EEFORd was caused by the increased representation of combined cycle units and gas turbines.
The CBOT — the help PJM can expect from imports during peak loads — is estimated to increase pressure on the IRM. Garrido said imports from neighboring RTOs have decreased from 1.6% in 2019 to 1.5% in 2020.
“We’re getting a little less help from our neighbors,” Garrido said.
The FPR is essentially the same as 2019, Garrido said, coming in at 1.0865 (8.65%) instead of 1.086 the previous year.
| PJM
Garrido said the study results will also be used in the 2022/23, 2023/24 and 2024/25 Base Residual Auctions (BRA). He said delays in the 2019 BRA for 2022/23 necessitated the use of data from the 2020 study.
The PJM and world load models used are based on the 2002-2014 period that were approved at the August PC meeting. (See “Load Model Selection,” PJM PC/TEAC Briefs: July 7, 2020.) Analysis from the 2020 PJM Load Forecast Report released in January was also used.
Erik Heinle of the D.C. Office of the People’s Counsel asked if the IRM and FPR would be updated after the first BRA was conducted to make sure the modeling is kept accurate.
Garrido said the driver of FPR is load uncertainty, so the results of the BRA wouldn’t matter for the FPR and does not necessitate a recalculation. Garrido said the recalculation is triggered by a new load forecast, which will be released in January.
Garrido also won a same-day endorsement after conducting a first read of the 2020/21 winter weekly reserve targets, which are slightly changed from last winter.
The targets for December, January and February are 23%, 27% and 23%, respectively, compared to 22%, 28% and 24% last year.
Part of the reserve requirement study, the targets help staff coordinate planned generator maintenance scheduling and cover against uncertainties by ensuring that the loss-of-load expectation (LOLE) for winter is “practically zero,” according to the study. For the entire year, PJM sets the LOLE at one occurrence in 10 years.
Interconnection Queue Initiative
Ken Seiler, vice president of planning, discussed PJM’s plan for a series of workshops to explore ways to improve the efficiency and effectiveness of its interconnection queue process.
Seiler said more than 660,000 MW of generation requests has been studied since the inception of the interconnection process in 1999. More than 70,000 MW has been energized in that time.
“The process has served us well, but the process continues to change,” Seiler said. “We believe it’s time to take a look at some changes within the queue.”
Seiler said the interconnection process has seen many improvements over the years, including automation of tools and additional staffing. PJM currently has 122,000 MW in the interconnection queue with 88% of the megawatts made up of renewable generation sources.
The most recent queue that closed at the end of September has more than 560 projects, Seiler said, with more than 40,000 MW of energy requesting to be interconnected. Of the 560 projects, he said, 500 are either solar or storage.
Based on feedback from stakeholders and the increasing volume and size of the interconnection requests, Seiler said PJM decided it was time to take a “fresh look” at the interconnection process. Four workshops are proposed, including a review of the interconnection process, stakeholder presentations, PJM’s response to the stakeholder presentations and paths forward.
Adrien Ford of Old Dominion Electric Cooperative asked if PJM is looking for feedback on how stakeholders should proceed at looking at the interconnection process or on things that need to be changed in the process.
Seiler said PJM is looking for both things that need to be changed and a process forward to make the changes. He said the RTO has already identified things that need to be changed, but there are also hidden problems that can be identified by stakeholders.
“We want to hear what everyone has to say and what objectives are there and what the end goal is,” Seiler said. “We want to hear everything before locking down a plan to move forward.”
Sharon Segner, vice president of LS Power, said she appreciated the idea of having the workshops but wondered why the RTO hadn’t drafted a problem statement and issue charge to start an official stakeholder process. Segner said it costs time and resources for members to address issues, but with a formal stakeholder process there’s an opportunity to change rules instead of simply having discussions.
Seiler said there hasn’t been a defined problem that would necessitate a solution, so PJM wanted to identify problems through a workshop first before initiating the stakeholder process.
