A federal appeals court on Tuesday rejected a challenge to FERC’s 2020 revisions to how it enforces the Public Utility Regulatory Policies Act, though it concluded the commission committed a “serious violation” by not conducting a formal environmental assessment (EA) before issuing the order (20-72788).
Multiple renewable energy industry and environmental advocacy groups petitioned for review of Order 872, which they argued made it more difficult for independent, non-utility-owned energy generators to be designated qualifying facilities under PURPA (RM19-15, AD16-16). (See FERC Rejects Challenges on PURPA Changes.)
The 9th U.S. Circuit Court of Appeals, however, found that FERC holds broad rulemaking discretion and its interpretations of the law were not unreasonable. The court also rejected the petitioners’ challenges to four specific provisions of the order.
The court did agree with the petitioners’ contention that FERC violated the National Environmental Policy Act by not preparing an EA before issuing the order. It remanded the order to FERC to conduct an EA, but it declined to vacate it.
“Although FERC’s failure to prepare an EA is a serious violation, Order 872 does not suffer from fundamental flaws, making it unlikely that FERC could adopt the same rule on remand, and the disruptive consequences of vacatur would be significant,” the court said.
PURPA directed FERC in 1978 to promulgate rules to encourage development of two types of QFs: alternative energy sources such as renewables owned by the same person within 1 mile of each other that totaled no more than 80 MW generation capacity, or fossil-fired cogeneration facilities.
The law mandated that electric utilities buy the power generated by QFs under rate guidelines established by FERC and set by states. In response, FERC issued Orders 69 and 70 in 1980.
Congress changed the statutory language via the Energy Policy Act of 2005, and FERC responded with Order 688, which among other things established a rebuttable assumption that facilities with not more than 20 MW capacity do not have adequate, nondiscriminatory access to markets.
With Order 872, issued under then-Chair Neil Chatterjee (R), the commission explained that extensive technology advances and dramatic energy industry changes in the preceding 40 years made significant revisions necessary.
Among other things, FERC:
expanded the 80-MW calculation radius to up to 10 miles and set a list of factors to establish whether facilities were “separate”;
allowed states to eliminate the fixed-rate option;
gave states additional flexibility to calculate utilities’ avoided costs; and
reduced the 20-MW nondiscriminatory threshold to 5 MW.
Ruling
The 9th Circuit rejected the petitioners’ contention that Order 872 discourages development of QFs, and therefore violates PURPA, which directed FERC to encourage such development.
The judges shot down various other arguments as well. They ruled that:
FERC did not overstep the authority granted to it by PURPA, and Order 872 meets the test of the Chevron
FERC was not arbitrary or capricious in making the rules; it was reasonable and used discretion delegated to it by Congress.
Order 872’s rate-related provisions do not violate PURPA’s nondiscrimination requirement.
The court did fault FERC for its reasoning for not preparing an environmental impact statement or an EA.
“FERC misunderstands NEPA’s requirements,” it wrote, adding that the commission’s own regulations for implementing NEPA support its conclusions.
“It was eminently foreseeable that a regulatory change of this magnitude could produce significant environmental effects,” it wrote. “It was a near certainty, for example, that at least some QFs could lose their status under the 2020 site rule, or that at least some states would eliminate the fixed-rate option for the calculation of avoided costs.”
But the court concluded that vacatur would cause severe trouble, as several states have already initiated proceedings in response to the order and some utilities already have received relief from mandatory purchase obligations with facilities rated at 5 to 20 MW.
“Victory. Again,” Chatterjee posted on X in response to the news. “The Chatterjee FERC record in the courts is quite strong.”
California will need to double its public EV charging infrastructure between 2030 and 2035 to serve the expected number of electric vehicles in the state, according to a new report by the California Energy Commission (CEC).
That draft Electric Vehicle Charging Infrastructure Assessment, which highlights the massive needs stemming from the state’s aggressive transportation decarbonization goals, coincided with the release of a CALSTART working paper on phasing the national EV charging infrastructure build-out.
The CEC assessment estimated that by 2035, more than 15 million light-duty electric vehicles in California would require more than two million chargers at public and “shared private” locations, more than doubling the seven million vehicles and one million chargers projected for 2030. This estimate did not include chargers installed in single-family homes but included shared private locations such as multifamily dwellings and workplaces.
The estimate of 15 million electric light-duty vehicles represents a tenfold increase from today. In the first quarter of 2023, California surpassed 1.5 million light duty electric vehicles, with nearly 85% full EVs, 15% plug-in hybrids (PHEVs) and less than 1% hydrogen fuel cell vehicles. In that quarter, full EVs and PHEVs accounted for more than 20% of new passenger vehicle sales. Light-duty vehicles were defined as vehicles with a gross vehicle weight rating below 10,000 pounds, primarily privately owned cars and trucks.
The assessment was the second biennial report required under Assembly Bill 2127. The draft report extended the 2021 analysis by five years to 2035, the target date for Gov. Gavin Newsom’s ambitious transportation electrification goals. His Executive Order N-79-20 set goals for 100% zero-emission new passenger car and truck sales and 100% zero-emission vehicle operations for drayage trucks by 2035.
For the grid, peak weekday charging for light-duty vehicles is likely to reach 4,000 MW in the middle of the day by 2030, with more than a third of that from DC fast chargers. Residential charging, in contrast, would peak overnight, with the estimated demand showing a significant rise at 9 p.m. when time of use rates drop.
The assessment’s estimates for the mix of Level 1, Level 2 and DC fast chargers for light-duty vehicles appeared to be conservative, with only 83,000 DC fast chargers in the 2.11 million total, or less than 4%. That is a much lower percentage than today when California has 9,808 DC fast chargers to its 82,000 public Level 2 chargers.
