The Arizona Corporation Commission on Wednesday voted to advance energy rules that would require the state’s electric utilities to cut carbon emissions 50% by 2032 and 100% by 2070.
In a 3-2 vote, Commissioners Jim O’Connor (R), Anna Tovar (D) and Sandra Kennedy (D) voted in favor of the rules. Chairwoman Lea Marquez Peterson and Commissioner Justin Olson, both Republicans, were opposed.
The carbon-reduction targets in the approved rules are less ambitious than those the commission considered earlier this month, which would have required electric utilities to reduce carbon emissions by 50% by 2032, 75% by 2040 and 100% by 2050. That proposal died due to lack of support.
Because the proposed energy rules were substantially amended, the revised rules will go through the formal rulemaking process. The comment period will open on July 9. A final vote is expected in the fall.
Tovar and O’Connor jointly proposed an amendment, which the commission adopted on Wednesday, giving utilities until 2070 to reach 100% carbon-free emissions. Interim standards include a 50% reduction by 2032, a 65% reduction by 2040, an 80% reduction by 2050, and a 95% reduction by 2060.
The Arizona Corporation Commission is advancing a rule making that would get the state’s utilities to net zero carbon emissions by 2070. | Arizona Corporation Commission
The rules also include requirements for energy efficiency and energy storage.
Sandy Bahr, chapter director for Sierra Club’s Grand Canyon Chapter, said the group was pleased that the energy rules are moving forward.
“Early action on reducing carbon emissions to address our climate crisis is critical,” Bahr said in a release. “These rules include an important carbon standard to reduce emissions 50% by 2032, as well as standards for energy efficiency and distributed storage that will help our state move forward on reducing emissions.”
Western Resource Advocates said in a release that the commission’s vote “sets (a) promising interim target but falls far short on overall climate action.”
“The 2070 date for reaching carbon-free electricity falls far short of meeting the timeframe that scientists tell us is needed to avoid the worst impacts of climate change,” said Adam Stafford, Western Resource Advocates’ senior staff attorney in Phoenix. “A more urgent timeline of no later than 2050 for eliminating the harmful fossil fuel emissions that cause climate change is of critical importance.”
The update to the state’s energy rules has been in the works for nearly three years.
But the rules appeared to be dead earlier this month, when Olson, Marquez Peterson and O’Connor voted to approve an amendment from Olson that made provisions of the rules voluntary rather than mandatory for utilities. Olson, joined by Tovar and Kennedy, then voted against the amended rules. (See Ariz. Regulators Kill Clean Energy Proposal.)
Following the May 5 defeat of the rules, Kennedy asked for a reconsideration.
Marquez Peterson has repeatedly expressed concerns that the proposed energy rules would give utilities a “blank check” that would increase costs for ratepayers.
“I find it ironic that stakeholders who have been hyper-critical of utilities in the past due to massive overbuilding, now seem to have no problem giving these same utilities a blank check to overbuild in the name of ‘clean energy,’ which will ultimately be paid for [by] Arizona families and businesses,” Marquez Peterson said in a May 12 letter filed in the energy rules’ docket.
Amendments to the rules that the commission adopted on Wednesday include adding a ratepayer impact measure test, changing portfolio options that utilities must include in their integrated resource plans, and adding the definition of “all source,” which includes supply- and demand-side resources. Tovar and O’Connor proposed those amendments.
Marquez Peterson proposed an amendment, which the commission adopted, to allow a utility to seek a fair return on investments made in demand-side resources, such as energy efficiency and demand response.
FERC on Tuesday approved a set of CAISO tariff revisions intended to prevent the kind of supply shortages that triggered rolling blackouts in California last summer during an extended Western heat wave (ER21-1536).
The changes, the product of an expedited effort to head off shortages this summer, originate from the root cause analysis performed by CAISO, the California Public Utilities Commission and the California Energy Commission last fall to determine what contributed to the state’s first rolling blackouts since the Western energy crisis of 2000/01. (See CPUC, CAISO Take Major Steps for Summer Reliability.)
The joint report identified a number of causes, including the extreme weather, outmoded resource adequacy planning, transmission constraints and wholesale market design issues. (See CAISO Says Constrained Tx Contributed to Blackouts.)
Among the market changes approved by FERC on Tuesday was CAISO’s proposal to better incentivize incremental energy imports under tight system conditions by providing bid cost make-whole payments to resources with hourly block intertie schedules issued through the ISO’s hour-ahead scheduling process.
Under existing rules, CAISO’s hour-ahead scheduling process produces binding hourly block energy schedules for all imports and exports, but those schedules are settled at prices set in the ISO’s 15-minute market, a practice it established in order to reduce real-time energy imbalance offset charges. CAISO additionally adopted a rule making hourly block schedules ineligible for bid cost recovery in order to encourage economic bids at the interties, a practice it now says may disincentivize suppliers from offering incremental energy into the real-time market.
| Shutterstock
“CAISO explains that, during stressed grid conditions, the risk of receiving a payment less than bid price can increase, in part, because CAISO may take out-of-market actions before the 15-minute market that result in 15-minute prices clearing at amounts below an hour-ahead intertie block bid price,” FERC noted. “As a result, suppliers in the hour-ahead scheduling process may face a charge as opposed to a payment to deliver needed imports.”
