CAISO and the California Public Utilities Commission entered the new year trying to get ready for summer and avoid the shortfalls and rolling blackouts that plagued the state in August and September.
The CPUC on Friday proposed ordering the state’s three big investor-owned utilities — Pacific Gas and Electric, Southern California Edison and San Diego Gas & Electric — to contract for additional “incremental” capacity that can be ready this summer to meet heavy demand.
On Wednesday, CAISO held a meeting on the schedule and scope of a series of upcoming sessions to address “market enhancements for summer 2021 readiness.” Substantive meetings are scheduled to begin this week, with topics that include export and load scheduling priorities and resource sufficiency in the ISO’s interstate Western Energy Imbalance Market.
In the first week of 2021, CAISO conducted three days of meetings on its Resource Adequacy Enhancements stakeholder initiative, which started in 2018 but took on new urgency after last summer’s energy emergencies.
The ISO and stakeholders weighed a final draft proposal on the first phase of RA enhancements and a six-time-revised straw proposal on the initiative’s second phase. Items under discussion include RA import requirements, activating storage resources and rules on planned generator outages.
CAISO’s Board of Governors is scheduled to vote on the phase-one changes in March and on phase two in May and September
The ISO proceedings address issues raised in the preliminary root-cause analysis of the blackouts on Aug. 14-15 that affected more than 1 million residents during a severe heat wave that encompassed the Western U.S. Shortages occurred as solar power waned in the evening and there was insufficient capacity to meet continued high demand from air conditioning.
The October preliminary analysis, and a subsequent report by CAISO’s Department of Market Monitoring, identified problems that included inadequate RA planning, forced outages at power plants, a lack of storage for solar and wind resources, transmission constraints, imports that did not materialize and exports that should not have occurred in strained conditions. (See CAISO Wasn’t Gamed in Blackouts, Watchdog Finds.)
“The most significant and actionable of these factors involve California’s resource adequacy program,” the DMM’s November report said. “To limit the potential for similar conditions in future years, system level resource adequacy requirements should be modified to ensure more capacity is available during net load peak hours,” as solar ramps down but demand stays high.
Supply is tightening across the West as coal and “older baseload” fossil-fuel and nuclear plants retire, CAISO staff members noted during an RA enhancements meeting Wednesday.
“Severe weather events have become more common and have impacted … several BAs at the same time, further tightening system conditions,” said Milos Bosanac, CAISO lead infrastructure and regulatory policy developer. Heat waves could continue to pummel the West in the future and limit imports, Bosanac said in his presentation.
To head off shortfalls, RA imports must be linked to specific generating resources in other states, he said. That is not the situation now. If supply is not connected to a physical source, “it poses a risk to supply not being committed to the CAISO when it matters most, when conditions are tight,” he said.
In addition, the ISO wants firm commitments from transmission owners to prioritize RA imports during times of tight supply. Transmission lines from the Pacific Northwest to California can become nearly maxed-out during heat waves, Bosanac noted.
Much of California’s import RA capacity comes from the Bonneville Power Administration over the California-Oregon AC intertie (COB) and the Nevada-Oregon Border DC Intertie (NOB), he said. Those interties will require the highest guarantee of transmission capacity, he said.
“Looking at particularly the COB and NOB interties, usually on those last legs of those interties … especially in the summer months, flows tend to reach or be very close to the limits of those path, Bosanac said. “[With] a higher likelihood of curtailment … it’s important that these deliveries be on the highest priority transmission service to minimize that risk of curtailment so that those imports can be delivered to the CAISO.”
During an RA meeting Thursday, Doug Boccignone, a principal at Flynn Resource Consultants representing the California Community Choice Association, said only five parties control half the transmission import capability on COB and NOB.
“The rights are really concentrated,” Boccignone said. “It makes me concerned that if California is dependent on imports from the Northwest to meet the resource adequacy requirements … there’s the potential for those parties that control those rights to be in a much different position than they are today.”
CAISO said there are 21 parties that hold transmission rights on the two interties. Bridget Sparks, infrastructure and regulatory policy developer, said the ISO’s analysis did not show a high risk for the entities to exert market power.
“If we think of the market as COB and NOB combined … there is a slight market concentration, [but] it’s nowhere near a monopolistic control,” Sparks said.
SPP’s Corporate Governance Committee last week approved nominations for several open positions on stakeholder groups. The nominations will go before the Board of Directors on Jan. 26 for final approval.
Members selected Sunflower Electric Power’s Al Tamimi and NextEra Energy’s Matt Pawlowski to fill contested open positions on the Finance Committee. Tamimi, a familiar face for years in SPP stakeholder meetings, will represent the transmission-owning (TO) sector and Pawlowski the transmission-using (TU) sector.
SPP’s Corporate Governance Committee hears from applicants for open committee positions. | SPP
The CGC also approved Oklahoma Gas & Electric’s Usha Turner as an investor-owned utility sector representative on the Members Committee. She replaces Greg McAuley, who left OG&E in December to return to his native Florida.
Turner, director of federal and regional policy for the utility, said she has absorbed McAuley’s RTO policy responsibilities into her existing role.
OGE Energy’s Scott Briggs and Arkansas Electric Cooperative’s Maria Bunting Smedley were recommended to fill positions on the Human Resources Committee representing the TO and TU sectors, respectively.