In addition to building out EV charging infrastructure for passenger vehicles, the assessment forecast demand for fast chargers for commercial vehicles. The 377,000 medium- and heavy-duty EVs in 2035 would need an additional 256,000 20 to 150-kW DC fast chargers in depots, as well as 8,500 higher powered 350 to 1,500-kW public DC fast chargers. For medium- and heavy-duty vehicles, the load on the grid is more spread, with a peak demand in 2030 of 800 MW overnight, largely from vehicles at depots.
CALSTART, a nonprofit consortium focused on clean transportation, released a working paper on charging infrastructure for zero-emission medium- and heavy-duty vehicles throughout the United States. In Phasing in U.S. Charging Infrastructure: An Assessment of Zero-Emission Commercial Vehicle Energy Needs and Deployment Scenarios, CALSTART recommended phasing the building-out of commercial vehicle charging infrastructure, starting with “favorable launch areas.” The phased approach could support commercial EV uptake at the rates specified in the Global Memorandum of Understanding on Zero-Emission Medium- and Heavy-Duty Vehicles (Global MOU), which the United States signed in 2022.
“This phased approach can manage distribution grid upgrade timelines and maximize utilization even with the Global MOU’s attainable market penetration rates, which exceed those proposed by U.S. regulators,” the report said. “Favorable regions include where 1) industry concentrates, 2) public and private funds have high leverage, 3) policy is supportive, 4) energy will cost less or 5) distributed grid modernization will occur.”
The Virginia State Corporation Commission last week ruled that Dominion Energy overstepped its authority in requiring distributed solar for large customers to go through new processes that led to spikes in the cost of installation.
The Virginia Distributed Solar Alliance filed a complaint against the new procedures in June, alleging they overstepped the regulated utility’s authority, as the SCC has been looking into the issues around interconnection of distributed sources in other cases. The SCC last approved interconnection rules back in 2020 and it is now looking at additional changes.
The commission on Aug. 30 agreed to suspend the parameters and interconnection agreements until it wraps up its open proceedings looking into the issues, but it declined to “address the myriad of additional relief” sought by the solar group.
The group’s other requests can be taken up in other proceedings, the SCC said. It also noted that it was not taking lightly Dominion’s claims about safety and reliability, but that it lacked authority to implement the new processes without a prior order.
“Dominion should continue to take the actions necessary to maintain the immediate safety and reliability of its system; this may include, but need not be limited to, seeking specific authority from this commission in one or more formal proceedings,” the commission said.
The utility adopted new parameters for projects between 250 kW and 1 MW and projects that range from 1 to 3 MW in December 2022, but the solar group’s complaint focused on their impact on projects below 1 MW, which are midsized, nonresidential projects. The complaint alleged that the new rules have led to costs, delays and barriers to adding such distributed generation around Virginia.
The rules that were suspended by the SCC led to “unprecedented” costs and delays by potentially requiring distributed solar to pay for substation upgrades and dark fiber cable and relay panel equipment. Dark fiber costs between $150,000 and $200,000/mile; relay panels can cost $250,000 for equipment and potentially more than double that for engineering, mobilization and construction management.
The complaint listed a number of anecdotes, including one at the James River Juvenile Detention Center for Henrico County, where Dominion estimated $2.25 million in preliminary costs for a 686-kW system. Prince William County Schools faced similar costs on a 987-kW array it was planning. Both projects, and others owned by private firms, proved too expensive with the extra costs that Dominion assessed under the now-suspended rules.
Dominion had argued in a filing last month that it needs to update the rules as distributed generation has grown rapidly in Virginia since a law passed expanding its net energy metering program.
“As a result of these changes, more net metering generation, with higher capacity ratings, are now rapidly developing and penetrating the company’s electric power system,” the firm said. “The company has been tasked with integrating more net metering distributed energy resources, with higher capacity ratings, that are now permitted to produce up to 150% of the customer’s expected annual energy consumption.”
The parameters suspended by the SCC were meant to ensure Dominion’s ability to specify the equipment and technical specifications needed to establish safe and reliable interconnection, the company said.
MISO’s Independent Market Monitor took his concerns to stakeholders last week over what he deems unrealistic fleet assumptions in MISO’s long-range transmission planning.
MISO Independent Market Monitor David Patton delivered a presentation at an Aug. 31 long-range transmission plan (LRTP) teleconference to let stakeholders know he’s concerned MISO’s long-range transmission planning could upend market functions. He said the issue is serious enough for him to delve into MISO’s transmission planning matters when usually he’s confined to market matters.
“The performance of the market is greatly impacted by out-of-market investments … coordinated by MISO,” Patton said. He said overblown transmission investments can “fundamentally” affect locational marginal prices and ancillary services.
Patton said the capacity expansion prediction MISO is using to develop its second LRTP portfolio contains an overestimated amount of intermittent, renewable generation and an exaggerated amount of dispatchable generation retirements.
“Planning to that future, I think is highly problematic,” Patton said.
MISO would come up with a “very different set of future transmission needs” if it includes a more realistic fleet projection that includes battery storage, hybrid storage, and renewable resources and new natural gas generation, he said.
Patton’s criticisms are contained in this year’s State of the Market report. He also appeared in front of MISO board members to critique MISO’s transmission planning future. Board members have questioned Patton’s departure from markets into transmission planning. (See “LRTP Doubts,” MISO IMM Zeroes in on Tx Congestion in State of the Market Report.)
Minnesota Public Utilities Commission staff member Hwikwon Ham said he had serious concerns with Patton’s critique of transmission planning. He asked what’s keeping the IMM from weighing in on states’ integrated resource planning, because that also affects MISO markets.
Ham said MISO’s second LTRP portfolio’s assumptions are based directly on states’ emissions reductions plans.
“You are directly defying that outcome,” he said.
American Transmission Co.’s Bob McKee agreed MISO’s futures use “actual” state plans and planned retirements.
Patton said he wasn’t trying to question state directives. But he said his analysis shows a 2040 fleet mix that contains 108 GW less solar and wind resources than MISO is planning for. He said MISO states still could achieve their official emissions reduction targets even with the absent, hypothetical intermittent resources. Patton said he didn’t account for “announcements made by governors that may or may not make their way into legislation.”
