VALLEY FORGE, Pa. — State advocates would like to see more details when supplemental transmission projects are proposed to the Transmission Expansion Advisory Committee (TEAC), Greg Poulos, executive director of the Consumer Advocates of the PJM States (CAPS), said in a presentation to the committee on Tuesday.
The data currently provided by transmission owners tends to be inconsistent and lacking enough information to allow for proposal of alternatives, Poulos said.
“I’d like to get that information in a way that’s most efficient” for transmission owners and advocates, he said.
In particular, he pushed for a breakdown of project costs beyond an overall estimate; increased clarity about whether a project falls under state jurisdiction; and the inclusion of contact information for a TO’s relevant planning staff.
He also argued that the long period of time between the presentation of a need and a proposed solution suggests the timeframe for submitting alternatives could be lengthened. Currently, comments and alternatives must be submitted within 10 days, which Poulos said is inadequate if there are follow-up questions about a proposed project or for a prospective developer to evaluate a need and create a solution.
Tom Schmidt, principal planning engineer at Buckeye Power, said alternative proposals are welcome, especially when expensive repairs are needed, but they’re not always feasible for a variety of reasons, such as when equipment fails. He noted that TOs provide a spectrum of information on projects, often providing a large amount of documentation.
“Some have plenty of details to support their spending and others it seems a little bit lighter,” he said.
No Plan to Extend Accreditation Uprate Study Application Deadline
PJM’s Pauline Foley told the committee that the RTO does not plan to lengthen the application period for generators to seek temporarily higher accreditation while PJM transitions to the modified effective load-carrying capability (ELCC) methodology FERC approved last week. The studies allow an existing or planned generator that is re-entering the transmission queue in order to increase its capacity interconnection rights to undergo annual transitory studies to determine if it can temporarily increase its capacity rating by utilizing existing transmission headroom. (See FERC Approves Revisions to PJM’s ELCC Accreditation Model.)
In its order accepting the ELCC changes, the commission recommended that PJM consider leaving applications open longer should it seek a delay to the 2025/26 Base Residual Auction, currently scheduled for June 2023. PJM filed with FERC to make that delay on April 11. (See PJM Seeks to Delay Capacity Auctions Through 2028 Delivery Year.)
Protests against the ELCC filing argued that PJM’s original intention of setting applications to close on March 3 violated noticing requirements under the Federal Power Act and left insufficient time for generators to make complicated decisions about unit accreditation. In a dissent, Commissioner Allison Clements agreed with those concerns and said the majority’s decision to allow applications through April 10 was also insufficient.
Foley told the PC that extending the application period would not conform to stakeholders’ intentions when they endorsed the filing’s language.
Reliability Analysis Update
Dominion (NYSE:D) proposed a $7.7 million upgrade to address a 300-MW load drop violation in the 2027 Regional Transmission Expansion Plan around the area of Dulles International Airport in Virginia.
The upgrade would cut the existing Brambleton-Poland Road 230-kV line and create a new 0.59-mile-long, double circuit 230-kV line between the Brambleton and Evergreen Mills substations. Both original substations would remain connected.
INCLINE VILLAGE, Nev. — Speakers debated whether the West would benefit more from the one day-ahead market run by CAISO or with another run by SPP at last week’s meeting of the Committee on Regional Electric Power Cooperation and the Western Interconnection Regional Advisory Body.
The spring CREPC-WIRAB meeting took place as CAISO is drafting tariff language to add an extended day-ahead market (EDAM) to its real-time Western Energy Imbalance Market (WEIM) and SPP is developing its Markets+ program with a day-ahead market as its centerpiece. (See SPP: 31 Entities Join in Markets+ Development.)
Advocates for a CAISO-led day-ahead market and others backing SPP spoke on two panels Wednesday at the Hyatt Regency Lake Tahoe Resort, where Western regulators and stakeholders filled a large meeting room to capacity.
“Markets give us affordable and reliable energy through breadth, depth and transparency,” said Ric O’Connell, executive director of GridLab, a nonprofit technical advisory firm in Berkeley, California. “We need a market that’s broad enough to capture resource and load diversity, and we need a market that’s deep and liquid so that there’s a lot of energy traded in that market, either in real-time or in the day-ahead.”
A Western day-ahead market without California would lack those attributes, O’Connell said.