To remedy the problem, CAISO crafted a rule that would guarantee suppliers at the interties receive at least their bid price under tight system conditions. The ISO’s Department of Market Monitoring supported the revision. Pacific Gas and Electric offered qualified support, asking the commission to require ongoing monitoring and an after-the-fact cost-benefit analysis of the use of the make-whole payment by CAISO and the DMM to prevent potential gaming of the market.
In approving the rule, FERC said it found CAISO “has provided adequate specification of the circumstances under which it may suspend these make whole payments.” It also rejected PG&E’s request for ongoing monitoring, saying the new rule is unlikely to create a significant volume of uplift payments because it will be applied for very limited periods, and noting that CAISO and the DMM already perform monitoring of market results.
Other tariff changes approved Tuesday include:
the extension of CAISO’s hourly block and 15-minute bidding options to reliability demand response resources (RDRRs). The change will allow scheduling coordinators to specify whether an RDRR can be dispatched in the real-time market in hourly, 15- or five-minute intervals based on its operational and technical constraints. The ISO said its current rules don’t recognize the specific characteristics of RDRRs, which are often large load resources that can’t respond to five-minute dispatch orders. As the ISO learned during last summer’s heat wave, that can lead to price suppression in the five-minute market when the market process assumes those loads will be dropping off.
use of net load uncertainty in the capacity test within the Western Energy Imbalance Market’s resource sufficiency evaluation (RSE) used to validate each EIM entity’s balancing authority area has sufficient capacity to meet its load and export obligations prior to a market interval. The net load uncertainty requirement “would account for the net load forecast error between the 15-minute and five-minute real-time market dispatch, adjusted for the EIM diversity benefit,” FERC noted. CAISO had noted that its own BAA had passed the RSE’s capacity test amid last summer’s emergencies, indicating a shortcoming with the test. Inclusion of net load uncertainty should help prevent a BAA leaning too heavily on the EIM to meet its net load needs.
a requirement that an EIM entity use an automated market feature that updates its “mirror resource” schedule when the market awards an import at a CAISO intertie scheduling point sourced from the entity’s BAA. The ISO noted that entities currently have the option of either updating automatically or manually, but that the manual option increases the likelihood for error, especially under stressed conditions.
pricing of all operating reserves at the applicable energy bid cap when those resources are dispatched during emergency conditions.
Interconnection Changes
The commission also approved two changes to CAISO’s generator interconnection process to make more capacity available this summer.
The first removes the cap on the ISO’s behind-the-meter expansion process, which currently allows interconnection customers to add generating capacity without increasing the interconnection service capacity originally studied at a site up to the lesser of 125% of the existing capacity or 100 MW.
The second will allow CAISO to temporarily award interim deliverability to independent study interconnection customers who reach commercial operation before the ISO conducts its next deliverability assessment to determine the capacity of projects in the queue.
Interconnection customers are currently required to participate in the market as “energy only” resources until CAISO is able to conduct its next cluster deliverability assessment. The ISO says customers typically must wait a year before that assessment, during which time they are excluded from providing resource adequacy capacity even if surplus transmission deliverability is available.
Under the new rule, any customer awarded interim deliverability will retain that status only until it either achieves full commercial operation or CAISO completes the next scheduled deliverability assessment and the customer completes delivery network upgrades.
ISO-NE on Monday said it should have the resources necessary this summer to meet demand during average and above-average temperatures.
Under typical weather conditions, demand is expected to peak at 24,810 MW, according to the RTO’s 50-50 forecast. An extended heat wave could push demand up to 26,711 MW in the 90-10 forecast.
ISO-NE’s forecasts do not account for extreme conditions such as the Western heat waves and Texas winter storm during the past year. The RTO said it is working on ways to plan and prepare for those type of weather events.
“Events in other parts of the country have shown how quickly the unexpected can become reality,” ISO-NE COO Vamsi Chadalavada said. “Over the next several months, we’ll work with the New England states and stakeholders in the energy industry to discuss the challenges these types of events pose to the region.”
Peak demand vs. annual energy use on the ISO-NE grid | ISO-NE
More than 31,000 MW of capacity are expected to be available, including generators using natural gas, nuclear, oil, coal, hydro, biomass and wind; demand response resources; imports from New York and Canada; and more than 2,600 MW of energy-efficiency measures.
The forecasts also include a reduction of more than 800 MW during the peak hour that can be expected from the region’s more than 209,000 behind-the-meter solar PV installations. New England has approximately 4,000 MW of solar PV installed, which produce their highest output in the early afternoon hours. The regional increase in solar power has pushed the peak hour of grid demand to later in the day, when production from solar PV systems is lower.
The RTO also continues to monitor the impact of the COVID-19 pandemic on demand. As vaccination efforts have expanded during the last several months and New England states continue their reopening efforts, ISO-NE said demand is near normal, pre-pandemic levels after a slight decline.
Last summer’s demand peaked at 25,121 MW on July 27. The all-time record occurred Aug. 2, 2006, when demand reached 28,130 MW after a prolonged heat wave.