MISO expects it will add 369 GW of new, mostly renewable resources by 2042, bringing its total installed capacity to 466 GW. However, only 202 GW of that capacity is accredited; staff assumes a declining effective load-carrying capability for the renewable additions. (See MISO: Long-range Tx Needed for 369 GW in Interconnections.)
Patton also said he found MISO’s forecast that it will have 29 GW of flexible resources — including green hydrogen, long-duration battery storage, small modular nuclear reactors and reciprocating internal combustion engines — highly unrealistic. He questioned whether those technologies will be commercially available by the 2040s.
Patton also said half of MISO’s 13 states don’t have definitive decarbonization mandates. He said MISO shouldn’t assume members don’t build dispatchable gas resources between now and 2030.
But some stakeholders said they viewed Patton’s view as more environmentally harmful and more expensive to ratepayers, because of an expansion of gas infrastructure. Some also said it was disrespectful for Patton to show up to a planning meeting so late in the game to advocate for a rethink of MISO’s transmission planning future.
Patton said he will make a point to participate in MISO’s LRTP benefit analysis going forward.
Sustainable FERC Project attorney Lauren Azar said she worried Patton’s transmission analysis based on a concern for the market is shortsighted because the market only sends short-term signal and doesn’t indicate “the type of grid we’re going to need in 2042, or even 2035.”
“MISO is [a] leader in the nation in building 20 years out,” Azar said.
But Patton warned about the dangers of overbuilding transmission based on a flawed view of future capacity.
“If we adopt a future that’s not realistic, I don’t think we can be confident in that,” he responded.
Southern Renewable Energy Association’s Andy Kowalczyk asked Patton to consider MISO may be running the risk of underbuilding the transmission system, which also would raise costs for ratepayers. He said he didn’t think battery storage would “absorb” the need for new transmission because it still needs to charge from and dispatch to the system.
Sustainable FERC Project’s Natalie McIntire said she was skeptical of Patton’s analysis that MISO states could achieve a dramatic, more-than-90% carbon reduction by 2042 while removing 108 GW of renewable energy from the equation.
But North Dakota Public Service Commissioner Julie Fedorchak said she thought it was worthwhile for Patton to question MISO’s fleet assumptions when the second LRTP portfolio could cost as much as $30 billion.
“We absolutely need more analysis instead of less,” she said.
Mississippi Public Service Commission consultant Bill Booth called for MISO to take a fresh look at its battery storage addition assumptions.
“This is an expensive endeavor. We cannot afford to build wasteful transmission. …These are costs that are going to be borne by ratepayers, and we need to make sure they’re necessary and needed and the best thing for the footprint,” said Kavita Maini, an energy consultant representing MISO end-use customers.
MISO Responds
MISO Vice President of System Planning Aubrey Johnson said MISO in the past has been accused of not “being big or bold enough in transmission planning,” especially in its 2011 multivalue transmission portfolio. He said MISO is embarking on “least regrets” long-range transmission planning.
Johnson reminded stakeholders that the LRTP portfolios are being developed to resolve major regional system issues, not ensure the interconnection of an additional 369 GW, or ensure a certain generation mix. He said MISO’s planning future is meant to reflect members’ resource planning.
“It’s not the goal to maximize transmission building, but to maximize the value of the transmission we recommend,” Johnson said. He added he’s confident MISO will advance the most valuable second LRTP possible.
FERC has ruled it’s appropriate for MISO to continue to preclude renewable resources from providing ancillary services in its markets, countering a solar trade group’s complaint.
FERC said the Solar Energy Industries Association (SEIA) didn’t present evidence that MISO’s policy of barring renewable output from ancillary services was producing unfair rates (EL23-28).
In an Aug. 31 order, the commission said much like its recent order authorizing MISO’s ban on wind and solar generation from supplying ramping capability, it remains the case that renewables rarely are the most economic choice to supply operating reserves because their locations exacerbate already binding transmission constraints. (See related story, FERC: MISO Can Ban Intermittent Resources from Providing Ramp.)
SEIA lodged the complaint early this year in part because of MISO’s effort to bar renewables from furnishing ramping. (See Solar Trade Group Challenges MISO Ban on Renewable Ancillary Services.) The group argued that MISO’s dispatchable intermittent resources are operationally capable of providing regulation service, spinning reserves and supplemental reserves and that MISO’s market rules today discriminate against some resources because they’re tailored to the large, centralized power plants of the past. It also said instating renewables’ eligibility for such services would foster competition.
But FERC said SEIA didn’t demonstrate that renewables “can reliably deliver the ancillary services they are cleared to provide to the MISO market in a manner comparable” with other resources.
The commission acknowledged MISO’s current market clearing software isn’t sophisticated enough to consider locations of resources and nearby congestion rendering them non-deliverable. It said if MISO were to clear operating reserves from renewable sources, congestion would prevent them from making it to market in most cases. Thus, allowing procurement would create a reliability issue and payments to unhelpful resources, FERC decided.
The commission also agreed with MISO that it’s far more lucrative for renewable resources to provide energy over ancillary services.
Lastly, FERC said SEIA’s arguments differed from the commission’s previous regulations requiring open access transmission service and establishing separate performance and capacity payments for frequency regulation service, and its ruling against the undue discrimination of electric storage resources.
“Those orders did not require that every resource type must be allowed to provide such services,” FERC said.
FERC said though it’s “undisputed” MISO’s tariff treats renewable and nonrenewable resources differently with respect to ancillary services, SEIA didn’t prove that renewable and nonrenewable resources are “similarly situated” because when renewables are cleared to provide ancillary services, they’re trapped behind a transmission constraint.
As with their order blocking MISO renewables from providing ramp capability, Chairman Willie Phillips and Commissioner Allison Clements issued a joint statement to emphasize that the order was limited. The two said MISO’s market dynamics are set to change — and the snub likely will be temporary — as renewable energy becomes more prevalent.