“California has close to half the load of the West,” he said. “California has massive transmission connections both to the Pacific Northwest and to the Desert Southwest, and it’s been trading with [entities in those regions] for decades … so I would posit that a Western market that does not include California is going to lack the breadth and depth that we need to unlock the benefits of affordable and reliable energy in the West.”
The Western Energy Imbalance Market encompasses 80% of load in the Western Interconnection and has achieved $3.4 billion in benefits for its participants, including $1.5 billion last year alone, he said.
“We have huge potential to increase those benefits if we move to a day-ahead market that covers that same 80%,” and even more if CAISO were to lead a Western RTO, he said.
Having two markets in the West and bifurcating those benefits would be a step backward, O’Connell said.
‘A Swiss Cheese Universe’
In a subsequent panel, Stefan Bird, CEO of PacifiCorp division Pacific Power said the benefits of CAISO’s WEIM are proven and substantial.
PacifiCorp co-founded the interstate trading market with CAISO in 2014 and was the first utility to commit to joining EDAM in December. The utility serves 2 million customers in California, Idaho, Oregon, Utah, Washington and Wyoming. (See PacifiCorp to Join EDAM, Final Plan Released.) The company is so far not among the 31 utilities and industry groups that have officially signed on to SPP’s effort to develop a Western market.
“It doesn’t matter if we’re in our red states or blue states. We save money, improve reliability and reduce emissions [through the WEIM],” Bird said. “It’s not theory. This is the real deal.”
PacifiCorp has derived nearly $600 million in benefits as a WEIM participant, much of it by buying cheap solar power from California and other Western states, he said.
“Prior to the EIM existing, we wouldn’t have been able to take advantage of all that low-cost solar that was being deployed very rapidly in California [without] enough load in California to use it all,” Bird said. “The alternative in California was to curtail it. But for the EIM being able to trade very rapidly intra-hour — as opposed to the old days [when grid operators would] pick up the phone and try to make trades on an hourly basis — that simply wasn’t possible.”
PacifiCorp has reduced its greenhouse gas emissions by 42.6 million metric tons since 2014 because it does not need to run its fossil fuel-burning plants as much when renewable power is available through the WEIM, he said.
“The morning sun comes up with all that solar energy in Utah and southern Oregon and California, Bird said. “We’re taking every bit of it we can, and we back off our coal fleet, our gas fleet. We’re not incurring those fuel costs. We’re not burning the emissions, and we save our customers money.”
“We don’t want to see those benefits disappear or get broken, and that’s precisely what’s being contemplated in a separate [SPP day-ahead] market that would be created on top of [the WEIM’s] footprint,” Bird said.
Having two day-ahead markets in the West would produce seams problems between balancing areas and provoke “situations of conflict where a peace treaty has got to be negotiated, and that’s going to take years,” he said.
It would be “a Swiss cheese universe that I think would really put a dent in those [WEIM market] benefits that are most important to us,” Bird said.
Independent Governance
Tom Bechard, CEO of Canadian energy marketer Powerex, said the seams issue was being overblown by those in favor of a CAISO-led day-ahead market. Powerex has been a WEIM member since 2018, but Bechard’s comments reflected a preference for SPP’s Markets+.
“There are some people in the room who are putting seams coordination first,” Bechard said. “I think that’s really kind of a misplaced priority. The [dialogue] I’m hearing about seams seems to be more fear-based than fact-based. And I know for a fact that seams can be managed efficiently through joint operating agreements.”
A higher priority for those weighing day-ahead markets should be governance, Bechard said. He recommended a model resembling SPP’s governance structure.
“It is not just an independent board that’s required,” Bechard said. “You need to have stakeholders with voting rights, and you need to have an impartial operator. Having stakeholders with voting rights ensures that it’s the stakeholders that determine what goes to the board rather than the market-operator staff. And having an impartial operator ensures that the operator is not subject to undue influence from any particular state or set of states.”
SPP has an independent board, a committee of state regulators and stakeholder groups that develop and vet policy proposals. It plans to apply the same governance structure to Markets+.
CAISO staff and management develop policy proposals with stakeholder input. The ISO is led by a Board of Governors appointed by the California governor and confirmed by the state Senate, resulting in all of its members being Californians. A legislative effort is underway to open the board to out-of-state members so CAISO can become an RTO. (See Lawmaker Introduces Bill to Turn CAISO into RTO.)