FERC on Monday granted ISO-NE an extension on its Order 2222 compliance deadline, giving the RTO until Feb. 2, 2022 (RM18-9). The original deadline was July 19.
Order 2222, issued last September, directs RTOs and ISOs to open their markets to distributed energy resource aggregations. (See FERC Opens RTO Markets to DER Aggregation.)
In its extension request, ISO-NE told the commission that Order 2222 compliance “requires substantial coordination.” An extension would ensure the RTO “has sufficient time to engage with relevant electric retail regulatory authorities, electric distribution companies, meter readers and other affected stakeholders,” it said, and its approach to metering and integration of demand response resources would benefit from further discussions with NEPOOL stakeholders. The extension also provides the RTO and NEPOOL time to review whether Order 2222-A, which FERC issued in March to refine and clarify some requirements in the original order, impacts its compliance proposal. (See FERC Limits State ‘Opt Out’ on DR.)
The Massachusetts Department of Public Utilities, Connecticut Public Utilities Regulatory Authority and Vermont Public Utility Commission supported ISO-NE’s compliance extension, including the ability to solicit more input from stakeholders. Advanced Energy Economy agreed with the RTO that several issues warrant further discussion and emphasized the importance of allowing stakeholders to provide feedback on ISO-NE’s proposal to ensure full compliance.
Christie Concurs, with Caveat
Commissioner Mark Christie concurred with granting an extension, but he reiterated that he would not have voted for Order 2222 if he were on the commission last September.
“Since — at least at this point — the RTOs have no choice but to comply with these orders, I respectfully concur with the letter order granting ISO-NE’s request for extension of time to make its compliance filing,” Christie wrote. “I also hope that by granting the extension, ISO-NE will have more time to try to mitigate some of the potential for reliability problems.”
ISO-NE will seek votes on its Order 2222 compliance proposal and any potential amendments at the December meetings of the NEPOOL Markets, Reliability and Transmission committees. The RTO will then request a vote from the Participants Committee at its January 2022 meeting. (See “Discussing Order 2222 Compliance,” NEPOOL Markets Committee Briefs: May 11, 2021.)
Summer 2021 “is shaping up to be a challenge for electric system operators” in most of the ERO Enterprise thanks to extreme weather and elevated temperatures, NERC said in its 2021 Summer Reliability Assessment released Wednesday.
Although resource availability has improved since last year, with all regions possessing sufficient anticipated reserve margins that exceed their reference margin levels, ERCOT, WECC, MISO and NPCC are still at elevated risk of energy emergencies due to above-normal temperatures predicted across much of North America that can push demand higher while also affecting availability of generation resources.
California is in particular danger, with energy emergencies possible even during periods of normal peak demand and more likely “when above-normal demand is widespread in the West,” echoing WECC’s warnings from earlier this year. (See Southern Calif. Could Fail RA Test, WECC Says.)
United States and Canada summer temperature outlook | NERC
The California-Mexico (CAMX) assessment area faces the greatest risk, despite planned resource additions of 1,300 MW over the summer, because of the widespread use of solar facilities in the region. NERC predicts more than 10,000 MWh of expected unserved energy in CAMX for the upcoming summer.
While solar resources are capable of meeting daily peak demand, problems arise later in the day as output diminishes and demand remains high due to continued warm temperatures. While California’s current 625 MW of battery storage — and a further 875 MW scheduled to be installed this summer — will help alleviate the problem, energy imports and thermal resources will still be needed to make up the shortfall. If either is not available, firm load shedding and forced outages may be necessary to maintain stability.
Wildfires are also a major factor again this year due to the heat and dry conditions expected in late summer across the Western U.S. and Canada, as FERC Summer Assessment Spotlights Western Drought Risks.) Western utilities may have to initiate public safety power shutoffs to mitigate the risk of wildfires, potentially impacting thousands of customers.
Texas Faces Resource Shortfalls
Energy emergencies remain a high risk for Texas as well. While the state looks good on paper, with the 15.3% planning reserve margin comfortably above its 13.75% reference margin level thanks to the addition of more than 7.8GW of generation resources since last year, it is expected to face many of the issues that are worrying WECC.
For one thing, many of the resources added since 2020 are wind and solar facilities, bringing the same concerns about their dependence on weather. In Texas the biggest question is around wind, which accounts for a “significant portion” of electricity supply in the state. As a result, grid operators must have plans for what to do in periods of low wind.
Two potential generator outage scenarios in ERCOT this summer. Left: Low wind and normal generator outages at peak demand. Right: Extreme demand and resource outages, including wind. | NERC
Wind availability is concerning enough to merit two scenarios exploring the implications of weather-related shortfalls in the assessment. In one, the organization combined a 50/50 peak demand forecast, which has a 50% chance of being exceeded, with a prediction of 90/10 low wind conditions, which has a 10% chance of being exceeded. Under this scenario, assuming operational mitigations of 2.3 GW, expected operating reserves fell to just 1 GW, a worryingly thin margin.