The CGC endorsed Northeast Texas Electric Cooperative CFO Caleb Head as chair of the Credit Practices Working Group.
SPP staff assured stakeholders they are looking into the causes of congestion around the MISO seam following a third straight month of record market-to-market (M2M) settlements.
SPP incurred $22.87 million from MISO in M2M settlements during November, a 56.3% increase from the $14.63 million in October. That mark more than doubled the previous high. (See Record $14.63M M2M Settlement for SPP, MISO.)
“Some of it [the spike in M2M settlements] is a ‘perfect storm’ scenario,” SPP’s Scott Brown told the Seams Steering Committee on Friday. “It was a combination of significant outages in certain areas, increased wind and a low mix of [firm-flow] entitlements [FFEs] in the areas where there is an increased use of the system along the seam.”
FFEs are allocated property rights to the RTOs, with each RTO calculating its real-time usage. The grid operators exchange M2M settlements for redispatch based on the non-monitoring RTO’s market flow in relation to its FFE.
“In general, one of the major causes for these M2M events and settlements is when the wind is high in both SPP and MISO,” said Clint Savoy, the SSC’s staff secretary.
Market-to-market settlements between SPP and MISO have set records for three straight months. | SPP
Ten permanent flowgates were binding for 525 hours, resulting in $11.77 million in M2M settlements, while 36 temporary flowgates bound for 1,612 hours, accounting for $11.1 million in payments.
Pointing to a trouble spot on the western side of the Nebraska-Iowa border, SPP Director of System Planning Casey Cathey reminded the committee that the grid operator identified a potential interregional transmission project in the area last year. It failed to meet MISO’s benefit-to-cost ratio threshold.
The 161-kV Raun-Tekamah permanent flowgate in eastern Nebraska accounted for almost $5 million in settlements to SPP alone, binding for 198 hours. Cathey said the Raun area is one of the highest priorities for SPP’s 2021 Integrated Transmission Planning assessment and the joint transmission study with MISO. (See MISO, SPP Stakeholders Applaud New Joint Study.)
“You look at the locations of the [generator interconnection] queue for SPP and the locations of the queue for MISO, and intuitively, without running any studies, you understand that unless we build bigger pipes — more transmission — [the Raun area’s congestion] is going to continue,” Cathey said.
“It’s not going to drop down, but I don’t know that the magnitude will be as high for a sustainable period,” he said. “There’s nothing in the works that alleviates this congested area. The trend will continue, just not to that magnitude.”
Cathey hopes the Strategic and Creative Re-engineering of Integrated Planning Team (SCRIPT), which has been tasked with reviewing and possibly combining SPP’s seven different transmission planning processes, will be able to relieve some of the pressures on the grid. (See “SPC Takes Look at Tx Planning,” SPP Briefs: Week of Aug. 31, 2020.)
“All these different business functions operate on different timelines and for different reasons. I’m not saying it’s broken, but this is what happens,” he said. “That’s the big part of what we’re trying to do with SCRIPT and consolidation.”
SPP has piled up $140.23 million in settlements from MISO since the two grid operators began the M2M process. Under the process, the monitoring and non-monitoring RTOs manage M2M constraints by exchanging shadow prices and other information to ensure that the RTO with the more economic dispatch addresses flows. The shadow price indicates the marginal value of an additional increment of relief on a congested constraint in reducing the total production costs.
M2M settlements have been in SPP’s favor 13 of the last 14 months and 52 times in 69 months since the process began in 2015. The top 10 constrained flowgates since the process began all have MISO paying SPP, staff said.
SSC Supports Affected-system Studies
The SSC told staff it would approve a proposal to revise the queue priority for transmission projects in affected-systems studies with seams neighbors, but only if they are applied to all neighboring grid operators.
A majority of stakeholders in a snap poll during Friday’s webinar said they would support Associated Electric Cooperative Inc.’s (AECI) proposal to establish a relative queue priority for study requests between the cooperative and AECI.
Only three of the 15 respondents to the poll said they would not support AECI’s proposal.
Staff are also gathering feedback from the Generation Interconnection Users Forum.
SPP uses the studies to determine non-jurisdictional and neighboring interconnection requests’ effects on its transmission system. The studies take into account interconnection requests on neighboring grids, including those of AECI, MISO, Minnkota Power Cooperative and NorthWestern Energy.
PJM and state officials seeking the most efficient way to integrate more than 12 GW of offshore wind generation have identified six scenarios for analysis in a study expected to produce results after mid-2021, the RTO told the Transmission Expansion Advisory Committee Wednesday.
The Offshore Transmission Study Group, which was created in response to a request by the Organization of PJM States Inc., developed the scenarios during five meetings since October 2020, Matthew Bernstein, PJM analyst for state policy solutions, told the TEAC. PJM staff also held one-on-one meetings with individual states, he said.
The scenarios will consider the magnitude, points of interconnection and timing of OSW injections for both announced and planned projects. The analyses will also consider the impact of generator deactivations and states’ clean energy goals, Bernstein said.
PJM may study additional scenarios based on the initial study findings and feedback from the states, he continued.
Within PJM, New Jersey (6.4 GW), Virginia (5.2 GW) and Maryland (1.2 GW) have announced OSW goals.
Bernstein said the analyses are directed at upgrades that will be necessary for the onshore system and will not consider offshore infrastructure such as a mesh network grid or collector stations.