The WEIM Governing Body includes members from outside California and shares joint authority with the ISO Board of Governors over matters affecting the interstate market. EDAM also would be governed under a joint-authority model.
‘Grid of the Future’
Bechard contended that an SPP day-ahead market could offer greater benefits in the future through resource diversity, assuming new interregional transmission lines connecting it to the Pacific Northwest get built.
When envisioning a day-ahead market, “we shouldn’t be thinking about the grid that we have today,” he said. “We should be thinking of the grid of the future.”
As more solar comes online in the Desert Southwest and California and thermal generators retire, resource diversity and trading benefits between the regions will diminish, he said.
“They’re going to have the same resources, the same load, the same issues with solar oversupply and evening ramp and net peak load,” Bechard said. “We see that opportunity to trade between those markets declining.”
Resource diversity and economic value between the Pacific Northwest and SPP will be greater, he said. The Northwest has large amounts of hydropower, and SPP has 30 GW of wind power in an area with weather patterns and peak demand times different from the West’s, he said.
Bechard cited a Lawrence Berkeley National Laboratory report that showed some of the nation’s highest-value transmission lines could be built linking SPP to the West, alleviating congestion and allowing resource transfers. (See Lawrence Berkeley Lab Sees New Transmission Value Spike in 2022.)
If the 31 entities that have signed on for the development phase of SPP’s Markets+ program continue to its operational phase, the market would have a 50 GW peak load, he said.
California has a 54 GW peak load, so if CAISO were a separate market, there would be “two big markets … optimizing within their footprints” and potentially engaging in “robust and automated trade” in the day-ahead time frame, he said.
“It’s much better than the status quo,” Bechard said. “And it’s definitely not a step back from what we have today.”
American Electric Power (NASDAQ:AEP) and Liberty Utilities (NYSE:AQN) have shelved their plans to exchange AEP’s Kentucky operations for $2.6 billion, ending two years of attempts to gain the transaction’s approval.
AEP announced Monday that it and Canada’s Algonquin Power & Utilities, Liberty Utilities’ parent company, have mutually agreed to cancel the deal two weeks before either party could independently pursue termination rights. In a press release, AEP characterized the sale’s collapse as a reaffirmation “of its commitment to Kentucky customers.”
The company said it now must take “swift and decisive action to be best positioned in the near term while continuing to develop a long-term strategy for Kentucky.” That means filing a base rate case with the Kentucky Public Service Commission for 2024 that will include securitizing retired coal generation.
“As a partner in Eastern Kentucky for more than 100 years, we’re renewing our focus on bringing opportunities to the region and supporting the communities we serve,” AEP CEO Julie Sloat said. “We are working diligently to reimagine our strategy with the goal of not just supporting Kentucky but being an essential part of its economic and energy future. “We believe there are opportunities ahead for our Kentucky operations, and we will focus our efforts on economic development, reliability and controlling cost impacts to customers.”
Late last month, the Kentucky PSC, the Kentucky Office of the Attorney General and Kentucky Industrial Utility Customers urged FERC to halt the sale for a second time. They argued that Kentucky customers would pay larger bills through increased zonal transmission rates under Liberty ownership. (See Kentucky Officials Ask FERC to Deny AEP-Liberty Deal.)
FERC first rejected the sale in late 2022, indicating that the companies needed to pledge more consumer protections.
In a separate press release, Algonquin Power CEO Arun Banskota said the management team and board of directors decided “after careful consideration” that the transaction was not in Algonquin’s best interest “in light of the evolving macro environment.”
“I would like to thank the teams who have worked tirelessly throughout this entire process. Looking forward, [Algonquin] remains supported by a high-quality asset base [and] a strong balance sheet, and is well positioned to deliver sustainable, long-term growth, capitalize on the energy transition and create value for shareholders,” Banskota said.
AEP also announced it had elevated interim Kentucky Power President and COO Cindy Wiseman to permanent president and CEO.
“Wiseman’s experience overseeing customer service, economic development and government affairs positions her well to redefine the company moving forward,” AEP said.
AEP reaffirmed its 2023 earnings guidance range of $5.19 to $5.39/share and an annual long-term growth rate of 6 to 7%. It said proceeds from its recently announced plan to sell its 1,365-MW unregulated, contracted renewables portfolio to IRG Acquisition Holdings for an expected $1.2 billion will compensate for previously forecasted proceeds from its Kentucky operations sale. AEP also said its equity financing forecast remains unchanged absent the transaction.