The other scenario combined a one-in-10-year forecast for demand levels with extremely low resources, with 12.1% of expected thermal resources unavailable and wind output reduced by 76.8%. This resulted in a 12.7 GW shortfall. Though the report acknowledges this combination of high demand and low resource availability is “exceedingly rare,” it does call the scenario a “plausible” depiction that provides “insights into potential emergency conditions.”
COVID-19 Continues to Complicate Forecasts
All other regions are expected to have little trouble meeting peak demand, though the report warns that MISO and NPCC-New England could see demand exceeding capacity resources in the 90/10 forecast, requiring “additional non-firm transfers from surrounding areas.” Predicting demand is also likely to be once again more difficult this year than usual due to the ongoing impacts of the COVID-19 pandemic, especially with many employers ending their remote work postures. The impact of the return to normal is likely to affect commercial and residential loads in ways that are hard to predict.
Despite the progress of vaccinations, NERC predicts that pandemic-related health measures will also be needed throughout the summer, especially as utilities undertake customary mutual assistance efforts during the upcoming hurricane season.
Although utilities have by now largely gotten used to these protocols, they remain a complicating factor in planning. For example, social distancing and personal protective equipment were featured prominently in SERC Reliability’s spring extreme weather webinar last week. (See SERC Urges Preparation Ahead of 2021 Hurricane Season.)
The U.S. Bureau of Ocean Energy Management is looking for manpower and increased efficiencies to handle the added workload of offshore wind permit applications expected from President Biden’s goal of 30 GW by 2030, a senior agency official told Reuters’ U.S. Offshore Wind 2021 conference Wednesday.
Michelle Morin, chief of the BOEM Office of Renewable Energy Programs’ environment branch, said the agency expects to handle at least 16 offshore wind projects by 2025. In response, her department is about to hire seven new employees and expects a 30% staffing increase next year.
“We’ve really ramped this up,” Morin said in answer to a question about the agency’s plan to meet the surge in workload. “We are pulling resources from all over the Bureau of Ocean Energy Management” to help with the OSW permitting process.
The agency also expects to improve efficiency by pooling information that is common to several projects, allowing it to assess how to handle those elements and smooth their evaluation process, she said. That way, she added, “we can really focus on the unique aspects of each project” and whether they meet the criteria for agency permit approval, she said.
Certainty vs. Flexibility
Morin spoke on a panel that focused on how to improve the arduous, often lengthy permitting process needed for projects to secure BOEM approval. The panel highlighted the inherent tension between the desire on both sides to provide predictability in a situation for which there are few historic precedents to provide a guide.
Biden has emphasized renewable energy since the start of his administration, with particular emphasis on OSW power. He aims to create a thriving industry that will create jobs and economic opportunity, including new supply chains that can manufacture and deliver wind turbines for projects.
The administration on May 11 approved its first big offshore wind farm, an 800-MW project in the waters off Martha’s Vineyard in Massachusetts after a decade-long approval process. Massachusetts Gov. Charlie Baker, speaking at the conference Wednesday, said “it took forever for us to get it through the process.” (See BOEM Approves 800-MW Vineyard Wind I.) On Tuesday, the administration announced plans to offer leases for California’s first OSW areas. (See BOEM to Offer Leases for Calif. Offshore Wind.)
Morin said one obstacle to a project’s passage is that it could need the evaluation of 10 or more agencies to get approval. “We’re working together, trying to do a one-government approach because this is one environmental impact statement, one record of decision,” she said.
But project developers could also take steps to make the permitting process smoother and shorter, she said, by providing as much detailed information as possible early on in the process. She noted that developers say that what they need from BOEM is certainty in the process, especially how long it will take. “We also look for certainty,” and that is helped by getting key information early on in the process, she said.
Paul Phifer, permitting manager for Atlantic Shores Offshore Wind, said that aside from certainty of schedule, developers look for predictability in the questions that they may be asked later in the project. Atlantic Shores, a joint venture between Shell New Energies US and EDF Renewables North America, is one of two projects seeking to be designated the developer on New Jersey’s second OSW project. (See Developer to Use Union Labor for NJ OSW Project.)
“Having some of the substantive comments come two or three years into project design, for a developer, [is] just too late,” he said. One solution would be to get multiple agencies involved in the permitting process as early as possible, he said. Still, he added, there will always be tension between needing certainty in the process and the ability to make changes if needed.
“We’re all looking to have maximum flexibility because we don’t know exactly often what project technology is going to be available when we start building, or what agreement we might get about purchase power from a state or another entity,” he said. “So we need to maintain flexibility. While maintaining that, I think we still could have conversations, an interagency process, earlier, that give us better guidance and help familiarize the agencies with what we’re contemplating.”
“I think the more you can design that project with close coordination with the key agencies, you have the best picture to foresee future changes,” he said. “Nobody wants a significant change late in the game. I mean, it slows it down. It’s costly. You may be under agreement to provide power to the state by certain time. So there’s a lot of risks associated with those late changes.”
Financing Groundbreaking Projects
Morin added that the agency’s ability to bring certainty may improve with time, as more projects go through the process.
“As we conduct more of these reviews, hopefully we’ll be able to better predict where there might be points that there could be some risks to the schedule,” she said.