Dave Anders of PJM said a similar workshop method was conducted when stakeholders began looking at the energy price formation issue in 2017. (See PJM Stakeholders Explore Price Formation, Seek Transparency.) Anders said the workshops are designed to expose areas of interest for members to address in the stakeholder process.
ELCC Data Submission
Andrew Levitt of PJM’s market design and economics department provided an overview of the effective load-carrying capability (ELCC) data submission requirements and the applicable deadlines for intermittent and limited duration resources.
ELCC, which is already used by MISO, NYISO and CAISO, evaluates reliability in each hour of a simulated year and compares a resource mix with limited resources against one with unlimited resources.
Members endorsed a joint stakeholder proposal at the September Markets and Reliability and Members committee meetings to use the ELCC method to calculate the capacity value of limited-duration, intermittent and combination (limited-duration plus intermittent) resources. The proposal was endorsed over the objections of the Independent Market Monitor and other stakeholders who said the proposal was flawed and could have profound and unforeseen effects on the capacity market. (See ELCC Method Endorsed by PJM Stakeholders.)
PJM is attempting to make a FERC filing by Oct. 30 to satisfy a paper hearing procedure started last year to investigate whether the RTO’s 10-hour minimum run-time requirement for capacity storage resources is unjust and unreasonable. (See FERC Partially OKs PJM, SPP Order 841 Filings.)
Levitt said PJM needs data submittals from certain resource types by Nov. 1 to release ELCC results by December, the soonest FERC is likely to approve the October filing. Levitt said ELCC could be in place for the 2022/23 BRA.
Under the new rules:
“Immature” and planned solar and onshore wind projects that intend to deliver capacity in 2022/23 must provide estimates of hourly historical production back to June 1, 2012, based on site conditions and historical weather. PJM defines an “immature” resource as solar and onshore wind projects that came into service after June 1, 2012.
Immature and planned offshore wind, landfill gas and hydro without storage that intend to deliver capacity in 2022/23 must provide estimates of hourly historical production back to June 1, 2012.
All energy storage resources, hybrids and hydropower with non-pumped storage must provide relevant physical parameters, including MWh of storage.
Manual 14C Update
Mark Sims, PJM’s manager of infrastructure coordination, provided a first read of changes to Manual 14C: Generation and Transmission Interconnection Facility Construction.
Sims said minor changes are being proposed to Manual 14C as part of the biennial cover-to-cover review. Some of the changes include an update of the with the latest Tariff provisions clarifying the filing process for title transfers and associated title documentation in Section 5.
New sections on cost tracking for baseline projects and another for supplemental cost tracking are also being proposed, Sims said.
PJM will seek approval of the changes at the Nov. 4 PC meeting.
Transmission Expansion Advisory Committee
IEC Project Status
Questions over the status of the controversial Independence Energy Connection (IEC) transmission project were raised during a market efficiency presentation at the Oct. 6 TEAC meeting.
Nick Dumitriu, senior lead engineer for PJM, provided an update on the 2020/21 long-term market efficiency window. Dumitriu said the 2020 Market Efficiency Analysis Assumptions whitepaper was shared with the PJM Board of Managers for consideration at their Sept. 15 meeting.
Dumitriu said a preliminary market efficiency base case was posted Sept. 4, and a retooled base case is expected to be posted by the end of October. The final base case and congestion drivers will be posted in December before the start of the 2020/21 long-term window.
LS Power’s Sharon Segner asked if Transource Energy’s Independence Energy Connection running between Maryland and Pennsylvania will be examined by PJM during the reevaluation analysis scheduled to be completed between October and December as part of the Regional Transmission Expansion Plan (RTEP).
Transource’s proposed alternative plan for the eastern segment of its Independence Energy Connection project | ea
PJM selected the $383 million IEC — its largest market efficiency project to date — during the 2013/14 long-term planning window to address congestion in the AP South interface. The RTO has since reviewed its benefits to the grid several times, determining in each round that the project remains the most effective way to reduce load costs. (See Updated: Transource Files Reconfigured Tx Project.)
Tim Horger of PJM said the RTO has continued to look at the status of the project and is “taking seriously” the project review.