April 16 marked 30 years since one of the seminal moments of our digital being. In 1993, amidst a need to keep up with the dizzying pace of technological innovation, the Clinton administration announced a cryptographic device that would enshrine itself in cybersecurity history.
The MYK-78 was developed by the National Security Administration to give the government a “back door” into all communications in the interest of national security. Nicknamed the “Clipper Chip,” it would permit federal, state and local law enforcement to access and decipher voice and data transmissions at their discretion.
Unsurprisingly, the notion of the government having a permanent opt-in method to eavesdrop on all cell phones, computers and pagers was met with a vociferous uproar. Sure enough, a meager three years and much backlash later, the Clipper Chip was scrapped.
The rise and very quick fall of the Clipper Chip is a cautionary tale of how a failure to understand the operational environment of privacy and tech can lead to failures in policy.
President Biden’s National Cybersecurity Strategy, published March 2, is not a failure in policy. It espouses objectives that are long overdue amidst a world of pervasive cyber threats. It includes the desire to eliminate malicious cyber actors from Russia and China and defend critical infrastructure like hospitals and power generation. “Its implementation will protect our investments in rebuilding America’s infrastructure, developing our clean energy sector, and re-shoring America’s technology and manufacturing base,” the Strategy says. It would expand “the use of minimum cybersecurity requirements in critical sectors,” building on those governing the electric industry.
However, one particular element of the Strategy must tread very carefully: “Shape Market Forces to Drive Security & Resilience.” It aspires to promote privacy and security of personal data, and, interestingly, aims to shift liability for software products from users to tech companies to promote security practices.
This comes at a time when relations between government and tech are at something of a nadir. Apple, Google and Meta have been vocal about their privacy practices: Tim Cook was obstinate in refusing to give the government a back door into iPhones; Meta promulgated end-to-end encryption loud and clear on its Messenger and WhatsApp platforms. The message here? Trust us as we’ll keep the government out of your pocket. And from Apple: Our privacy measures are way better than our competitors’s.
Federal Trade Commission Chair Lina Khan has dialed up government bellicosity toward the tech companies, and the Strategy will further empower this. The FTC may be one of the first agencies to take advantage of the ability to “shape market forces” if given the power by Congress to do so. Should the liability initiatives in the Strategy give birth to more lawsuits, tech companies will be hit with a deluge of regulations and policies — a tightening of the government leash on the so-called market forces.
And then battle will be done in the courts, as it’s being done already. The language “shifting liability” may be innately at war with the biggest, most substantial legal defense in a tech company’s arsenal: Section 230 of the Communications Decency Act, which Biden and company have been vocal about revamping. Section 230 exculpates a publisher from the content on its platform (i.e., you can’t prosecute Meta for a graphic video posted to Facebook). The Supreme Court is deliberating over a case predicated on Section 230 at the time of this writing.
Further friction between tech and government would also, ironically, weaken the Strategy itself. Why? The “Defending Critical Infrastructure” and “Dismantle Threat Actors” sections of the Strategy involve the promotion of public-private collaboration. Widening the existing wedge between tech and the government doesn’t sound like the way to do this.
Alphabet, Meta, Apple, Amazon, and Microsoft and company arguably have the most sophisticated, talented minds and data repositories that can safeguard the U.S. in a world of nefarious cyber threats. Why run the risk of antagonizing them?
Shahid Mahdi is product lead for EnerKnol, a provider of energy regulatory intelligence software.
Researchers are seeking ways to mitigate wind patterns that could limit the output or cause excessive wear on the hundreds of wind turbines planned off the Atlantic Coast.
The National Renewable Energy Laboratory said last week that it and the General Electric Global Research Center (NYSE:GE) are applying ultra-powerful supercomputer modeling to the low-level jet stream (LLJ) patterns that exist on the Outer Continental Shelf along the eastern U.S.
The region, with its steady wind and shallow waters, is regarded as ideal for wind power generation, but there is little observed data on actual performance: OSW in the U.S. so far consists of two test turbines off the coast of Virginia and a pioneering Rhode Island wind farm whose five 6-MW turbines are much smaller and much closer to shore than what is planned to come.