Louise Pesce, managing director of Mitsubishi UFJ Financial Group (MUFG), which has helped finance numerous new energy projects, said investors may also get more accustomed to the process as more projects get underway. She called Biden’s plan for 30 GW “incredibly ambitious.” Investors may see the early projects as higher risk, she said, but that may diminish as the support industries and infrastructure emerge in the U.S., rather than components being imported.
Pesce said she doesn’t anticipate a shortage of financing to develop early U.S. projects, in part because offshore projects have proven their worth in Asia and Europe, where the industry is more advanced.
“Banks that have been active in Asia and Europe are very keen and eager to utilize that experience here in the U.S. and add to liquidity available from the more U.S.-centric lenders,” Pesce said.
“I think that the construction for the first project is going to be slightly more complicated; I won’t say it’s more risky, but it is more complex,” she said. “There’s more components to consider with the U.S. first-mover projects versus the U.K. or the European market, where you have a mature industry of vessels [and a] supply chain established.”
Still, she said, “I think that those are similar risks that lenders are used to seeing elsewhere.”
When it was his turn to ask a question during the opening panel of FERC’s technical conference on modernizing electricity market design in ISO-NE, Commissioner Mark Christie started with the part of his résumé that includes 17 years as a member of the Virginia State Corporation Commission.
FERC Commissioner Mark Christie | FERC
“I’m very sympathetic to state sovereignty and accommodating state sovereignty and respecting it,” Christie said to a group of New England regulators, RTO executives and the chair of the NEPOOL Participants Committee, brought together to discuss the relationship between states’ policies and ISO-NE market design.
Contending that the RTO’s No. 1 job is to “keep the lights on,” Christie asked if states wanted responsibility for their resource adequacy like some others in PJM, MISO and SPP, or a governance change to make ISO-NE more like ERCOT, as in an energy-only market.
“My question to you is: What do you think of those two options?” Christie said.
Matthew Nelson, chair of the Massachusetts Department of Public Utilities, said the fundamental goals of the states and RTO “are almost in lockstep.” States like Massachusetts and Connecticut are procuring offshore wind and hydropower on their own, but there should be a market-based mechanism that the states create with ISO-NE and NEPOOL stakeholders to procure clean energy “with an eye toward reliability,” he said.
Connecticut DEEP Commissioner Katie Dykes | FERC
Katie Dykes, commissioner of Connecticut’s Department of Energy and Environmental Protection, said that she “respectfully” objected to Christie’s presumption of ISO-NE’s chief task — and his question.
“Yes, in Connecticut, we are focused on clean energy, but in addition to that, we have had to take extraordinary actions in recent years to shore up the reliability of the [ISO-NE] grid and the market,” Dykes said. The RTO’s capacity market design had been constructed around the investment needs of natural gas resources, she contended. Additionally, when the Millstone nuclear plant was considering premature retirement, ISO-NE and its market “had no plan to address this,” and it was left to Connecticut “legislators and ratepayers … to prevent [Millstone] from retiring.”
Vermont Department of Public Service Commissioner June Tierney said Christie’s question was based on “a false duality.”
“There’s more than one way to design a market to keep the lights on,” she said. ISO-NE “needs those lights to be kept on with clean energy in a way that addresses climate change meaningfully.”
ISO-NE CEO Gordon van Welie | FERC
ISO-NE CEO Gordon van Welie said markets are “never going to work very well” with inadequate infrastructure supporting them “or if policy objectives are not aligned.” He said the constraints in the region are around gas pipelines and storage plus LNG imports.
“We have to design the markets around those constraints, and we are in the position where certain energy providers are going to have an outsized influence on our reliability,” van Welie said. “That’s just where we ended up because of the choices we made over the last two decades.”
In terms of policy objectives, van Welie said there is a “misalignment at the moment” between the RTO and the states but added that the markets were set up to achieve reliability. “They’ve done an excellent job of doing that, despite the fact that we had to work around some of these constraints.”
A Forward Clean Energy Market (FCEM), which is under consideration, offers some hope to relieve some of the tensions, but it will not ultimately solve the problem, he said. (See ISO-NE: No Difference Between FCEM and ICCM — Yet.)
“Until the region figures out how it wants to socialize some of these costs for reliability that are outside of the market, we’re going to stay stuck in that situation,” van Welie said. “There’s no market design that will solve the problem that Commissioner Dykes wants us to solve.”
Potential Market Changes
Mark Karl, ISO-NE | FERC
In a discussion about the short-term options available and potential market changes that could better accommodate state policies, Mark Karl, ISO-NE vice president of market development and settlements, said that the capacity market design “needs to change.”
“We recognize that without the successful combination of state resource procurement policies, over time the combination or the continuation of them will lead to a mismatch and potential double procurement of resources by the state and the market, which would create the inefficiencies and would tend to increase consumer costs,” Karl said.
For the past few years, Karl said, the RTO has been working to accommodate state-procured resources within the minimum offer price rule (MOPR) framework. ISO-NE recently added a project to its Annual Work Plan to address the removal of the MOPR from the capacity market. Karl said that the Competitive Auctions with Sponsored Policy Resources (CASPR) mechanism was the RTO’s “second-choice policy,” but there is a “lack of regulatory support for it.”