“We strongly urge MISO to continue to improve and enhance the software on which its markets rely. Both MISO and the commission recognize the limitations of MISO’s current software, and the record suggests that these shortcomings are contributing to problems that go beyond [renewable] integration alone,” Phillips and Clements wrote. “We anticipate the continued development of these resources and encourage MISO to be ready for them as they come online.” They said MISO should devise ways to account for locational congestion in its software when selecting resources.
CAISO is planning ahead for a solar eclipse that will abruptly slash solar power across much of California the morning of Oct. 14.
CAISO successfully managed the drop in solar output during a total eclipse on Aug. 21, 2017. But since then, grid-scale solar within the CAISO footprint has increased from 10,000 MW to 16,500 MW. (See Grid Operators Manage Solar Eclipse.)
And behind-the-meter solar has grown from 5,700 MW to 14,350 MW.
“The October 2023 eclipse will be more impactful than the 2017 eclipse because of the growth in solar capacity since 2017,” CAISO said in a technical bulletin issued last week.
In response, CAISO has scheduled a series of meetings — including a workshop on Sept. 5.
Outreach to Western Energy Imbalance Market entities is planned, as CAISO said coordination across the WEIM is critical to ensure optimal market dispatch during the eclipse.
CAISO is planning additional reserve procurement, a step it also took to prepare for the 2017 eclipse. The ISO will consider restricting maintenance operations around the time of the eclipse, to reduce the risk of an “inadvertent issue” occurring during maintenance work.
Another option would be to implement a Flex Alert or activate demand response programs during the eclipse. CAISO said it probably won’t need to do that, “due to the eclipse occurring on a weekend when loads are typically lower.”
Blocking the Sun
During the so-called Great American Eclipse in August 2017, grid-connected solar generation in CAISO territory dropped by more than 3,500 MW in about an hour. CAISO replaced the lost solar power with electricity from imports, hydropower and natural gas power plants. Consumers conserved electricity during the eclipse to relieve stress on the grid.
The 2017 eclipse was on a Monday, from about 9 a.m. to noon in California.
In contrast to that eclipse, the event on Saturday, Oct. 14, will be an annular eclipse, in which the moon will block much of the sun but leave an outer ring.
Large parts of Oregon, Nevada, Utah and New Mexico, and small parts of California and Arizona, will see the maximum impact of next month’s eclipse, with about 90% of the sun obscured. Much of California will see lesser amounts of sun obscuration, in the 70% to 80% range.
The Oct. 14 eclipse will last from about 8:05 a.m. to 11 a.m. in CAISO territory. At the peak, around 9:30 a.m., grid-scale solar generation will drop to 12% to 23% of capacity, CAISO said. Solar production won’t be completely cut off, but will fall to a low of about 3,023 MW at 9:26 a.m.
Output will also be reduced for behind-the-meter rooftop solar, leading to increased load. The maximum impact to load will be a 4,843-MW increase at 9:15 a.m., compared with normal clear-sky conditions, according to CAISO’s forecast.
Because the eclipse will occur on a Saturday, loads will be lighter than they would be on a weekday.
Ramp-up Concerns
One of CAISO’s concerns is the steep ramp up in solar power after the eclipse peaks. The eclipse will end just as solar sites are reaching their midday production maximum, the ISO noted.
“The period after the eclipse maximum to the end of the eclipse … is the period of operational interest the CAISO will study to ensure adequate supplies of generation [reserves] are available to mitigate any adverse effects of the anticipated steep up-ramp in solar production,” CAISO said in its technical bulletin.
CAISO said it will coordinate with hydro and battery resources to help with potentially large ramps.
The bulletin models eclipse impacts on a clear-sky day, which CAISO said represents a “high impact” scenario. Impacts will be less if Oct. 14 is a cloudy day.
CAISO plans to send out messages through its market notification system before and during the event.
“This message is to serve as a reminder that the solar eclipse will take place on Oct. 14, 2023, from 8:05 to 11:05 PDT,” one sample message reads. “This is a unique event for the ISO BA, during which approximately 9,700 MW of solar generation will rapidly go away and then return within the span of less than three hours. Your cooperation and support throughout the event will help to ensure grid reliability.”
In light of stressed-out supply chains and a bogged-down study process, MISO has agreed to re-evaluate its rules around commercial operation dates in its interconnection queue.
Stakeholders and staff plan to discuss extending the grace periods around commercial operation dates at upcoming meetings of the Interconnection Process Working Group (IPWG).
MISO policy requires its interconnection customers’ generator interconnection agreements (GIAs) contain a commercial operation date that’s within three years of the date originally requested in their queue applications. MISO additionally allows an up to three-year extension of the commercial operation date in the initial GIA. When customers can’t meet either, MISO can terminate the GIA and generator developers lose their place in line unless they can secure a waiver of their commercial operation dates from FERC.
Last week, EDP Renewables’ David Mindham said supply chain troubles and delays in MISO’s studies of generation projects mean that projects regularly take longer than the allotted six years from originally planned commercial operations and often require FERC waivers, which create uncertainty.
Mindham raised the issue at the Aug. 30 meeting of the Planning Advisory Committee, which ultimately assigned the issue to the IPWG for consideration.
Mindham said MISO should consider extending its COD deadlines in its Tariff so they’re feasible. He said transmission owners often don’t have network upgrades ready until well into the second extension. Mindham said current wait times for equipment like breakers can last three and a half years and “eat away at the three-year grace period.”
“There are dozens of these projects that will require FERC waivers. This problem doesn’t seem to be going away. If anything, it seems to be getting worse on the transmission owners’ end, and it’s going to take several years for that to get caught up,” he said. “… The commercial operation date should have some meaning. It should be a date that developers can reasonably meet.”
Multiple MISO interconnection customers have sought commercial operation date waivers with FERC since the pandemic began and strained supply chains. Mindham said an extension could cut down on the need for developers to seek future waivers.