Horger said PJM is deferring a review of the project pending a ruling from the Pennsylvania Public Utility Commission. Transource is seeking the PUC’s approval of land acquisition, siting and construction for a 230-kV line in Franklin and York counties. The record closed with the filing of reply briefs in late September (Docket # A-2017-2640200).
Horger said an update on the project will be provided at the November TEAC meeting.
Segner said PJM has an Operating Agreement requirement to continue reevaluating projects until all required permits have been received.
Horger said the project is in a unique situation where a CPCN has been issued by one of the states involved in the permitting process. He said there are “a lot of moving parts” involved in the project, including reliability impacts.
“LS Power would maintain the position that you have an obligation to follow your Operating Agreement under all circumstances,” Segner said.
A big part of $612 million intended to provide battery backup to homes in high fire-threat areas has been gobbled up by customers who use electricity to pump well water instead of helping the low-income and medically vulnerable residents it was meant for, the California Public Utilities Commission said Thursday.
The CPUC approved $830 million for its Self-Generation Incentive Program (SGIP) in January, with $612 million dedicated to “equity” and “equity resiliency” subsidies to aid residents who face repeated public safety power shutoffs (PSPS) by utilities to prevent wildfires. Thousands of the program’s targeted customers rely on electrically powered medical equipment to keep them alive. (See California PUC Devoting $1.2B to Self-generation.)
In its decision, the CPUC authorized investor-owned utilities to collect $166 million annually from ratepayers from 2020 to 2024. However, the commission did not include income criteria for the well-pump grants, which are part of the program, nor did it prevent customers from applying for funds for their vacation homes.
“We were seeing some second-home residents” receive the hefty grants, which pay the full cost of battery storage and solar cells to charge the units, said Commissioner Clifford Rechtschaffen.
The program’s “very clear focus was on helping the most vulnerable customers and communities in high fire-threat areas and ones that had been affected by multiple PSPS events,” Rechtschaffen said. “In particular, we targeted medical baseline customers, low-income customers and critical care facilities in disadvantaged communities.”
“The program provides very, very generous subsidies,” he said.
Portable solar and batteries are meant to help medically vulnerable customers during power shutoffs under the state’s SGIP program. | Edison International
More than eight months after the decision took effect, with one of California’s worst fire seasons in full force, the state’s three large investor-owned utilities haven’t started reaching out to medically vulnerable customers, Rechtschaffen said.
Instead, developers of storage systems have targeted households with wells, regardless of income, and scooped up much of the funding that was supposed to last through 2024. Commissioner Martha Guzman Aceves said an informal analysis by her staff showed that only a small percentage of the storage contractors were licensed by the state.
Pacific Gas and Electric has already committed its $270 million share of the multi-year program and has hundreds of customers on a waiting list, Rechtschaffen said. Southern California Edison and San Diego Gas & Electric have doled out 50% and 60% of their shares, respectively, he said.
Half the applications have been for well-pump programs, while 30% have been for medically vulnerable customers, he said.
In his proposed decision, Rechtschaffen wrote that “if current trends continue, incentive awards to electric-pump … customers threaten to severely limit the … funds available to the many other types of eligible residential and non-residential customers.”
He proposed adopting income eligibility criteria for grants that haven’t already been funded, requiring households to show they fall below 80% of an area’s median income and that a well provides water for their primary residence.
“Requiring electric-pump well customers to meet the same income eligibility restrictions required of most other …. residential customers levels the playing field and helps ensure that other types of customers with critical resiliency needs have the opportunity to use equity resiliency budget funds,” he wrote.
The decision would apply the new criteria to grants that were submitted but not fully funded as of Aug. 17, when Rechtschaffen issued a letter advising utilities of the commission’s concerns.
Several commissioners expressed unease about applying new rules retroactively to those who have already filed for funding.
“We evidently made a serious omission” in not restricting the funds based on income, said Commissioner Genevieve Shiroma. But “to now go back and say, ‘Oops,’” and change the rules for pending applications, “I’m very uncomfortable with that,” she said.