Philip Bartlett, Maine Public Utilities Commission | FERC
Philip Bartlett, chairman of the Maine Public Utilities Commission, said that CASPR “has not proven effective in terms of allowing state-supported resources into the market.”
“The goal here is to define what it is we’re trying to achieve clearly, and then develop the tools that will do that at the least cost, while also supporting the renewable resources,” Bartlett said.
Dan Dolan, president of the New England Power Generators Association, agrees that market reforms are “clearly” needed. However, it is also necessary to recognize the MOPR has been a part of the capacity market “for a very good reason.”
Dan Dolan, New England Power Generators Association | FERC
“Economic price formation to provide market-based reliability is critical and cannot be lost sight of,” Dolan said. “But I also recognize the discussion over the last several months and today about the future and potentially numbered days of MOPR.”
Dolan said “out-of-market reliability support” like Connecticut’s subsidies for Millstone should be avoided “as much as humanly possible.” He said markets need to deliver reliability at a competitive price.
“How we do that is to evolve the electricity market in New England to manage three elements,” Dolan said. “First, it must integrate the state-sponsored resources to recognize their capacity value. Second, it should incorporate the underlying clean energy decarbonization policies into the market … and third, it must ensure that the market is still providing resource adequacy and broader reliability services in a competitive manner.”
Abigail Krich, Boreas Renewables | FERC
Abigail Krich, president of Boreas Renewables, said if reliability is a concern, “better defining our reliability needs and products should be the issue of top priority.” Krich expressed three key concerns that should be addressed to prevent the market from acting as a barrier to entry or limiting the counting of resources needed to meet state policy goals.
“First, the accreditation process in which different resources are qualified to provide a certain quantity of capacity does not currently strike a reasonable balance between the goals of recognizing the unique attributes of different technologies and treating all technologies comparably,” Krich said. “Second, the overlapping impact deliverability test effectively prevents new capacity resources in transmission constrained areas from competing with existing resources. Finally, energy-only solar generators that do not participate in the [Forward Capacity Market] are neither counted toward metering nor reducing the installed capacity requirement. They are simply ignored.”
Panelists Warn of Long-term Transition Woes
The last panel of the day found strong support for centralized clean energy procurement mechanisms. But while participants stressed the urgent need for a path toward New England’s carbon-free future, they also emphasized the danger of mishandling the transition.
Christopher Geissler, ISO-NE | FERC
“The costs of getting things wrong here are significant. … We want to make sure we get it right, and we design it in a way that is consistent with sound market design so that we’re not back at the commission a year later saying, ‘We have to patch it up … [because] this didn’t work exactly how we thought it would,’” said Christopher Geissler, principal economist for ISO-NE. “While we want to work as quickly as possible, I think our objective would be to do the work as well as possible, and if that takes a little bit longer, I think that’s a trade-off that … would be necessary.”
The FCEM framework — which would competitively procure clean energy commitments that can complement other wholesale power market products — received the endorsement of several panelists. But others cautioned against seeing any one strategy as a cure-all. Geissler, for instance, noted several barriers to the FCEM working as desired, such as a lack of consensus on what exactly constitutes clean energy and the likelihood of rapidly growing complexity as more products are added to the mix.
Arnie Quinn, Vistra | FERC
Arnie Quinn, senior director of FERC-jurisdictional markets at Vistra, echoed this warning, emphasizing that participants must be sure of the need they are trying to fill before they move forward with a new market design.
“Too much focus on emissions is going to get us California and CAISO from last summer; too much focus on cost is going to get us Texas from last winter,” Quinn said, referring to the Western heat waves of 2020 and the winter storm of February 2021, respectively. “So, we really have to incorporate [all] communities’ goals into the wholesale market. We think a reasonable carbon pricing mechanism, or a well designed regional clean energy standard, are both steps in the right direction.”
Jolette Westbrook, Environmental Defense Fund | FERC
Jolette Westbrook, director and senior attorney for energy markets and regulation at the Environmental Defense Fund, observed that while there is a need for new market designs that “take [environmental justice] into account in a very meaningful way,” regulators must also recognize that changes cannot be made overnight. Short-term measures will be needed to cover the transition period.
“In the near term, for example, ISOs should adopt capacity market reforms so that all resources can compete on equal footing,” Westbrook said. She added that the long-term shift must incorporate “off-ramps” so that “corrections can be made early” if the new market is discovered to have unintended damages to disadvantaged populations.
Michelle Gardner, NextEra | FERC
The changing nature of the bulk power system and its generation mix are also complicating factors in adopting FCEM or other market designs, panelists warned, echoing multiple recent assessments from FERC Summer Assessment Spotlights Western Drought Risks.) As the electric grid continues its transition away from conventional generation, market structures will need to accommodate the characteristics of the new resources coming online while still supporting consumer demands.
“Our market today is based on summer peaking, and so we may need more dynamic purchases to support the changing resource mix across the season, shifting demands across the day, and new technologies,” said Michelle Gardner, senior director of regulatory affairs at NextEra Energy. Moreover, “as the states look to centrally procure clean energy, we are going to want those megawatts to count toward resource adequacy … and as we all know, intermittent [generation resources] have very different profiles, depending on the season.”