“We’re looking at what these different offshore wind injections are going to do to the onshore system,” Bernstein said. “We’re still in the process of developing these scenarios and have not begun the actual analysis itself.”
Theodore Paradise, senior vice president of transmission strategy for Anbaric Development Partners, asked how the modeling efforts relate to the New Jersey Board of Public Utilities’ request in November that PJM integrate the state’s OSW goals into the RTO’s Regional Transmission Expansion Plan. New Jersey’s request made it the first state to embrace the state agreement approach under FERC Order 1000, which allows states to fund transmission projects needed to meet public policy needs.
PJM expects to open a competitive solicitation window including New Jersey’s request in the first quarter of 2021. (See NJ Asks PJM to Seek Bids for OSW Tx.)
Bernstein said the assumptions and analysis of the onshore component developed in response to New Jersey’s request will be incorporated into the study.
“You can look at this as incorporating the other states’ offshore wind objectives around what we’ve already done with New Jersey as part of a larger collaborative effort,” he said.
Sharon Segner, vice president of LS Power, said the goal of having a more active public policy planning process is “really encouraging.” Segner asked if PJM anticipates the scenarios will be made public before the results are produced.
Bernstein said it is “too early” to tell what will be made available to stakeholders and when. He said the scenarios will be described in the final report.
Segner said PJM’s presentation made it seem as if the RTO was attempting to identify regional transmission solutions to accommodate states’ OSW goals. She said typically in these types of scenarios, each would be put into the planning windows and the parties would be developing and proposing regional transmission solutions.
“I’m not completely understanding how this fits into the process,” Segner said. “It sounds like an interesting development, but I’m just trying to put the pieces together.”
Mark Sims, PJM’s manager of infrastructure coordination, said Segner was jumping a bit too far ahead in the process. Sims said there’s still education that needs to be completed on the issue before PJM decides how to implement the potential solutions a state decides to move forward with.
Sims said the goal is to identify what the states want to accomplish, develop assumptions, run the studies and give information on possible results.
“If any state or group of states decides to move forward, we envision that’s when the competitive process would play a role,” he said.
More than four months after Hurricane Laura’s landfall in its South region, MISO is questioning whether its value-of-lost load (VOLL) should be used to price energy during extraordinary weather events.
During a Market Subcommittee teleconference last week, Director of Market Design Kevin Vannoy solicited stakeholder opinions as to whether the RTO’s $3,500/MWh VOLL pricing is appropriate during force majeure events.
“What should the market reflect when we take actions to manage transmission, balance the system, balance the region?” Vannoy asked stakeholders during the call Jan. 7.
Vannoy also asked whether MISO’s pricing logic for dead buses should be reviewed. Stakeholders have until Jan. 28 to submit their feedback.
MISO’s Independent Market Monitor continued its call for a retroactive pricing change for the dead buses priced at VOLL in Hurricane Laura’s wake. (See “Laura Pricing in Question,” MISO Monitor Reviews Blustery Fall.)
The Monitor’s David Patton said MISO’s after-the-fact settlements produced $90 million in balancing congestion costs, which showed up on customer bills as uplift charges. He said approximately $10 million of the cost was because of dead-bus pricing at $3,500/MWh in Louisiana’s Lake Charles area, where Hurricane Laura destroyed enough distribution and transmission lines to effectively create a dead zone.
“We’re concerned about some of these settlements applying the VOLL pricing to dead buses,” Patton said. “Load is not being served because the system effectively doesn’t exist to serve it. The load is not being served because we lack sufficient resources to serve it. The load is not being served because the system is demolished.”
He went on to say MISO’s VOLL settlements near Lake Charles for Aug. 27 are “not consistent with how MISO settles dead buses in the day-ahead market, which would price such a load zone at basically $20/MWh.”
MISO’s day-ahead dead-bus pricing relies on prices from nearby live buses.
“That’s what the Tariff calls for,” Patton said.
Vannoy said an evaluation of MISO’s pricing practices at dead buses will likely be rolled into MISO’s existing scarcity pricing reconsideration, which was already poised to bring changes to the VOLL and operating reserve demand curve. (See MISO Revisits Scarcity Pricing Rethink.)
The grid operator is hosting a workshop on the scarcity price effort on Jan. 22.
Market participants impacted by Hurricane Laura had until December to initiate a settlement dispute with MISO. The RTO is now in confidential discussions over the disputes.
Customized Energy Solutions’ Ted Kuhn asked whether MISO should pause collections on some Hurricane Laura-induced settlements until it determines whether VOLL pricing should apply to the event.
“What if we did that rather than everyone having to scramble and file legal briefs, so their rights are protected?” he asked.
Vannoy said he wouldn’t comment on the Aug. 27 retroactive settlements. “I think the goal here is to look at future modifications and future event applications,” he explained.
Laura Rauch, MISO’s director of settlements, said if settlement changes are granted after dispute resolution, other affected market participants will be notified and invited to final discussions to hear the outcome.
“The Tariff is very clear that changes to historic settlements require disputes submitted in a timely manner,” Rauch said. “To the extent that we make a determination that the historic settlements need modification, we’ll review that for all impacted market participants.”
MISO Corporate Counsel Jacob Krouse added that affected market participants can challenge the RTO’s determinations even if they haven’t filed dispute resolutions.
Patton said the hurricane’s devastation might have been minimized if MISO had specifically assigned capacity to load.