LAS VEGAS — The stars may not yet have aligned in favor of CAISO in the contest to bring an organized electricity market to the West, but key players in the industry appeared to be doing just that last week at an ISO event to celebrate the progress of its Extended Day-Ahead Market (EDAM).
Wednesday’s EDAM Forum at Resorts World on the Las Vegas Strip attracted 240 in-person attendees and about 300 participants online, a CAISO official said. The packed agenda included a CEO roundtable, a panel of Western utility commissioners, an in-depth presentation on potential EDAM benefits and a discussion about evolving markets in the West.
The ISO convened the forum just a week after CAISO submitted to FERC its EDAM tariff and associated day-ahead market changes designed to increase rewards for flexible resources and reduce load imbalances between the day-ahead and real-time markets. (See CAISO Files EDAM Proposal with FERC.)
And, accidentally or not, the event also coincided with two important developments.
The first was a notice issued by the coalition of utility regulators who this summer proposed the creation of a Western RTO that would be independent of CAISO’s governance while still building on the ISO’s Western Energy Imbalance Market (WEIM) and the EDAM. The document outlined an aggressive timeline for developing the governing framework and seating a board of directors for the new entity, signaling that the backers are moving urgently to build a market structure that ensures the participation of California and increases the likelihood of a single, seamless Western market. (See Backers of Independent Western RTO Seek to Move Quickly.)
The second was the Balancing Authority of Northern California’s (BANC) announcement that it will advise its publicly owned utility members to join the EDAM over SPP’s competing Markets+ day-ahead offering. Accompanying that was a parallel announcement that the board of BANC’s largest member, Sacramento Municipal Utility District, approved the utility’s request to join the EDAM. (See BANC Moving to Join CAISO’s EDAM.)
Scott Miller, executive director of the Western Power Trading Forum, expressed surprise at what he saw at the event.
“This really changes the calculus of my thinking around” Western markets development, Miller told RTO Insider immediately after the forum concluded.
“It was the general positivity — even from CEOs whose folks are involved in Markets+ — that struck me as interesting,” Miller said later in an email. “The fact that a ‘shared governance of EDAM with CAISO’ might be acceptable was a bit of a shift, although the shared governance might prove a problem in an RTO setting where transmission operations are turned over to the RTO.”
‘Tremendous Benefit’
During the CEO roundtable, Pacific Power CEO Stefan Bird explained why the utility’s parent, PacifiCorp, the first entity to join the WEIM in 2014, also decided to become the first participant in the EDAM.
“We want to use as much renewable power that’s free — has no fuel cost — as much as possible and avoid those emissions,” he said.
“I was part of that group running around the West, I don’t know, 10-plus years ago, and dreaming about … how cool it would be if we could just coordinate better and be more efficient in how we leverage the abundance that we have across the West, and so proud of how far we’ve come and excited about the next steps,” Bird said.
Idaho Power CEO Lisa Grow offered “profound thanks” to CAISO for developing the EDAM.
“I have been in this industry for 36 years, and I have participated in every single effort we’ve had to create an RTO, or some sort of organized market, and we just never quite got there,” she said. “I think that the demonstration that we can take incremental steps is the only thing that we’ve seen work.”
Grow said the industry’s transition to clean energy will require the region to “optimize the system we have.” She also questioned whether there’s a need for a full RTO — at least in the near term.
Idaho Power doesn’t “have legislative or PUC-mandated things that we have to do towards an RTO, so we can kind of watch how this goes,” she said.
NV Energy CEO Doug Cannon gave a “shoutout” to CAISO for its responsiveness in developing a WEIM rule change that allows a participant that fails the market’s resource sufficiency test during a trading interval to acquire energy within the market rather than just being shut out.
“That’s a tremendous benefit,” Cannon said. “What we were concerned about is, you’ve got somebody who’s already kind of down. Why are we pushing them further down by not letting them get access to this broader market? Instead, as a West, let’s come together and give that person an option to pick [energy] up. Now, they have to carry their weight, they’ve got to pay the price, but let’s help them through that challenging time. And the California ISO came to the table and helped deliver product that really helped there.”
Jacob Tetlow, executive vice president of operations at Arizona Public Service, said “this summer has been incredibly challenging for us.” The summer featured a 30-day stretch of temperatures exceeding 110 degrees Fahrenheit in Phoenix, leading the utility to smash its previous peak load record of 7,600 MW by nearly 600 MW.
“To me, the Energy Imbalance Market is a very helpful tool. It creates liquidity in the market. It puts resources in that might not have otherwise been available. That’s an efficiency gain,” Tetlow said.
But Tetlow also cautioned that the WEIM can’t be relied on as a resource adequacy tool, given that the market’s operations cut some of APS’ hour-ahead schedules and low-priority transmission in July.
“So, it absolutely helps, but it can’t be the tool to make sure you’re resource sufficient for your customers,” he said.
“No market is actually a substitute for a solid foundation of resource adequacy,” said CAISO CEO Elliot Mainzer. “RA — that’s the bottom foundation layer. And that’s why it’s so important for all of us to be taking those steps to get to solid resource adequacy to meet those planning standards. The market really is an optimization tool.”
Mainzer pointed to instances in July and August when it was “kind of hot everywhere” in the West, and the bilateral day-ahead market did not provide enough liquidity to cover all the short positions heading into real time in the WEIM.
While some low-priority exports had to be curtailed, he said, “we were then able to work together to foster maximum liquidity into the hourly markets, and then we were able to sit there and watch the Energy Imbalance Market cycling power across the West, particularly most of it heading certainly not California’s direction, [but] at that point in certain places that were really on the edge.”
Solving for The ‘Future Everything’
Of the CEOs participating in the roundtable, the Bonneville Power Administration’s John Hairston was the most reserved in his assessment of CAISO, the WEIM and the EDAM.
While Hairston acknowledged BPA has seen benefits since joining the WEIM in 2022, he also alluded to a running complaint among Northwest hydroelectric producers that the market undervalues the attributes of their resources. He said the agency’s portfolio of 31 hydroelectric dams is a “foundational piece to the clean energy transformation” in the West because of its flexibility and lack of greenhouse gas emissions.