MISO has expanded its availability-based capacity accreditation proposal for generation resources by including hours that aren’t so risky.
The grid operator originally proposed that a resource’s accreditation would hinge solely on availability during “resource adequacy hours,” or the year’s top 5% of hours that MISO believes contain reliability risks. The plan will now include unremarkable hours in addition to RA hours, leading to more lenient accreditations.
MISO will use a resource’s availability “across all hours with a two-tiered weighting structure between tight condition hours and non-tight hours.” Risky hours will carry more weight than other hours. The grid operator will use the top 3% of tight hours and retain a rolling three-year period to define a resource’s availability for accreditation.
“Resources that tend to offer their full availability and don’t miss tight hours receive full credit,” staff said.
During a special May 21 teleconference, Scott Wright, the RTO’s executive director of market strategy and design, said staff will soon prepare numbers for the weighting.
WEC Energy Group’s South Oak Creek coal plant, slated for retirement in 2024 | WEC Energy Group
Stakeholders denounced the RTO’s first resource adequacy hours selection as too random to be helpful. Some have said it’s too difficult to pin down when maximum generation events are likely to occur. Other stakeholders have said MISO has not provided enough data-driven results to justify a new accreditation process.
“This should reduce year-over-year volatility in accreditation values, and allow for better planning,” Kevin Vannoy, director of market design said of MISO’s revisions.
He said staff would “continue to monitor this as the resource mix evolves.”
Vannoy also said the accreditation will necessitate improvements in managing outages. “MISO’s going to have to enhance our tools and processes for outage coordination,” he said.
24-Hour Exemption
An accreditation exemption provision has drawn the most attention from MISO stakeholders and its Independent Market Monitor.
The grid operator is providing a 24-hour exemption for offline resources during tight condition hours. If the offline resources rumble to life in a 24-hour window of the identified tight conditions, the inaction won’t count against a resource’s capacity accreditation.
IMM staffer Michael Chiasson said the 24-hour lead time seems too long. He said the grace period makes some resources “totally unavailable” for a perilous morning or midday peak.
The IMM’s David Patton said many emergencies occur with as little as 15 minutes’ advance notice.
“You’re proposing something here that doesn’t seem to differentiate” flexible resources from inflexible resources, he said. “At the end of the day, the resources that help you make it through these emergencies are the flexible ones.”
Patton said that while he recognized MISO was “trying to make stakeholders happy,” it probably wasn’t doing what is best for reliability.
“You need to prioritize where your principles are over just minimizing stakeholder concerns,” he told MISO staff.
Customized Energy Solutions’ Ted Kuhn argued that many emergency weather conditions are foreseen and take place over multiple days.
“The winter event and summer heat waves last for days,” he said. “Planning for only a two-hour event seems ill-advised.”
MISO Executive Director of Market Operations Shawn McFarlane said the grid operator first needs to address the generation fleet’s growing unplanned and forced outages.
“When we’ve needed generation and resources the most, they haven’t been there as much as we’re forecasting,” he said.
McFarlane acknowledged that MISO may need to eventually drop the 24-hour grace period.
Kuhn said using MISO’s exemption, some generators could be spared from any performance measurement during resource-adequacy (RA) hours in their accreditation.
MISO market design adviser Dustin Grethen said “it is a risk” that generators could be exempted for all RA hours. “We’d probably need some protection in place there.”
Grethen asked stakeholders for ideas on how MISO might allocate a limited number of RA hours exemptions.
Clean Grid Alliance’s Natalie McIntire said she was unsure how the new accreditation will help on an “unexpectedly warm day … that we don’t see weeks in advance.”
“It’s a hot topic,” Vannoy agreed, saying that outage planning will continue to evolve as more is learned about climate change and extreme weather.
Still 4 Seasons
MISO is still planning for four separate seasonal-capacity auctions. The proposal is premised on a four-month summer season, a two-month fall, and three months apiece for spring and winter. Staff said warmer Septembers are better categorized among summer load shapes.
The grid operator plans to use its current annual loss-of-load expectation analysis to set seasonal reserve requirements. Reliability targets will be rounded up to a minimum one-day-in ten-years standard, even if minimal or no risk is identified during shoulder seasons.
MISO will also conduct four separate analyses so transfer limits between its resource-adequacy zones vary with the seasons.
Patton said he doesn’t agree with the proposed four-season accreditation. He said MISO should instead focus on separate winter and summer accreditations.
“I don’t think you’re going to have a lot of tight hours in spring and fall,” he said.
Grethen said a seasonal division will account for special attributes, such as winter weatherization, and remove a year-round higher must-offer requirement to allow some units to take seasonal outages.
The Biden administration Tuesday announced it plans to offer leases for California’s first offshore wind areas, a 399-square-mile block off Morro Bay that could support 3 GW, and the Humboldt Call Area off Northern California, which it said is big enough for an additional 1.6 GW.
Interior Secretary Deb Haaland, National Climate Adviser Gina McCarthy and California Gov. Gavin Newsom took part in the announcement of the two potential wind energy areas (WEAs).