“The South is one of the worst problems in this regard. In the Midwest region, we don’t have as big a problem with this disconnect,” he said, adding that load pockets in Louisiana and Texas are limited by transmission constraints.
“The capacity values do not correspond to the load pockets. It’s all merged together,” he said. “This might not have happened … if we defined our loads better.”
ISO-NE’s Board of Directors deals with turnover every year, but two board members will retire in both 2021 and 2022. According to materials presented to the NEPOOL Participants Committee last week, these departures will create expertise and leadership gaps on the RTO’s board.
Board Chair Kathleen Abernathy gave a presentation — originally delivered to the Joint Nominating Committee (JNC) in December — on ISO-NE’s “roadmap” for future director appointments.
Abernathy (2021) is one of the four retiring directors in the next two years, along with Philip Shapiro (2021), Barney Rush (2022) and Vickie VanZandt (2022). Rush is chair of the board’s Markets Committee and an electricity markets expert, which makes it critical to replace with him, according to Abernathy’s presentation, as New England’s future grid priorities rely on “innovative, reliable, well functioning markets.” The region also depends on having a robust transmission network, and VanZandt is a national transmission expert who has planned, built and operated bulk power transmission systems.
The retirements of Abernathy and VanZandt additionally result in the board’s loss of two of its three female directors. “Board diversity has been a core tenet of ISO New England and has been present since its inception,” Abernathy said. “We are focused on ensuring we have the necessary range of technical and life skills to provide proper oversight as we address the issues of reliability and the clean-energy transition.”
Improving Nomination Transparency
ISO-NE General Counsel Maria Gulluni and NEPOOL Secretary David Doot followed Abernathy with a general overview of the JNC’s process for selecting candidates, as well as options to improve its transparency.
The JNC comprises seven board members, NEPOOL’s six sector leaders and a representative of the New England Conference of Public Utilities Commissioners (NECPUC). With input from the board, state representatives and market participants, the committee identifies the types of expertise that ensure ISO-NE has “sufficient knowledge and expertise to act as the RTO for New England,” according to the Participants Agreement (PA) between ISO-NE and NEPOOL.
JNC members sign a nondisclosure agreement that prohibits sharing nonpublic information. The NDA is primarily intended to protect the identity of unsuccessful candidates, but it does not include, for example, role descriptions and search criteria.
Transparency of the search process became an issue in September, when former Maine Public Utilities Commission Chair Mark Vannoy was elected to the board on a slate with incumbent Directors Brook Colangelo and Roberto Denis. The slate was approved by the RTO’s board and endorsed by the PC.
Although the JNC approved the slate unanimously, stakeholders at the time told RTO Insider the leaders of NEPOOL’s End User and Alternative Resources sectors attempted to withdraw their support for Vannoy after hearing negative feedback from their sector members. The sector leaders were not permitted to identify Vannoy until after the JNC voted under RTO rules. (See Consumer Advocates Upset with Pick for ISO-NE Board.)
Gulluni and Doot said that the JGC could improve transparency through more “robust reporting” of, for example, what happened at its meetings. But other changes may require amendments to the PA and need both ISO-NE and NEPOOL approval. NEPOOL needs a 70% vote for endorsement, and FERC must additionally review and approve any changes. Any renegotiation of the PA may also open it to unrelated issues raised by participants, states or the RTO, they said.
Energy Market Value Rises
ISO-NE COO Vamsi Chadalavada reported the energy market value for December was $426 million (through Dec. 29), up $181 million from November and down $42 million from the same month last year.
Natural gas prices were 120% higher than November average values, which pushed the average real-time hub LMPs to $42.04/MWh, up 71% from the prior month. Average natural gas prices and real-time hub LMPs were down 7.5% and 1.7%, respectively, from the same period last year.
Average day-ahead cleared physical energy during the peak hours as a percentage of the forecasted load was 98.5% during December, down from 99.6% during November, with the minimum value for the month of 93.5% posted Dec. 5.
Daily uplift, or net commitment period compensation (NCPC) payments, in December totaled $3.4 million over the period, up $1.4 million from November and down $1.3 million from December 2019. NCPC payments were 0.8% of the energy market value.
New Jersey’s new solar power incentives program should use competitive solicitations to minimize costs and differentiate between project types and locations to ensure “a robust and diverse fleet,” consultants recommended to the Board of Public Utilities on Friday.
The BPU commissioned The Cadmus Group to produce the “New Jersey Solar Transition Final Capstone Report” in response to the Clean Energy Act of 2018 (AB-3723), which required the state to replace the Solar Renewable Energy Certificate (SREC) market with a lower-cost program to encourage solar development.
Ariane Benrey, program administrator, presented the report at a meeting Friday, where the BPU also approved two measures related to the state’s offshore wind projects and Public Service Electric and Gas’ (PSE&G) $778 million smart meter deployment (EO18101115). PSE&G will be the second utility in the state to install smart meters, following Rockland Electric. Smart meter proposals by Jersey Central Power & Light and Atlantic City Electric are pending before the BPU.
State of Transition
The Clean Energy Act required that the SREC program close once solar totals 5.1% of electricity sales, a threshold the state hit in April 2020. (See Solar Subsidy Program Ending in New Jersey.)
An interim, “transition” program took effect in May for projects registered with the state by the 5.1% milestone date but not yet operational, as well as projects registering after the milestone but before implementation of the successor program that is the subject of the capstone report.
