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December 29, 2024

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SPP MOPC Briefs: April 10-11, 2023

Staff, Stakeholders See Resource Adequacy as Key Issue

SPP staff and stakeholders spent much of last week’s virtual Markets and Operations Policy Committee meeting discussing resource adequacy and the various initiatives the grid operator has rolled out to address the issue.

“Resource adequacy is a critical area for us,” SPP’s Casey Cathey said. “The regional fuel mix is consistently changing. The state of the future grid is extremely important. Loads are changing; pretty much everything’s changing that we know of in our industry, even HR.”

As director of grid asset utilization, Cathey runs a department responsible for planning a reliable and efficient bulk electric transmission system, with an eye on economically preparing SPP for the future grid. His staff facilitates generation interconnection and transmission service functions and operates resource adequacy across both the Western and Eastern interconnections.

Cathey’s department is not alone.

“Everything we’re doing related to resource adequacy is critical, which is why we have a number of different groups that are focusing on various aspects of resource adequacy,” COO Lanny Nickell said.

SPP’s Supply Adequacy Working Group (SAWG) handles immediate resource adequacy issues and the technical aspects of various studies. The Improved Resource Availability Task Force was formed after the February 2021 winter storm and is working on fuel assurance and resource planning and availability recommendations identified in the RTO’s review of the storm. (See SPP Board of Directors/Members Committee Briefs: July 26-27.)

The grid operator has also created the Resource and Energy Adequacy Leadership (REAL) Team under state regulators’ Regional State Committee. Chaired by Texas Public Utility Commissioner Will McAdams, the REAL Team has been tasked with the more strategic aspects of resource adequacy by assessing SPP’s current construct and anticipated challenges from resource mix changes, extreme weather effects, increased demand and evolving consumer behaviors.

Staff and stakeholders will be busy in the near term. SPP’s annual tasks include winter and summer season deliverability studies and, this year, a loss-of-load expectation study to help determine the planning reserve margin for summer. The study will address weather-forecast uncertainty by using 40 historical weather years dating back to 1980. It will also determine a winter resource requirement and PRM and an unforced capacity PRM.

Staff and the REAL Team are both looking at whether an expected unserved energy (EUE) standard needs to be developed. Then there’s the SAWG and Operating Reliability Working Group’s joint review of the planned and maintenance outage policy and a slew of other work.

Cathey noted SPP and the industry have traditionally followed the one-day-in-10-years LOLE standard, a legacy from a time when generation fleets primarily comprised thermal resources. He said the industry may be leaning toward a combined standard that combines LOLE with EUE and loss-of-load-hours.

“One thing that is missing in our LOLE study is forecasting climate change. There’s not a forecast or prediction or aspect to our LOLE study today, so that’s another area that we’d like to continue to explore,” Cathey said. “We have an urgency for resource adequacy, not the least of which is that resource adequacy is now one of our top corporate risks and also industry-wide. Everyone’s trying to figure out the potential policy changes.”

Nickell assured stakeholders that they will continue to have a voice in the resource adequacy work.

“I just want to deal with the impression that this is all happening behind the scenes and behind closed doors, and it’s just staff collaborating on this stuff,” he said. “That’s absolutely not true. We have been working with stakeholders along the way. … They will all have an opportunity to provide input.”

Responding to FERC’s Rejection

One of the REAL Team’s first actions has been to direct the SAWG to modify and “harmonize” two revision requests so they focus on equitable and appropriate treatment of resources in response to FERC’s recent rejection of SPP’s capacity accreditation methodology for wind and solar resources on procedural grounds.

The commission agreed in March with renewable energy developers’ arguments that it had erred with last year’s order accepting the RTO’s proposed tariff revisions to accredit wind and solar resources based on historical performance using an effective load-carrying capacity (ELCC) methodology (ER22-379). (See FERC Grants Rehearing of SPP Capacity Accreditation Proposal.)

“This was a surprise to SPP and SPP staff and members,” Cathey said, noting the ELCC was expected to be in place this summer.