“Hydro is highly responsive, so as you add renewables to the resource mix, you’re going to have to have that instantaneous response,” he said. “And so how we manage the system and reserve it is going to be critically important. And how we also allocate it to markets — participate in markets — will also allow us to figure out how to optimize this incredible resource for attacking climate change and dealing with meeting these renewable portfolio requirements in the most efficient manner.”
When BPA this summer embarked on a public process to determine whether to join the EDAM or Markets+, it signaled that its near-term decision on a day-ahead market could hinge on a longer-term evaluation of joining an entity that — unlike CAISO — promises a governance structure that meets the federal agency’s statutory requirement for independence. (See Regulators Propose New Independent Western RTO.)
“When we joined EIM, we were really clear,” Hairston said. “We came out of our public process and said the governance structure was sufficient but wasn’t preferred. The joint authority model [with the CAISO and WEIM boards sharing decisional authority] has worked, but at the end of the day is not independent, and that’s what we’re looking for in this next step.”
Hairston said he “applauded” Western regulators for putting out an independent RTO proposal “that has some legs,” but said the process will be “complex.”
“We need answers now around governance,” he said.
“I get that we have unanswered questions,” Grow said. “I think we have to be careful not trying to solve for the future everything, because it will collapse under its own weight.”
“The governance issue is a tricky one,” said Jim Shetler, general manager of BANC, which sits squarely inside CAISO as a separate BA. “I like to say we’ve lived in the belly of the beast for the last 25 years and we’ve learned to figure out how to manage that.”
“I also like to say I think the ISO today is a very different animal than the ISO 20 years ago. Clearly a much more collaborative organization,” Shetler said.
Mainzer attempted to drive that point home in his remarks wrapping up the forum.
“We’re just super-motivated to make sure that people feel that they can walk away from a CAISO stakeholder process and say, ‘Look, that is really fabulous, and we feel heard, and we feel acknowledged,’” he said.
He also gave a nod to the regulators’ RTO proposal, acknowledging that for many Western stakeholders, the “pathway to independent governance is a critical success variable.”
“And I’m just appreciative of the work of our regulatory community, to start taking this issue on with seriousness and obviously recognize the importance of getting the right people at the table, open and transparent,” he said.
AUSTIN, Texas — ERCOT last week announced two leadership changes it said would “sharpen our focus on daily operations” as it battles near-daily tight grid conditions.
The grid operator said in a Friday press release that Woody Rickerson, previously vice president of system planning and weatherization, has been promoted to senior vice president and COO. He will be responsible for grid operations, weatherization, planning and commercial operations.
“This new position will leverage Rickerson’s deep operations experience and support ERCOT’s continued investments in grid innovations,” ERCOT CEO Pablo Vegas said in a statement.
Kristi Hobbs, newly named vice president of system planning and weatherization, will handle some of Rickerson’s previous responsibilities. She will oversee transmission planning, generator interconnection activities, training and weatherization, and will report directly to Rickerson.
The promotions, both effective immediately, come after ERCOT made six appeals in seven days for voluntary conservation Aug. 24-Aug. 30. The grid operator has recorded 10 all-time peak records this summer. However, it has encountered tight conditions during the early evening, when solar power ramps down and wind resources, which generally contribute less than solar during the summer, try to fill the gap. (See ERCOT Continues to Rely on Voluntary Conservation.)
“As our industry faces dynamic changes, ERCOT is continuously evolving and making the necessary improvements to the grid to support the needs of a growing population and robust economy,” Vegas said
The announcement came the day after ERCOT’s Board of Directors re-ratified Rickerson and Hobbs as officers during its bimonthly meeting.
In two other organizational changes, Chief Compliance Officer Betty Day was given oversight of business continuity and Rebecca Zerwas named director of state policy and Public Utility Commission relations and a board liaison.
ERCOT has been operating without a COO since Cheryl Mele left ERCOT and the position in 2019. She now is vice president of customer care and corporate communications at El Paso Electric.
NPRR1186 Remanded to TAC
The board remanded back to the Technical Advisory Committee a nodal protocol revision request that has drawn opposition from the storage community.
The directors asked that stakeholders and staff address only unusual scarcity situations raised by Eolian, a storage developer that appealed TAC’s approval of NPRR1186. Eolian asked that ERCOT be directed to resubmit new NPRRs to determine batteries’ state-of-charge (SOC) parameters and related compliance obligations. (See “SOC Transparency,” ERCOT Technical Advisory Committee Briefs: Aug. 22, 2023.)
Eolian COO Stephanie Smith called for scarcity events to be carefully defined, “ideally with reasonable amounts of study to ensure no further unintended consequences to the market.” She said NPRR1186’s requirement that batteries meet an SOC obligation at the top of the hour will negatively affect reliability and counter the benefit multi-hour batteries provide.
“We don’t yet know whether there will be cost implications to consumers or if it will create grid conditions that lead to reliability concerns or events,” Smith said. “Unfortunately, we don’t always start at the top of an hour and even though we have hourly products, we don’t want all batteries charging at the same time to meet a requirement … that could lead to unintended consequences, especially during tight conditions.”
NPRR1186 also adds definitions and telemetry requirements related to SOC information that date back to 2018 and introduces a requirement that qualified scheduling entities (QSEs) representing an ESR telemeter the next operating hour’s ancillary service (AS) resource responsibility. It also specifies that QSEs are expected to manage the SOC to ensure that each ESR has sufficient energy to meet its AS responsibilities and that the day-ahead market process should begin to respect the AS award limits for ESRs based on duration requirements.
Staff says the measure provides a necessary, cost-effective interim solution to improve the awareness, accounting and monitoring of SOC before the Real-time Co-optimization + Batteries project finishes its work in 2026. As of June 1, ERCOT says there were about 3.3 GW of batteries energized on the system. That total could grow to 9.5 GW by October 2024 should interconnection queue projects with signed agreements and posted security join the grid.