Renewable energy credits (RECs) under the transition program range between $91.20 and $152/MWh, compared with an average of $214/MWh during the last five years of the SREC program, according to the state.
Under New Jersey’s 2019 Energy Master Plan, in-state solar would comprise 34% of the state’s electric generation by 2050 as part of Gov. Phil Murphy’s midcentury goal of 100% “clean energy.” The plan seeks 5.2 GW of in-state solar by 2025, 12.2 GW by 2030 and 32 GW by 2050.
The state registered about 3,476 MW of solar under the SREC program and estimates about 700 MW will be added under the transitional incentive, leaving about 8,020 MW to be filled under the successor program by 2030.
For the successor program, Cadmus recommended the BPU implement a fixed-incentive program, similar to the transition incentive, to “provide strong certainty, business visibility and especially ‘finance-ability.’” It said the fixed incentive would complement net metering incentives in the near term and could evolve into a “total compensation” program “to reflect more holistically the value of these projects to the market, grid and environment.”
It said the new program should ensure flexibility through a timetable of re-evaluations and potential revisions “while providing the industry with enough line-of-sight to enable long-term investment.”
The largest solar projects should receive incentives based on competitive solicitations, with administratively set incentives for smaller projects, Cadmus said. “This will enable market price discovery while establishing minimum incentive levels.”
The consultants also urged the use of megawatt-based targets that consider historical trends and segments that may have been underutilized in the past, such as commercial rooftops, solar carports and front-of-the-meter “grid supply” projects.
They also recommended differentiating between project customer classes, installation types, locations and technologies, noting that “variations in tariffs and interconnection costs across electric distribution company service territories, along with differences in construction costs between solar installation types, can have significant impacts on overall project economics.”
The BPU should order a study on the state’s total feasible capacity for solar, Cadmus added. “New Jersey was an early leader in solar in the United States and has developed a robust market. That relatively long history of success in installations, however, suggests that the developer community has likely spent significant time prospecting for optimal projects and that some of the best opportunities for solar may have been taken already for various project types or otherwise did not work under existing market structures,” it said.
The Six Flags Great Adventure amusement park in Jackson, N.J., is mostly powered by a 23.5-MW solar project. | Six Flags
‘Total Compensation’ vs. Fixed Incentives
The “total compensation” incentive, like the Solar Massachusetts Renewable Target (SMART) program, acts like a contract for differences between the value of energy and the total compensation paid.
One advantage of the SMART program, Cadmus said, is that it includes adders and subtractors to encourage a diversity of project types and discourage large-scale, ground-mounted projects in undeveloped spaces. Projects on landfills, parking lots and in “dual-use” agriculture — growing crops such as wheat, potatoes and beans under solar canopies — receive adders.
But the consultants said the SMART approach is also complex and can result in unintended consequences, with larger, front-of-the-meter (FTM) projects crowding out behind-the-meter (BTM) systems. As of September 2019, 60% of the large building-mounted and canopy systems in the Massachusetts program were installed as standalone projects instead of BTM systems. “BTM systems provide several benefits, including more economic opportunities to pair with battery storage and reduce on-site demand … reducing interconnection costs and utility work associated with creating new standalone service,” Cadmus said. “Amending regulations to correct this flaw has been proposed as part of the [current] review of the program.”
Fixed incentives offer set prices that are paid in addition to any revenues the facility may earn from electricity sales and costs avoided through reduced energy consumption. The programs, such as Connecticut’s Zero Emissions Renewable Energy Credit (ZREC), typically require transmission and distribution utilities to purchase RECs from solar electricity generators through long-term contracts.
Providing solar developers a reliable revenue source over a long period reduces lenders’ risks and the cost of capital. The simplicity of fixed incentives also reduces transaction costs.
But regulators can have problems determining the appropriate price level, Cadmus said. “If the price level is set too high, the market will accelerate too quickly, solar developers will capture excess profit and undesirable electricity rate increases may occur. Conversely, if the price level is set too low, the market will grow too slowly or not at all.”
And because it involves long-term contracts, fixed incentives lack market-responsiveness, although “program design can help mitigate some of these potential disadvantages,” Cadmus said.
The consultants proposed minimum 15-year incentives in the PSE&G territory, ranging from a low of $55/MWh for a community solar ground-based project to a high of $180/MWh for a commercial carport system with third-party ownership. Minimum incentives for residential rooftop systems were estimated at $95/MWh.
The 127-page report followed more than a dozen stakeholder meetings and a series of focus groups since January 2019.
With the release of the report, BPU staff recommended the board direct further stakeholder proceedings on developing the successor program. “The capstone report and underlying analysis should be considered as guidance only and … does not bind the board in any way on the development of a successor program or related incentives,” Program Administrator Benrey said.
BPU President Joseph Fiordaliso said the acceptance of the report was an “important step” in the development of a replacement for the SREC program, whose development in 2004 led to heated debates over its price tag.
He said he welcomed feedback on the report. “We [the BPU] don’t have all the answers,” Fiordaliso said. “Collectively, hopefully, we will.”
In a related matter, the board also approved a waiver of a requirement that applicants to the Community Solar Energy Pilot Program provide an interconnection upgrade cost assessment (QO20080556). The waiver applies only to projects proposed in the PSE&G service territory for program year 2, applications for which are due by Feb. 5. PSE&G informed BPU staff that it is unable to perform the requested interconnection cost assessments because of staffing constraints and an increase in interconnection study requests. In lieu of the assessments, applicants can submit a letter explaining why interconnection of the proposed project is likely to feasible.