The blade sweep of the largest OSW turbines can approach 10 acres of airspace and reach almost 900 feet above the sea surface. LLJs can occur at this altitude along the Atlantic Coast, and they can be strong, NREL said.
The researchers in their study said that depending on the detection criteria used, LLJs can be observed at least 2 to 7% of the time in the New York Bight, where multiple wind projects are envisioned. But the LLJ is categorized as a nonconventional wind event, they said. Its characteristics are not well understood, and it is not currently considered in some annual energy production calculations.
With exascale computer simulations, the research team has shown a propensity for LLJs to cause a severe wake-induced decrease in wind turbine power output and an increase in load on turbine blades. This could cause excessive wear and tear on the equipment, lower its efficiency and even cause shutdowns, NREL said.
But the simulations are also pointing toward strategies to mitigate the impacts of LLJs. In a news release, the principal investigators said this is a promising development.
“Site-specific, high-fidelity simulations of wind farms are typically beyond the scope of the wind energy design process due to the sheer complexity of the science and computational modeling involved,” said Balaji Jayaraman, a senior engineer at GE Research. “However, through advances in exascale computing algorithms and models for multiscale atmospheric flows — driven by the U.S. federal research labs including NREL and powered by the world’s leading supercomputing capabilities — we’ve been able to demonstrate the feasibility of new wind turbine designs previously not possible.”
“This team was able to accomplish all the goals originally proposed back in 2019,” added NREL’s Shashank Yellapantula.
NREL is the lead lab for the U.S. Department of Energy’s Exascale Computing Project. It has been spearheading an effort to simulate the air flow around wind turbines in a large wind farm with unprecedented accuracy using the latest generation of computing.
The NREL/GE team ran simulations on five- and 20-turbine arrays in a 10-km region with 2 billion points on a grid pattern to visualize the invisible impacts of flow dynamics and make conclusions.
They found LLJs caused a significant increase in load on turbine blades. In the larger wind farm, the LLJs led to deeper wakes that reduced wind velocity and increased turbulence, reducing power output.
Derating the turbines — running them at a lower power level to limit damage — has been the common response by wind farm operators to this scenario, NREL said.
Using the data and observations gathered so far, the team is now designing strategies to reduce the impact of LLJs while maintaining higher power output.
“We’ve never had this level of detail available to us before to understand that wind farms that are designed a certain way can withstand the power of LLJ phenomena,” Yellapantula said.
Bringing emissions-free OSW online is a priority for the federal government and many states as a strategy to limit the impact of climate change.
More than two dozen OSW lease areas are designated from Massachusetts to South Carolina; construction has begun in two, and plans for several others are under review by the U.S. Bureau of Ocean Energy Management. Manufacturers meanwhile are working to improve technology and expand factory capacity.
A member of the Iowa Utilities Board said last week that regulators are in the early stages of determining how the state Supreme Court’s temporary reversal of right-of-first-refusal legislation will affect incumbent transmission owners’ spending.
The IUB’s Joshua Byrnes said the board is trying to “navigate” the injunction’s effect on MISO’s first long-range transmission plan (LRTP) cycle.
Byrnes said during Thursday’s Organization of MISO States board meeting he is notifying other MISO state commissions that Iowa staff are still working through the implications on transmission development.
Last month’s court ruling stands to affect $2.64 billion worth of transmission work in five Iowa projects that belong to ITC Midwest, MidAmerican Energy and Cedar Falls Utilities (21–0696).
MISO said in an emailed statement that it is reviewing the decision to determine its next steps. Staff did not address whether they might be preparing for a delay in certain LRTP projects or preparing more requests for proposals. The grid operator historically doesn’t take positions on state legislation.
Iowa enacted its ROFR law in 2020 as an amendment to the legislative session’s final appropriations bill. A standalone version of the law did not make it past the House subcommittee level.
LS Power challenged the law following its passage, arguing that it is unfair for it to be barred from competing for new transmission projects in Iowa unless an incumbent decides to relinquish its ROFR.
The Iowa Supreme Court ruled the legislation was unconstitutional under a state rule that an act should address just one subject conveyed in the title. The justices called the appropriations bill “a potpourri of various unrelated subjects”; legislators expressed frustration that they didn’t understand the ROFR component before the late-night Senate vote was conducted.