The announcement followed years of consultation between Interior and the Defense Department to identify areas that would not interfere with the Pentagon’s training and testing operations.
“Tackling the climate crisis is a national security imperative, and the Defense Department is proud to have played a role in this important effort,” Under Secretary for Policy Colin Kahl said in a statement. “The Defense Department is committed to working across the U.S. government to find solutions that support renewable energy in a manner compatible with essential military operations.”
The Bureau of Ocean Energy Management issued a call for information and nominations for offshore wind on Oct. 19, 2018, for three areas, including Humboldt, Morro Bay and the Diablo Canyon Call Area. Plans for Diablo Canyon were not disclosed in Tuesday’s announcement. Fourteen developers responded to BOEM’s 2018 solicitation.
BOEM and California officials will hold an Intergovernmental Renewable Energy Task Force meeting on June 24 to discuss the potential WEAs. After the task force meeting, the WEAs can be finalized and undergo environmental analysis. BOEM expects to include both the northern and central areas in a single lease sale auction targeted for mid-2022.
The Biden administration has proposed deployment of 30 GW of offshore wind by 2030, but most of the attention has been focused on the East Coast, which has the advantage of relatively shallow waters on the continental shelf, allowing turbines to be installed in the seabed. The deeper waters of the West Coast will likely require use of floating turbines.
California must triple its renewable capacity to meet its goal of 100% clean energy by 2045. Senate Bill 100, which established the goal, envisions 10 GW of offshore wind and more than doubling onshore wind from 6 GW to 12.6 GW.
State Assemblymember David Chiu (D) has proposed legislation that would require the California Energy Commission to set offshore wind targets within three months (Assembly Bill 525).
“I am excited about the opportunity for offshore wind on the West Coast and the Pacific,” BOEM Director Amanda Lefton said during an appearance Tuesday at Reuters’ U.S. Offshore Wind 2021 conference. “There is clearly interest from our state partners, and I think there is a tremendous opportunity to move forward.”
Experts say the distance between the wind areas and California’s ports will be among its biggest challenges in making offshore wind a reality. (See Port System Big Challenge for Calif. Offshore Wind.)
“While interest from the global industry will be unprecedented, West Coast development requires American ingenuity and innovation in next generation technologies that will create opportunities for engineering firms and skilled labor,” said Liz Burdock, CEO of the Business Network for Offshore Wind.
A recent report by Energy Innovation and RMI shows that Colorado is a long way from meeting emissions reduction targets set by the state’s 2019 Climate Action Plan. Even so, Governor Jared Polis is wary of strict legislation to cap emissions.
Democrats and environmental activists support SB200, which requires Colorado’s Air Quality Control Commission (AQCC) to “adopt rules that will result in the statewide reduction of greenhouse gas (GHG) emissions of 26% by 2025, 50% by 2030, and 90% by 2050, as compared to 2005 emissions.”
Energy Innovation and RMI’s report is based on data from the Colorado Energy Policy Simulator (EPS), which is intended to provide “additional analysis of policies that can drive deep emissions reductions in Colorado.” According to the simulator, which includes a “business-as-usual” scenario, existing policy, plant retirements and technology innovation will not be sufficient to meet the goals in the Climate Action Plan.
The EPS also includes a “GHG Roadmap 2019 Action Scenario based on legislation, utility commitments and executive action in 2019 and 2020.” However, even when taking these into consideration, there is still a significant gap between the state’s projected economywide GHG emissions and the goals set in 2019.
Colorado economy-wide GHG emissions | Energy Innovation: Policy and Technology LLC and RMI
According to the EPS scenario, Colorado would produce more than 100 million tons of emissions in 2030. To meet the state’s targets and help limit climate change to 1.5 degrees Celsius, the state must curb emissions to about 70 million tons by 2030.
Environmental groups and democratic lawmakers see SB200 as a way to close this gap. In January, the Polis Administration released the GHG Pollution Reduction Roadmap, which also concluded that current policy would not be sufficient to meet Colorado’s emissions targets. But Polis has been known to favor incentive programs and voluntary action rather than stringent legislation.
His concern with SB200 mainly lies in the authority it gives the AQCC and its potential to stunt Colorado’s economy. In April, Polis told The Colorado Springs Gazette’s editorial board that he would veto the bill if it made it to his desk. He said a reliance on future technology to meet these goals would require a flexible approach, and he’s unwilling to “give this unelected board, the Air Quality Control Commission, near-dictatorial control of our entire economy with a legal mandate to meet certain hard carbon reduction goals, many of which we’re already much of the way to.”
“We have a plan to be able to continue to clean our air, reduce carbon emissions, and part of that plan is additional legislative action like the infrastructure bill, like a building electrification bill, but requiring one particular state committee to have dictatorial authority across every sector of the economy is not a constructive way to achieve Colorado’s climate goals,” he said.
During a Senate hearing in April, one of the bill’s sponsors, Democratic Sen. Faith Winter, said that there are no “hard caps.”
The AQCC “has the flexibility to adjust goals as necessary to make sure we’re meeting our statewide goal,” she said.