CPUC President Marybel Batjer said she shared her colleagues’ worries about retroactivity but believes the program must be fixed.
“I’m very concerned about the equity program and it being oversubscribed so quickly when this was [planned] to be a three-year rollout,” Batjer said. “On balance, I think we have to address it. And I agree, Commissioner Rechtschaffen, with your assessment, but I do feel we need more consideration on this item.”
The commissioners voted unanimously to put off a decision until their next meeting on Oct. 22 so they could gather more information and weigh their options.
CAISO said Wednesday it plans to begin a stakeholder initiative on scarcity pricing with an issue paper and formal start in January.
The planned measure is a response to the energy emergencies of August and September, which required CAISO to order rolling blackouts Aug. 14-15. The state avoided additional blackouts only through extraordinary conservation measures, including removing Navy ships from shore power.
Scarcity pricing had been part of the ISO’s efforts to enhance its day-ahead market and extend the Western Energy Imbalance Market from a real-time to a day-ahead market. But the shortages caused a reassessment, Brad Cooper, the ISO’s senior manager of market design policy, said during a web conference on the annual update to CAISO’s three-year policy initiatives roadmap.
“Prompted by the conditions that occurred this summer, we’re now planning a separate initiative that we’re going to prioritize for next year that’s going to explore enhancements to our scarcity pricing provisions,” Cooper said.
“Recently FERC approved our … Order 831 compliance filing, which in some cases raises the bid cap to $2,000, but it does that in relationship to fuel costs,” Cooper said. “Last summer, a lot of times, prices outside the ISO went above $1,000, and that was not driven by fuel costs but by scarcity conditions. Those events really drove home the need to improve our market pricing in those scarcity conditions.”
In September, CAISO’s Market Surveillance Committee recommended the ISO pursue a scarcity pricing initiative to deal with the types of severe shortfalls seen in mid-August and over Labor Day weekend. (See CAISOMSC Urges Scarcity Pricing for Emergencies.)
“The experiences of mid-August again signal the urgency of such an initiative,” the committee said in its unanimous opinion, which it forwarded to the CAISO Board of Governors. “These conditions will likely grow more frequent, and the region is in need of a more coordinated approach to managing scarcity conditions.”
Scarcity pricing will be part of CAISO’s policy roadmap come January. | CAISO
Prices during the Western “heat storm” in August rose to $1,000/MWh or more and showed the need for higher-priced import offers during times of regional scarcity, the committee said. CAISO and market participants have noted that ICE prices for imported energy from neighboring states rose from $1,500 to $1,750 at the Palo Verde trading hub, which feeds into Southern California.
Scarcity pricing is triggered in markets when systems become so strained that reserve margins meant to protect the grid from collapse are threatened, as happened during the August blackouts.
A root cause analysis of the August blackouts by CAISO and other California agencies showed transmission constraints prevented ample, available imports from reaching the CAISO market and did not cite scarcity conditions. (See CAISO Says Constrained Tx Contributed to Blackouts.)
Cooper said he hopes to see an issue paper released soon after Jan. 1.
“We haven’t worked out the detailed schedule yet, but that’s our goal,” he said.
Other major initiatives in the roadmap include resource adequacy enhancements, day-ahead market enhancements and an effort to the extend the Western Energy Imbalance Market from a real-time to a day-ahead market.
All three could help CAISO meet its reliability issues as it switches from a market largely dependent on natural gas generation to one that plans to meet its capacity requirements through renewable energy and storage, ISO staff members said during the web conference.
A high priority is addressing the state’s summer evening net demand peak, after solar power goes offline but demand remains high during heat waves. The energy emergencies of August and September occurred under such conditions.
“A robust RA program is critical to ensuring reliable resources are procured with the right operational attributes and are available to the CAISO in order to serve load in all hours,” said Lauren Carr, an infrastructure and regulatory policy specialist with the ISO who presented the RA initiative.
The 2021 roadmap of policy initiatives is expected to go before the Western EIM Governing Body and the CAISO Board of Governors in December.