“We are not surprised the ROFR lacked enough votes to pass without logrolling. The provision is quintessentially crony capitalism,” the court said. “This rent-seeking, protectionist legislation is anticompetitive. Common sense tells us that competitive bidding will lower the cost of upgrading Iowa’s electric grid and that eliminating competition will enable the incumbent to command higher prices for both construction and maintenance.”
The court said that while its role is not to “second guess policy choices of the elected branches or regulators,” it is the court’s role to “adjudicate whether constitutional lines were crossed.”
The court concluded that LS Power is “likely to succeed on its constitutional challenge.” It vacated a prior appeals court decision, reversed a district court’s ruling, and remanded the case to the district level to “finally” decide the merits of LS Power’s arguments.
The Iowa ROFR legislation faces an uncertain future as other MISO states have introduced and sometimes discarded ROFR legislation since the beginning of the year. (See MISO States Ramp Up ROFR Legislation.)
A company specializing in conductors that cut down on electricity line loss by as much as 40% was awarded a $3 million grant from the California Energy Commission last week.
The grant to TS Conductor Corp. was one of four that the commission approved on Wednesday as part of the Realizing Accelerated Manufacturing and Production for Clean Energy Technologies (RAMP) initiative.
The program is aimed at helping clean energy startups move from hand-built prototypes to the low-rate initial production stage, a step toward mass production. Companies at the initial production stage might be struggling to secure capital or figure out how their technology can fit into a manufacturing process, CEC staff said during the meeting.
TS Conductor will use the funds to expand manufacturing at its Huntington Beach factory, with a goal of producing up to 2,300 miles of covered smart conductors per year. The company’s conductors feature smart sensors that can provide information on power line conditions in real-time, while an insulated cover prevents lines from sparking and causing wildfires. The conductors have the potential to increase grid efficiency, lower ratepayer costs and improve safety.
The commission approved funding to three other companies on Wednesday as part of the RAMP initiative:
Liminal Insights, which has developed an ultrasound-based inspection system used during EV battery manufacturing, will receive $2.75 million. Liminal’s system is designed to rapidly detect problems during battery manufacturing to improve battery yield, quality and safety.
Skyven Technologies will receive $2.97 million. The company has developed steam-generating electric heat pumps that can be used in industrial applications, replacing natural gas boilers. The technology uses electric power to recycle industrial heat waste back into steam, using substantially less energy than electric boilers.
Next Energy Technologies, which makes energy-generating windows for commercial buildings, will receive $3 million. The windows convert infrared and ultraviolet light to electricity, while allowing visible light to pass through. Multi-level commercial buildings often don’t have enough roof space for solar panels to offset the buildings’ energy usage, the company noted.
The CEC has previously funded 14 clean energy startups through two rounds of the RAMP program. Those companies have since raised $480 million in additional funding and now employ almost 600 workers.
CEC Chair David Hochschild said the RAMP projects help promote clean energy, in-state manufacturing and ratepayer benefits. Some projects have been more successful than others, he said, “but on balance, we are winning.”
“This is the role we should be playing,” Hochschild said. “This is the role of government.”
Battery Manufacturing
The commission also approved an initial $2.5 million award to CALSTART to administer a $25 million grant program for EV battery manufacturing in California. CALSTART, a nonprofit national consortium focused on clean transportation, administers other California programs, including the Hybrid and Zero-Emission Truck and Bus Voucher Incentive Project, or HVIP.
The CEC funds will allow CALSTART to get started on soliciting grant applications. Proposals will return to the CEC for approval of funding and environmental review. The money is coming from the California Budget Act of 2022.
The goal of the program is to increase in-state manufacturing of zero-emission vehicle batteries. Hochschild said he hopes some of the projects will be in Lithium Valley, an area of lithium extraction by the Salton Sea in Southern California. Co-location could lead to “very real process savings” in the manufacture of lithium batteries, he said.
Another CEC funding award on Wednesday was a $500,000 grant to GC Green Inc., a company that plans to install public EV chargers at the Tule River Eagle Feather Trading Post No. 1, about 60 miles north of Bakersfield.
The project includes two DC fast chargers, a Level 2 charger, and on-site solar with battery storage. The site is along State Route 190, an important rural corridor, proponents said.
The project aims to encourage EV adoption by the Tule River Indian Tribe and promote workforce development for the tribe. It’s also intended to demonstrate an EV charging model that other tribal communities can replicate.