Rickerson and other ERCOT executives said NPRR1186 simply allows them to see how much energy batteries have stored and whether that’s enough to meet their commitments.
“We have a reliability issue today … we want to use batteries. Batteries are the future,” Rickerson said. “But we can’t keep buying a service that isn’t always capable of being delivered. [NPRR1186] will fix that and allow us to get to this power over time.”
Vegas: Environmental Regs a Threat
Vegas reviewed for the board five environmental regulations with overlapping timelines that, when taken together, he said could have serious unintended consequences for the grid during peak demand periods.
“Many of these rules do apply to [thermal] resources,” he said. “They have to understand whether they comply with one, two, three or combinations. It’s a very complex system that could lead to very, very detrimental decisions.”
ERCOT’s generation fleet is reckoning with five recent regulations from EPA:
The coal combustion residuals (CCR) rule that regulates CCR disposal at inactive generating units and establishes groundwater monitoring, corrective action, closure and post-closure care requirements.
The greenhouse gas rule that proposes significantly lower carbon dioxide emissions for coal and gas units.
The Clean Air Act’s Good Neighbor Rule that lowers state-level nitrogen oxides from thermal units to mitigate pollutants to downwind states.
The Mercury and Air Toxics Standard rule that proposes particulate matter emissions standards for coal-fired generators and mercury emissions standards for lignite-fired generators.
Texas’s regional haze federal implementation plan that recommends new limits on sulfur dioxide and particulate matter emissions to meet air-visibility requirements at national parks and wilderness areas.
“We all need to keep in mind the compound nature of stacking multiple rules on top of each other because it’s pretty deadly when you’re the owner and private investment decisions need to be made,” board Vice Chair Bill Flores, a former U.S. representative, said. “It’s important for the Texas consumer to know that we’ve got 72 GW, over half of our fleet today, are these plants. These rules take a substantial amount of that offline within the short-term period, and there’s no replacement that provides reliable, cost-effective power.”
Vegas said ERCOT has filed comments on all five rules and has scheduled a meeting this week with EPA and U.S. Department of Energy “to continue that dialogue.”
“We are actively engaging with the Department of Energy and the EPA to make sure that they understand our risks as operators on the system,” he said. “We’re obviously continuing that dialogue with them so that they clearly understand that it’s not just a Texas issue, it’s a U.S. issue as the entire grid is transforming.”
The Good Neighbor Rule is not effective in Texas, Louisiana and Mississippi after the U.S. 5th Circuit Court of Appeals issued a stay in May. The court is not expected to make a final ruling until next year.
San Antonio Tx Projected OK’d
The board approved a $329 million reliability project in the San Antonio area that previously had been endorsed by TAC. The CPS Energy project addresses thermal overloads in South San Antonio and has been designated as a Tier 1 project because of its estimated capital costs of $100 million or more.
In other actions, the board also:
Authorized the creation of the Technology and Security Committee to provide oversight of technology-related functions and physical and cyber security initiatives and committee assignments for the board’s members. Director John Swainson will chair the committee, the board’s fourth.
Approved a date change for ERCOT’s annual meeting of members to Dec. 18, when the board’s committees will meet. The change, from Dec. 19, resolves a conflict with the full board’s meeting.
Board Approves 30 Rule Changes
The directors endorsed 30 revisions requests covering the three TAC meetings since the board last met. With the exception of an other binding document revision (OBDRR048) that sets two price floors for the operating reserve demand curve (ORDC), they all passed unanimously.
Office of Public Utility Counsel CEO Courtney Hjaltman abstained from voting on OBDRR048, which was opposed by all six members of TAC’s consumer segment. The measure adds price adders to the operating reserve demand curve of $20/MWh and $10/MWh that will come into play when operating reserves hit floors of 6,500 MW and 7,000 MW, respectively.
The PUC approved the ORDC revisions, designed as a bridge to the PUC’s proposed performance credit mechanism market structure, in August. (See Texas PUC Approves ERCOT’s ORDC Modifications.)
The board unanimously approved two other OBDRRs, 13 NPRRs, seven changes to the nodal operating guide, two revisions to the planning guide (PGRRs) and the resource registration glossary (RRGRRs) and single modifications to the retail market guide (RMGRR) and verifiable cost manual (VCMRR). They include:
NPRR1150: requires qualified scheduling entities (QSEs) that represent resource entities, emergency response service resources or other QSEs, and that receive or transmit wide-area network (WAN) data to maintain connections to the ERCOT WAN and a secure private network.
NPRR1163, LPGRR070: discontinue the process of evaluating interval data recorder meters to determine whether any are weather-sensitive.
NPRR1164: requires resource entities to identify whether a resource has the potential capability, even if unverified, to be called upon or used during a black start emergency or if it has the capability for isochronous control. It also would require resource entities and transmission service providers to identify if a breaker or switch has a synchroscope or synchronism check relay and would define the terms black start-capable resource, isochronous control capable resource, synchroscope and synchronism check relay.
NPRR1165: strengthens market entry eligibility and continued participation requirements for QSEs, congestion revenue right (CRR) account holders and other counterparties by removing minimum capitalization requirements; requiring counterparties to post independent amounts’ remove references to guarantors; clarifying financial statement requirements; and referencing International Financial Reporting Standards rather than retired International Accounting Standards.
NPRR1171, NOGRR250: clarify various reliability requirements for distribution generation resources and distribution energy storage resources seeking qualification to provide ancillary services and/or participate in security constrained economic dispatch (SCED).
NPRR1173: accounts for Texas standard electronic transaction processing options for municipally owned utility or electric cooperative service areas in the protocols.
NPRR1174: establishes a process allowing QSEs or CRR account holders to return overpayment settlement funds to ERCOT.
NPRR1175: strengthens market entry qualification and continued participation requirements for ERCOT counterparties like QSEs and CRR account holders, classifies information in the background check as protected information, modifies application forms for QSEs and CRR account holders, and add a new background check fee to the grid operator’s fee schedule.