Offshore Wind
The BPU on Friday also approved a solicitation for a consultant to help BPU staff work with PJM on transmission development for its offshore wind projects.
The board in November asked PJM to conduct a competitive solicitation for upgrades to connect 6,400 MW of offshore wind to the regional grid under its NJ Asks PJM to Seek Bids for OSW Tx.)
Jim Ferris, bureau chief for new technology at the BPU, said PJM is incorporating the state’s request into the 2021 Regional Transmission Expansion Plan (RTEP) and is working with BPU and PJM staff and transmission developers to solicit options for the board’s consideration.
Ferris said the consultant will be asked to assist staff in the preparation and review of documents required for the RTEP process, engage with stakeholders, aid in an independent review of all submitted proposals and provide recommendations for the best transmission solutions resulting from the process.
Fiordaliso said the BPU lacks staff with the expertise to manage the complicated RTEP process. “If we don’t have people who are well versed in certain subject areas, the learning curve is steep,” Fiordaliso said.
Commissioner Dianne Solomon said it made sense to bring in outside expertise. “We’re wading into waters that really need some specialized background and information,” Solomon said. “Far be it from me to tell PJM what to do, but I hope they too will engage consultants in areas in the past where they’ve said they don’t have sufficient staff to address some of these issues.”
The board also unanimously approved a memorandum of understanding to provide the South Jersey Port Corp. with $1.8 million in funds generated by the Societal Benefits Charge “to support the development” of a facility to manufacture monopiles for offshore wind turbines at the Paulsboro Marine Terminal in Gloucester County (QO20120770).
Kelly Mooij, director of the BPU’s Division of Clean Energy, said developing an OSW supply chain with manufacturing in New Jersey will produce economic benefits and help reduce the cost of reaching the state’s clean energy goals.
Gov. Murphy announced the $250 million Port of Paulsboro project last month, saying it would be the largest industrial offshore wind investment in the U.S. and create more than 500 jobs at full buildout. Construction will break ground this month, with production beginning in 2023. EEW Group, a German monopile manufacturer, will operate the facility.
Commissioner Bob Gordon asked if $1.8 million was enough for the facility. He said he has been a supporter of the idea of developing a supply chain for OSW in New Jersey but wondered if the BPU knows what the funds will be used for.
“It just seems to me that $1.8 million is not a make-or-break expenditure and is almost an afterthought,” Gordon said.
Fiordaliso said the funds will be used for infrastructure on the site.
MISO said it plans to subdivide its annual capacity auction by seasons so it can better manage budding reliability risks brought on by renewables’ growing share of the resource mix.
Jessica Harrison, the RTO’s senior director of research and development, said leadership is leaning toward a four-season capacity auction, though two or three seasons is still possible. (See MISO Nearing Decision on Seasonal Capacity Auction.)
“There’s still a range of preferences on the number of seasons,” Harrison said during a Resource Adequacy Subcommittee (RASC) meeting Jan. 6.
The grid operator intends to conduct the independent seasonal auctions simultaneously.
“It’s a proposal we’ll put forward and then monitor the need to hold more auctions in a year,” Harrison explained.
MISO’s decision will bring manifold implications and have it crunching separate planning reserve margins and local clearing requirements based on seasons.
The RTO will conduct the loss-of-load expectation (LOLE) study on a seasonal basis to determine how risk is spread across the year. Senior Manager of Resource Adequacy Coordination Lynn Hecker said it will assign seasonal reliability requirements based on the study results.
Stakeholders asked what MISO will do if it can’t detect loss-of-load risk within a particular season.
“That’s a question we’re discussing,” Hecker said. She said staff is considering assigning seasons with a 0.01 LOLE risk target to determine resource adequacy requirements for those seasons.
“The idea that resources are fully available year-round with only some small outages is frankly being tested by the industry,” Harrison said. “We are getting requests to operate resources during [only] portions of the year.”
MISO will impose a must-offer requirement on planning resources only for the seasons they clear in the capacity auctions.
Stakeholders asked whether the RTO will establish separate seasonal capacity import and export limits for its 10 local resource zones.
“That’s another design element to consider that we haven’t spent a lot of time on yet,” Hecker said.
Some attendees urged MISO to make sure its model can handle multiple reserve margin requirements and that the new seasonal requirements work with state integrated resource planning.
Minimum Capacity Requirement for LSEs
The grid operator also proposed a minimum capacity requirement for load-serving entities participating in the seasonal auctions. The LSEs would be expected to procure at least half of their planning reserve margin requirement before the auctions.
Entities could be faced with a “penalty mechanism” for not meeting the 50% requirement, MISO said.
The proposal seemed unpopular with stakeholders. Several appeared taken aback at the rule, with some saying it was only mentioned in passing in stakeholder meetings before being unveiled.
MISO’s Independent Market Monitor also expressed its displeasure.
“We don’t support this 50% requirement. We think it’s a bad idea,” Monitor staffer Michael Chiasson said.
But a few stakeholders said the requirement will end an overreliance on the MISO capacity auction and the free ridership some utilities enjoy.