The SAWG is working to separate the ELCC and performance-based accreditation into two separate RRs, with the ELCC request expected to reflect FERC guidance. The RRs have been targeted for final presentation to the board and RSC in October.

Cathey said the accreditation methodology changes for all resources should be filed together as a policy change and their implementation’s timing be consistent across all resource types. He said seasonal net peak demand should be defined in the tariff and modifications considered for ELCC allocation methodology.

FERC said in its filing that it expects staff to provide “sufficient detail in its tariff, consistent with the directives of this order, to allow the commission to act in a subsequent order without the need for additional record development.”

“We all know, especially since we passed the performance-based accreditation policy last summer, that we were working to become more equitable in our accreditation process across all fuel types,” Cathey said. “However, from a legal perspective, that was not in front of [FERC] in that docket, and so it’s certainly a lessons-learned for us.”

2024 ITP Scope Revisions OK’d

The MOPC approved a pair of Economic Studies Working Group recommendations to the 2024 Integrated Transmission Planning 10-Year Assessment’s scope that are more reflective of current grid conditions.

The first revision would include a winter weather analysis because of more frequent extreme conditions, such as the February 2021 and December 2022 storms. The MOPC and the Strategic Planning Committee both directed the ESWG to study extreme winter weather conditions.

The second increases the amount of assumed amounts of renewable capacity in the scope’s two futures, based on the amount of renewable interconnection requests in the queue. Both measures passed overwhelmingly, 80% and 93%, respectively.

Increased renewable energy assumptions (SPP) Content.jpgIncreased renewable energy assumptions in the 2024 ITP’s scope | SPP

 

The ESWG suggests building two distinct winter weather power-flow scenarios: one focused on operational conditions to better understand reliability issues that took place in December, and a generic model based on a set of historical winter regional stressors such as fuel availability, wind output, and transmission and generation outages.

“At the very least for December 2022 … we are going to have some outages baked in to be able to study what exactly happened in Winter Storm Elliot,” said ESWG Chair Derek Brown, of Evergy.

Brown said it could take as much as $600,000 for additional staff time to keep the 2024 ITP on schedule.

The ESWG also proposes to increase its assumptions for renewables added to the grid in the futures’ year 5 and year 10 scenarios. The studies will assume year 10 highs of 19.1 GW for solar in the reference case and 24.1 GW in the emerging technologies case; 54.9 GW and 59.1 GW for wind; and 5.7 GW and 9.6 GW for battery storage.

GI Backlog Tracking for 2025 Completion

SPP remains on track to clear its generator interconnection queue’s backlog by 2025 despite 599 active requests, Cathey said. The queue’s six cluster studies are all green thanks to the grid operator’s two-year-old, three-phase approach to processing generator interconnection requests in place since 2022 and its backlog mitigation plan.

The mitigation efforts began in 2022 with 898 GI requests for 171.5 GW of generation in the queue. As of Sunday, the requests are down to 593 for 118.1 GW of capacity.

“It’s mostly around restudies and ensuring that we’re not causing too much churn to the GI customers and making sure that we get through the backlog as each cluster of DISIS [definitive interconnection system impact studies] is captured,” Cathey said. “So far, it still appears to be effective.”

Even with the backlog, SPP has added almost 28 GW of capacity to the system since 2016 and executed 144 interconnection agreements. Complicating matters going forward is that a little over 41% of the queue’s requests (48.3 GW) are for solar. Wind (29.9 GW) and energy storage (21.8 GW) — all of it four-hour, lithium-ion batteries, Cathey said — account for much of the rest. Developers have 21 requests for 3.5 GW of thermal capacity in the queue.

“We’re trying to thread that needle in terms of where our fuel mix is going five, 10, 15 years in the future, coupled with our load profiles,” Cathey said. “We definitely need to work on those particular policies because even if they’re all approved, as massive as 119 GW are, it’s more than twice our peak load.”

Tx Service RR Remanded

The MOPC remanded a revision request back to the Transmission Working Group after Dogwood Energy’s Rob Janssen pulled it off the consent agenda for further discussion and vetting in the stakeholder process.