NPRR1176, NOGRR252: revise the Energy Emergency Alert (EEA) procedures to require a declaration of EEA Level 3 when physical responsive capability (PRC) cannot be maintained above 1,500 MW and require ERCOT to shed firm load to recover 1,500 MW of reserves within 30 minutes. The NPRR also would modify the trigger levels for EEA Level 1 and EEA Level 2, change the trigger for ERCOT’s consideration of alternative transmission ratings or configurations from advisory to watch when PRC drops below 3,000 MW and restore a frequency trigger for the EEA Level 3 declaration if the steady-state frequency drops below 59.8 Hz for any period of time.
NPRR1182: incorporates controllable load resources and energy storage resources (ESRs) into the constraint competitiveness test’s (CCT) long-term and SCED versions. Controllable load resources will not be mitigated but will be used to identify whether a market participant has market power in resolving a transmission constraint; other resources’ registration data will be used in the long-term CCT process, and real-time telemetry will be used in the SCED CCT process.
NPRR1183: revises rules for and make publicly available on ERCOT’s website general information documents that don’t include ERCOT critical energy infrastructure information (ECEII), remove a reference to the Freedom of Information Act from the ECEII’s definition and remove antiquated or duplicative language related to reliability must run.
NPRR1185: adds a provision for recovery of a demonstrable financial loss arising from a verbal dispatch instruction to reduce real power output.
NPRR1189: changes NPRR1136’s gray-boxed language to align it with existing requirements for ancillary services that resources can provide fast-response service only if awarded regulation service in the day-ahead market for that resource.
NOGRR215: allows new remedial action schemes to address only actual or anticipated violations of transmission security criteria when market tools are insufficient and clarify the procedures for retiring schemes.
NOGRR230: ensures the WAN data transmission’s integrity by requiring data be shared in a manner that prevents denial of service and distributed denial-of-service attacks.
NOGRR247: increases the under-frequency load shed (UFLS) program’s load-shed stages from three to five and changes the transmission operator load-relief amounts to uniformly increment by 5% for each stage, adds a UFLS minimum time delay of six cycles (0.1 seconds) and adds 59.1 Hz to the list of UFLS stages and revises the gray-box language from NOGRR226 to provide that the transmission owners’ load value used to determine load at each frequency threshold will be the TO’s load at the time frequency reaches 59.5 Hz.
NOGRR249: specifies methods for TOs to receive electronic communication of system operating limit exceedances.
NOGRR251: adds cold weather conditions to the template used for developing emergency operations plans to align with NERC Reliability Standard EOP-011-2 (Emergency Preparedness and Operations).
OBDRR045: edits the demand response data definitions and technical specifications, including modifications to the electric service identifiers list provided to retail electric providers.
OBDRR047: clarifies treatment of unused funds from previous emergency response service standard contract terms.
PGRR103: requires interconnecting entities to complete all conditions for commercial operation of a generation resource or ESR within 180 days of receiving ERCOT’s approval for initial synchronization.
PGRR108: updates language to reflect the current practice of posting regional transmission plan and geomagnetic disturbance assessment plans and update data sets.
RMGRR174: updates language to reflect the current practice of posting regional transmission plans and geomagnetic disturbance assessment plans and update data sets.
RRGRR033: adds data to the resource registration glossary pursuant to NPRR1164.
VCMRR034: provides that actual fuel purchases used to determine the reliability unit commitment guarantee will not be included when calculating fuel adders.
FERC last week approved transmission incentives for Missouri River Energy Services’ share of the Big Stone Project in Minnesota and South Dakota.
The wholesale power agency provides power to 61 member municipalities that own and operate their own distribution systems in Iowa, Minnesota, North Dakota and South Dakota. The MISO member is responsible for two segments of the Big Stone Project, which is a Multi-Value Project approved under the grid operator’s 2021 transmission expansion plan.
The first part of the line Missouri River is building is 345 kV and runs about 100 miles from South Dakota into Minnesota along a new right of way, while the second part also is 345 kV, but largely will be built on existing rights-of-way in Minnesota. Both segments involve related upgrades to substations, and the firm is working with Otter Tail Power.
Missouri River expects to spend $285.6 million on its half of the project, which will relieve reliability issues on the 230-kV system and improve connections between 345-kV systems.
The power agency asked for and got hypothetical capital structure, construction work in progress and abandoned plant incentives, plus a 50-50 equity and debt capital structure. To implement those incentives, the firm asked for and got some changes to MISO’s tariff.
The transmission investment is the largest ever made by Missouri River, representing 221% of the $129.5 million of its projected net transmission plan this year and 48% of its long-term debt. Coordinating the line’s permitting with multiple owners also will prove to be more complex.
“We find that Missouri River has demonstrated that the requested incentives are tailored to the risks and challenges faced by the Big Stone Project,” FERC said. “We also find that the approval of the hypothetical capital structure incentive and CWIP incentive will bolster Missouri River’s financial metrics, help ensure maintenance of its current credit rating and enable its participation in the Big Stone Project.”
Missouri River asked for the abandoned plant incentive because the project could fail due to no fault of its own, such as negotiations for construction and operations and maintenance agreements between partners with different business models. It also faces regulatory risks as it crosses two states and will require a federal environmental impact statement.
FERC granted the abandoned plant incentive, agreeing that it will help cut the risk of non-recovery of costs in the event the project is abandoned for reasons outside Missouri River’s control.
Commissioner Mark Christie filed a concurrence, saying that while the project met FERC’s existing requirements for transmission incentives, it was time to examine them generally. Christie has made the same point before on other orders involving transmission incentives.
“As this commission considers other potential reforms related to regional transmission planning and development, it is imperative that incentives like the CWIP incentive, abandoned plant incentive and RTO participation adder are all revisited to ensure that all the costs and risks associated with transmission construction are not unfairly inflicted on consumers while transmission developers and owners stand to gain all the financial reward,” Christie said.