“This might be scaled to the size of the utility,” Customized Energy Solutions’ Ted Kuhn suggested, adding, “If you’re a 10-MW utility, I don’t think anyone cares where you procure. But if you’re DTE Energy, it’s a different story.”
Minnesota Public Utilities Commission staff member Hwikwon Ham said the requirement might tread on states’ jurisdiction in RA matters.
“MISO can limit its auction to an LSE, but it cannot tell an LSE what to procure,” he said.
Staff said they would reconsider language around the requirement.
Availability-based Accreditation, Too
The grid operator will unsurprisingly pivot to a seasonal capacity accreditation for planning resources, matching the capacity auction. It is also proposing to adopt the Monitor’s recommendation to pivot to an accreditation based on resource availability.
While MISO will adopt an availability-based resource accreditation (ACAP), it will still establish seasonal reliability requirements on an unforced capacity (UCAP) basis. It said it will use a conversion calculation to align the ACAP-based capacity accreditation with UCAP-based planning reserve margins.
The Monitor’s David Patton pressed MISO to rework its capacity accreditation, pitching an accreditation that relies on the system’s megawatts on hand during the operating year’s tightest hours. MISO leadership said it will adopt some — but not all — design elements from the Monitor’s availability-based accreditation recommendation.
Patton said resources that have long startup times and expensive startup costs aren’t able to provide the reliability that fast-ramping and online resources will. He said that currently, MISO’s market doesn’t properly value more agile resources and suggested the RTO could adopt a “sliding scale” of capacity accreditation based on a rolling, three-year average of the resources’ response time.
“The uncertainties around the output of intermittent resources are going to expand the tightest hours of the year beyond those that are easy to see coming,” Patton warned.
He argued that it’s becoming more important for conventional resources to prove availability as the fleet adds more renewable energy. However, he said conventional generation’s availability is shrinking and its undeclared outages are becoming commonplace.
“In theory,” Patton said, “compared to an energy-only market, capacity payments should reflect elements of shortage pricing,” where the units that help most are appropriately compensated.
He said MISO’s current UCAP-based accreditation overlooks facility derates and unreported outages.
“A lot of the lost megawatts come from outages that are not reported, so they wouldn’t be reflected in UCAP,” he said.
Patton said he also took issue with MISO’s current construct that effectively assumes no planned outages happen during summer peak conditions. He said the assumption does a disservice to reality.
“When you look, we have 10-plus GW of outages in the hottest conditions of the year. You wonder how they occur because we seemingly have enough capacity,” he said.
Some stakeholders complained about the suddenness of MISO’s pivot to an availability-based accreditation.
“I feel like our conversations [in] spring, summer have been grounded in availability. That’s exactly what we’ve been trying to get at all year,” MISO RASC liaison Scott Wright said.
Harrison and Hecker asked for written stakeholder opinions and said more details and analyses will be shared in future RASC meetings.
Mississippi Public Service Commission consultant Bill Booth asked whether MISO hadn’t already taken care of some of the availability problems with 2019’s stricter outage-scheduling rules and its recently approved short-term reserve product.
Patton responded by drawing a distinction between energy and capacity and said capacity revenues should naturally decline when “more of the heavy lifting” of providing reserves is handled by shortage products.
Wright said MISO needs to employ tactics in both its operating and planning horizons to address the footprint’s changing risk profile.
“We’ve got to be on all sides of it,” Wright said, adding that an effort to more accurately measure capacity is a valuable planning tool.
CEO John Bear warned members early last year that MISO is pivoting from on a summer loss-of-load emphasis to an “all-hours-matter focus” because of the generation fleet’s “increasingly distributed and intermittent nature.”
The South Fork Wind Project will have negligible to moderate environmental impacts from construction, operation and decommissioning, according to a draft environmental impact statement (DEIS) issued by the Bureau of Ocean Energy Management last week.
The 132-MW offshore wind joint venture between Ørsted and Eversource Energy would consist of up to 15 wind turbines with a capacity of 6 to 12 MW each located about 30 nautical miles east of Montauk Point, N.Y.
BOEM will hold virtual public meetings on Feb. 9, 11, and 16 where it will accept comments submitted or postmarked no later than Feb. 22 before completing the EIS.
South Fork Wind Farm project map | BOEM
Environmental Impacts
The DEIS categorizes potential adverse or beneficial impacts as negligible, minor, moderate or major, comparing impacts from alternative scenarios and summarizing key findings for the project’s proposed Construction and Operations Plan (COP).
The developers proposed an offshore substation within the lease area, with associated export cables subject to applicable mitigation measures — turbines laid out in a uniform east–west and north–south grid with 1-square-nautical-mile spacing between turbines and diagonal transit lanes at least 0.6 nautical miles wide — spacing agreed on by all OSW developers last summer and recommended by the U.S. Coast Guard. (See Developers Seek 1-Mile Spacing for Vineyard Wind.)
“Impacts associated with the other action alternatives are generally similar to those described for the proposed action,” BOEM said.
The agency outlined four possible regulatory choices:
“no action,” the equivalent to rejecting the project outright;
approving it as proposed;
an alternative layout with a 4-nautical-mile-wide vessel transit lane as proposed by the Responsible Offshore Development Association; or
a “fisheries habitat impact minimization” alternative that would exclude certain turbines and associated cable locations if micro-siting is not possible.