“When you think about EV charging, you think about it as sort of a coastal elite phenomenon, and we have to make it for everybody,” Commissioner Patty Monahan said in supporting the grant.
MISO has circulated a new timeline for its first seasonal auction after a FERC order to rework a capacity value ratio forced it to delay the auction last month.
The grid operator now plans to open its offer window at 8 a.m. ET Tuesday. It will accept offers until 6 p.m. Friday and then begin the 20-day planning resource auction on April 24.
MISO anticipates sharing clearing prices in a stakeholder workshop May 19, about a month after it usually posts auction results. The planning year begins June 1.
The RTO said it published the new ratio for review on March 30. Staff said they gave stakeholders two weeks to confirm revised seasonal-accredited capacity and zonal-resource credit values based on the reworked ratio.
MISO said that after it wraps the auction, it will initiate stakeholder dialogue in Resource Adequacy Subcommittee (RASC) meetings “to investigate opportunities for future improvement.” It said it will reserve the July RASC meeting to examine 2023/24 auction data and discuss trends. Later in the year, it said it will likely begin work on a process to “codify publishing, updating, and locking down” the ratio in future auctions.
The delayed auction means MISO’s 2023 joint resource adequacy survey with the Organization of MISO States will also have a later timeline than usual.
The OMS-MISO survey form is open to utilities through May 9. The organizations expect to publish their findings, normally posted at the end of spring, in late June or early July.
During an OMS board meeting Thursday, Executive Director Marcus Hawkins said the survey’s new seasonal aspect should give stakeholders “more granular” adequacy estimates.
This year’s survey will reflect MISO’s seasonal auction format and project capacity values across four seasons for the next four years; count future capacity according to the grid operator’s seasonal accreditation method; and use seasonal planning reserve margin requirements to compare against capacity values. The 2023 survey will also allow for one- to three-year lags beyond developers’ stated commercial operation dates when counting potential new resources in the generator interconnection queue. MISO said its queue data shows that future generation has historically come online up to three years — and sometimes beyond that — after proposed commercial operation dates.
Hawkins said it’s critical that utilities complete the survey so that stakeholders have the best snapshot of the footprint’s near-term resource adequacy landscape. The survey is MISO’s only annual footprint-wide adequacy survey.
Hawkins said it’s up to states to decide how to use survey results and said OMS strives to communicate with regulatory staffs before the survey’s reveal to manage expectations and ease the “drama” of unexpected results.
He said because the OMS-MISO survey is delayed, it will also postpone the kickoff of OMS’ annual distributed energy resources survey, which seeks to get an annual count of the RTO’s DERs.
Hawkins said the double survey delays are meant “to avoid survey fatigue and confusing emails about multiple surveys.”
ERCOT stakeholders agreed last week to endorse staff’s recommended changes to the operating reserve demand curve that will serve as a bridge to Texas regulators’ proposed performance credit mechanism (PCM).
Staff are proposing to add multistep floors within the same range of operating reserves. Their analysis has shown floors of 6,500 MW at $20/MWh and 7,000 MW at $10/MWh would have increased revenues to generators by about $500 million during the 2020 and 2022 pricing years.
ERCOT says that the ORDC increasing during substantial operating reserve surplus periods will improve pricing signals, help retain existing assets, add new dispatchable generation and reduce the frequency of reliability unit commitments — all objectives of the Public Utility Commission when it directed the grid operator to evaluate bridging options.
After exploring several other alternatives in recent weeks, the Technical Advisory Committee sided with the staff proposal during a special meeting April 10 by a 21-6 vote, with two abstentions. All six representatives of the Consumers segment voted against the endorsement, citing a preference for a dispatchable reliability reserve service that they said would create more reserves and lead to a bigger reserve margin.
TAC members were supportive of an initial staff recommendation to publish an indicative PCM but determined it didn’t meet the bridging option’s requirements. The PUC required alternatives that make only minimal system changes and be implemented within a year, align with the existing market framework and can be hedged by market participants through their energy positions.
Mark Dreyfus, who represents the city of Eastland and other commercial consumers, said the proposed floors will create a “significant” wealth transfer from consumers to generators. He called for more transparency and reporting from the generators on the increased revenues intended to stimulate generation construction.