Dogwood abstained from the Regional Tariff Working Group’s vote on RR534, which is intended to clarify and correct tariff language that limits transmission service to the amount of interconnection service.

Janssen said 95% of RR534 is “perfectly fine,” but the inclusion of point-to-point service along with network service runs counter to FERC Order 888’s language that doesn’t allow limitations on parties purchasing transmission service in the absence of anticompetitive practices.

“While you do try to include both point-to-point transmission service and network service in this set of restrictions, my concern is that you actually increase the probability of gaming, because now you’re allowing a third party to buy point-to-point transmission service and effectively block a load-serving entity that might have a deal with a generator for being able to get transmission service for any deal that they put in place,” Janssen said. “That could result in a very significant problem for some parties as SPP’s grid gets more resource-constrained and parties are fighting for access to generating resources.”

The consent agenda, approved unanimously, included seven other RRs that are effective immediately and one, RR530, that requires the Board of Directors’ approval:

  • RR530: identifies consistent criteria for when it is acceptable to implement a transmission reconfiguration and outlines responsibilities for the reliability coordinator and transmission operator.
  • RR532: removes section 4.5.9.21 (Real-Time Joint Operating Agreement Amount) and adds the variable RtJoaHrlyAmt in the definitions section of 4.5.12 (Revenue Neutrality Uplift Distribution Amount) among other cleanup to revenue neutrality uplift language.
  • RR533: adds language to clarify how resources will be settled with operational tools downstream from the real-time balancing market and that cleared quantities are updated when a price correction is needed for the day-ahead market.
  • RR535: corrects the protocols for uncertainty products by clarifying summation for reserve zone additions, settlement variables and if/else replacements.
  • RR538: ensures the protocols and tariff clearly describe when emergency limits will be used and how market participants can know if the emergency limits are used.
  • RR540: ensures RR382 (Multi-day Minimum Run Time) is accurately implemented by revising governing language for day-ahead and reliability unit commitment make-whole payments.
  • RR541: clarifies that the credit customer, not the market participant, is the highest level for exposure tracking.
  • RR544: modifies the Transmission Owner Selection Process Task Force’s changes to the competitive transmission selection process to include cost caps and guarantees in competitive upgrades.
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PJM PC/TEAC Briefs: April 11, 2023

CAPS Pushes for More Transmission Upgrade Data

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.

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Western Day-Ahead Markets Debated at CREPC-WIRAB

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.

Ric OConnell 2023-04-12 (RTO Insider LLC) FI.jpgRic O’Connell, GridLab | © RTO Insider LLC

“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.

Stefan Bird Tom Blechard 2023-04-12 (RTO Insider LLC) Alt FI.jpgPacific Power CEO Stefan Bird (left) and Powerex CEO Tom Blechard debated the merits of day-ahead markets being developed by CAISO and SPP. | © RTO Insider LLC

 

“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.”

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AEP, Liberty Call off Sale of Kentucky Operations

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.

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Stakeholder Soapbox: Biden’s Cyber Strategy Risks Demonizing Biggest Ally: The Private Sector

Shahid Mahdi (Shahid Mahdi) FI.jpgShahid Mahdi

By Shahid Mahdi

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.

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Researchers Modeling Jet Stream Interference with OSW

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.

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Iowa Regulators Ponder MISO Transmission Projects After ROFR Ruling

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.)

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Clean Energy Startups Earn Millions in California Energy Commission Grants

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.

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MISO Unveils New Seasonal Auction Timeline, Ratio

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 auction was on hold as MISO recalculated its unforced capacity-to-intermediate seasonal accredited ratio that it uses to determine supply in the auction. The new ratio stands to lower some thermal resources’ accredited capacity values. (See FERC Order May Delay MISO’s 1st Seasonal Capacity Auction and Vistra, EPSA Protest MISO’s Show-cause Order.)

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.”

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ERCOT Stakeholders Endorse Staff’s Bridge to PCM

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.