It said it incurred costs of $1.8 million in drafting the EIS, which assesses impacts on air and water quality, bats and birds; marine mammals and sea turtles; benthic habitat; land and wetlands; fisheries and tourism; cultural resources; employment; social justice; and federal income.
Regarding marine mammals, “some individual whales or seals could suffer temporary or permanent hearing injury; these adverse effects would be moderate for affected individual marine mammals [and] overall cumulative adverse impacts would be moderate,” the report stated.
Commercial fisheries and for-hire recreation fishing might suffer moderate adverse effects from increased port congestion and reduced fishing opportunity during construction. Fishing gear could be lost or damaged, and catches might decline if target species avoid construction areas. The “reef effect” of turbine foundations and associated scour protection would have minor beneficial impacts to recreational fisheries, depending on the extent to which the foundations enhance fishing opportunities. Overall cumulative adverse impacts would be moderate, it said.
The report foresees that “overall cumulative adverse impacts [on navigation and vessel traffic] would be moderate.”
It also projects overall cumulative impacts to employment, federal revenue and income to be minor.
On social justice issues, the DEIS sees “minor to moderate adverse impacts to minority or low-income populations and tribes from the project,” with moderate cumulative adverse impacts overall.
Land Ahoy!
BOEM last summer held a series of public hearings on its supplemental environmental impact statement (SEIS) for the Vineyard Wind project in federal waters south of Massachusetts. It was to issue its final EIS in December and make a final decision by January. Vineyard Wind is a joint venture between Copenhagen Infrastructure Partners and Avangrid Renewables.
However, early in December Vineyard Wind announced a supplier agreement with General Electric for 13-MW Haliade-X turbines, supplanting a previous deal with MHI Vestas and delaying final approval of the project for some months. (See Offshore Wind Looks at Crowded Future in New England.)
The preferred landfall site for the South Fork export cable (SFEC Route A) is at the parking lot at the southern end of Beach Lane, with a new terrestrial cable to be buried under paved roadways and the Long Island Railroad right-of-way to the interconnection facility.
South Fork Wind Farm export cable route A is proposed to land at Beach Lane, East Hampton. | BOEM
A survey identified three archaeological sites or historic properties within or adjacent to proposed alternative landing sites and potential routes for the onshore cable, which are no longer being considered for the project and therefore will not be affected, BOEM said.
There are no previously reported archaeological sites along Beach Lane, and none were identified during shovel testing there, at the Hither Hills landing site or within the proposed onshore substation sites.
The East Hampton Town Board will hear public comments on its agreement to allow the export cable to come ashore under Beach Lane or elsewhere on Jan. 12 and will then vote on the contract.
Bonneville Power Administration acting administrator and CEO John Hairston will officially assume the top job at the federal power marketing agency, the U.S. Department of Energy said Thursday.
Like his predecessor, Hairston rose through the ranks during a long career at BPA, most recently working as chief operating officer and chief administrative officer.
“John has made a lasting and significant impact on the Bonneville Power Administration over the past 29 years, and I am proud to announce him as the new administrator,” Energy Secretary Dan Brouillette said in a statement. “BPA is an important provider of reliable, renewable hydroelectric and clean nuclear power to the Pacific Northwest, and John’s commitment to serve BPA will support the Department’s critical energy mission.”
“I am truly honored and humbled by the opportunity to lead Bonneville during this dynamic time, when we are not only challenged to meet the pressing needs of our customers but must also position BPA to be their long-term provider of choice for low-cost, reliable and responsible carbon-free power,” Hairston said.
At a November webinar hosted by the Committee for Regional Electric Power Cooperation (CREPC) on “Diverse Energy Leadership in the West,” Hairston said BPA has undertaken an “aggressive” program of cultural transformation. (See Industry Leaders Talk Diversity in the West.)
BPA Administrator and CEO John Hairston | CREPC-WIRAB
“Part of that change was my ascent into the front office, which I think allowed … for folks to kind of see someone different in the front office and see themselves and maybe aspects of their culture reflected in the leadership,” said Hairston, who is African American.
Hairston takes over at BPA as the Pacific Northwest and broader West face looming capacity shortages, a fact made evident last August when a persistent heat wave forced CAISO to initiate rolling blackouts while other balancing authorities teetered on the brink of doing the same.
“For us and our customers, resource adequacy is a pretty big deal,” Hairston said during the CREPC webinar.
He said the agency must find ways to work with its Western neighbors on RA; “for others to go through blackouts means [the region is] not cooperating.”
The Northwest Power Pool’s effort to create a formal RA program is a “really great opportunity” to collaborate with other regional utilities, he said. (See NWPP RA Effort Quickly Ramping Up.)
Hairston will also shepherd BPA through the final stages of a complex entry process into CAISO’s Western Energy Imbalance Market (EIM). BPA has a go-live date targeted for March 2022, pending the outcome of an extended stakeholder proceeding.
In November, Hairston said the EIM offers resource diversity and the ability to offset risk. It also provides BPA the opportunity to utilize its extensive hydroelectric system. Regarding the expansion of the EIM into a full RTO, he said “the governance issue is a challenge for us in the Pacific Northwest.”
Hairston’s appointment received praise from key stakeholders in the region.
“We are thrilled by the naming of John Hairston, and look forward to his continued leadership at the helm of BPA,” environmental group Northwest RiverPartners tweeted.
“Looking forward to working with John on building out our region’s clean energy future,” clean energy advocate Renewable Northwest tweeted.