“I think it is important that we get … some commitment that these funds won’t be used for the purposes that are laid out in the investment in existing generation and in new generation,” he said. “There’s no obligation on the part of the generators at the end, nor are they competing for these funds.”
Dreyfus found support from Randy Jones, a 17-year Calpine executive who spent two years on the previous ERCOT Board of Directors representing the Independent Generators segment. TAC Chair Clif Lange jokingly introduced Jones as “member emeritus.”
“I get nervous when we talk about mechanisms to absolutely push money from the demand side to the supply side, without real justification and without delving into what the potential unintended consequences are,” Jones said. “It seems to me that the policy shift that is occurring in Austin and at the commission is one that says, ‘Look, we’re tired of feeding money to renewable resources and allowing them to enjoy the benefits of the ORDC that dispatchable units actually earned.’
“Whatever change for a bridge mechanism we put in place should contain a proposal of not paying additional revenues to wind and solar and focusing on moving those revenues strictly to what it is you’re trying to encourage, which is dispatchable generation.
“I couldn’t agree more with Mark in the sense that we need to know … if this is actually going to serve the policy decisions that the commission has made. Maybe it’s time that we shift from being revenue neutral to being more targeted with these changes,” he added.
Staff will present their alternative and TAC leadership its minority position to the board’s Reliability and Markets Committee on Monday. The full board will take up the recommendation Tuesday. It is expected to eventually make a recommendation to the PUC.
Credit Group Adds Members
TAC members also confirmed two additional members to the committee’s newest stakeholder group, the Credit Finance Sub Group (CFSG).
National Grid Renewables Energy Marketing’s Jacqui Runholt and CPS Energy’s Jimmy Kuo will represent the Independent Power Marketer and Municipal segments, respectively.
The CFSG now has 13 members, and they will eventually vote on the group’s leadership. Austin Energy’s Brenden Sager and Reliant Energy’s Loretto Martin are running unopposed for the group’s chair and vice chair positions, respectively.
The Virginia State Corporation Commission on Friday approved Dominion Energy’s (NYSE:D) 2022 Renewable Energy Portfolio Standard plan, which includes more than 800 MW of carbon-free electricity.
The utility has to file such a plan every year in compliance with the Virginia Clean Economy Act. The SCC approved Dominion’s $89.154 million revenue requirement for VCEA-related costs in the rate year of May 2023 through April 2024.
“This is another big step forward in delivering reliable, affordable and cleaner energy to our customers,” Dominion Energy Virginia President Ed Baine said in a statement. “These projects will bring jobs and economic opportunity to our communities, and they will deliver fuel savings for our customers. That’s a win-win for Virginia.”
The projects approved on Friday are expected to lead to $250 million in fuel savings for customers over their first decade of operation. They include nine solar facilities and one energy storage project, which total nearly 500 MW and will be owned by Dominion itself. Kings Creek Solar and Ivy Landfill Solar are being built on previously developed land, with the latter being the first solar plant Dominion has built on a former landfill.
The commission also approved power purchase agreements with 13 solar and energy storage projects, which total more than 300 MW and are owned by independent developers.
Construction of the projects is projected to support thousands of jobs and more than $920 million in economic benefits across Virginia. The projects will cost the average residential customer an extra 38 cents on their monthly bill, with construction of the new renewable projects expected to be complete by 2025.
The SCC directed Dominion to provide additional analysis with its next RPS plan due later this year, including an assessment of the impacts of the federal Inflation Reduction Act and modeling that shows Virginia both inside and outside the Regional Greenhouse Gas Initiative’s cap-and-trade system for power plants.
The commission sided with the utility and against its own hearing examiner’s report, which recommended the rejection of cost recovery for the Shands Storage project. The project will be the largest storage facility in Virginia at nearly 16 MW once completed, but the report found it would cost consumers $36.8 million without corresponding benefits, especially given the so-far light development of renewables in PJM, though Dominion argued that was changing.
“The extent to which Shands Storage can take advantage of any such market evolution would depend in part on both the actual market design changes (which cannot be known at this time) and timing,” the examiner said in their report filed in early March. “As Shands Storage degrades over time, each year this project is operational under PJM’s current market design seemingly means it will have less product to sell in PJM if and when a market redesign occurs.”
The SCC disagreed, noting that the VCEA includes targets for storage and that Dominion will benefit from starting to roll out the resource in Virginia.
