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November 16, 2024

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NY OSW: If at First You Don’t Succeed, Try, Try Again

Two of the offshore wind developers that won and then lost contingent New York contracts are trying again, submitting proposals into the state’s latest solicitation. 

Community Offshore Wind and Excelsior Wind could be the fourth and fifth wind farms off the coast of New York, which is pursuing development of an offshore wind sector vigorously but with mixed results. 

Community and Excelsior announced their proposals Sept. 9, the final day to submit proposals without price tags in New York’s fifth competitive offshore wind solicitation (NY5). 

The New York State Energy Research and Development Authority (NYSERDA) would not say how many other proposals it received. It said redacted versions of the proposals would be made public in coming weeks.  

The process is not complete — developers must submit price tags for their proposals by Oct. 18 — but the door now is closed to additional proposals into NY5. 

NYSERDA expects to make contingent awards by Nov. 8, then execute the contracts and announce them to the public in the first quarter of 2025. 

Community is proposed by RWE and National Grid Ventures. Excelsior is proposed by Vineyard Offshore, an affiliate of Copenhagen Infrastructure Partners. 

In October 2023, Community and Excelsior were awarded contingent contracts in NY3, along with Attentive Energy One. All three contracts were predicated on an 18-MW turbine under development by General Electric.  

When the company — now GE Vernova — halted development of that machine, the contracts no longer penciled out. The NY3 solicitation was canceled, and the conditional contracts for 4 GW of capacity from the three projects were canceled in April 2024. (See NY Offshore Wind Plans Implode Again.) 

Excelsior announced Sept. 9 it had submitted a 1,350-MW project in NY5 — nearly the same nameplate capacity it had proposed in NY3. Community did not specify the nameplate capacity of the wind farm it is proposing for NY5. 

Headwinds

New York’s experiences are among the best examples of the growing pains of the U.S. offshore wind industry as it takes root off the Northeast coast. It has not had a project cancellation, like New Jersey has, but it has gone through multiple gyrations.  

New York has the first and so far only completed utility-scale offshore wind farm in U.S. waters, the 132-MW South Fork Wind. It also has Sunrise Wind and Empire Wind 1 under contract, and Sunrise is in early stages of construction. 

Along with the three contracts lost to supply chain problems in NY3, New York saw cancellations of contracts for Beacon Wind, Empire Wind 2 and earlier contracts for Empire 1 and Sunrise when soaring costs made those contracts untenable. The second contracts for Sunrise and Empire 1 carry much higher costs for ratepayers. 

Community is persistent if nothing else. 

It nearly won then lost the NY3 contract. It submitted a proposal into NY4 but was “waitlisted” and then not chosen. It submitted a proposal into NJ3, then withdrew it after concluding the pricing did not work. It submitted a proposal into NJ4 that is awaiting a decision by the state. 

(Community’s lease area is large enough and close enough that it could feed the grid in both New York and New Jersey.) 

The drive continues, and new headwinds arise even as previous problems are resolved. 

Atlantic Shores Offshore Wind this summer rebid into NJ4 a wind farm already under contract in New Jersey, presumably at higher cost. (See 3 OSW Proposals Submitted to NJ.) 

In recent weeks, Leading Light Wind has asked the New Jersey Board of Public Utilities for a delay because it is having trouble securing a supply contract for turbines. 

Earlier this month, the first-ever multistate solicitation was a decidedly mixed bag: Connecticut, Massachusetts and Rhode Island sought up to 6 GW of combined capacity and received 5.45 GW of proposals. But the projects selected totaled only 2.88 GW — 2.68 GW for Massachusetts, 0.2 GW for Rhode Island and 0.0 for Connecticut, which said it was still evaluating bids. (See Multistate Offshore Wind Solicitation Lands 2,878 MW for Mass., RI.) 

Vineyard Offshore proposed the 1.2-GW Vineyard Wind 2, up to 800 MW of which was selected by Massachusetts. The developer implied its ability to move forward with the project depended on Connecticut signing up for the rest.  

“We look forward to Connecticut’s forthcoming decision on the remainder of the procurement so that we can begin to deliver important economic and climate benefits to the region,” CEO Alicia Barton said in a news release. 

In the background to all this, a turbine blade disintegrated at Vineyard Wind 1 in July, littering beaches and waves with fragments and giving offshore wind opponents a camera-ready moment they are exploiting two months later. (See Blade Failure Brings Vineyard Wind 1 to Halt.) 

On a positive note, the first turbine recently was hoisted into position off the New England coast for Revolution Wind, which is expected one day to send up to 700 MW to Connecticut and Rhode Island.  

But Revolution, too, has had its setbacks. Brownfield contamination where its onshore substation will stand has pushed the anticipated completion date back from 2025 to 2026. (See Revolution, Sunrise OSW Projects Face New Delays.) 

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Potential Seen to Add up to 95 GW to US Nuclear Plants

The U.S. Department of Energy estimates that existing and recently retired nuclear power sites could host an additional 60 GW to 95 GW of new nuclear generation. 

DOE also said an additional 128 GW to 174 GW of new nuclear capacity could be built near existing or recently retired coal-fired facilities. 

In its 2023 report “Pathways to Commercial Liftoff: Advanced Nuclear,” the department estimated the U.S. would need 200 GW of additional nuclear capacity by 2050 to meet the growing demand for electricity and the growing emphasis on emissions-free generation. 

“A good chunk of that could come from a familiar place,” Michael Goff, acting assistant secretary for the U.S. Department of Energy’s Office of Nuclear Energy, wrote Sept. 9 in introducing the new report. 

“Evaluation of Nuclear Power Plant and Coal Power Plant Sites for New Nuclear Capacity” finds that 41 operating and retired nuclear sites could accommodate one or more new large light-water reactors rated at 1,117 MW for a total of 60 GW of new capacity. 

Using advanced reactors rated at 600 MW would bring the total to 95 GW, as more reactors could be built on more sites. 

For its analysis, DOE examined 54 operating and 11 recently retired nuclear power plant sites in 31 states.  

To determine suitability for expansion, it examined site footprint and acreage, aerial analyses, utility plans, a siting analysis tool developed by Oak Ridge National Laboratory, availability of cooling water, proximity to population centers or hazardous facilities, seismic risk and flood hazards. Researchers from Oak Ridge and Argonne National Laboratory contributed. 

Important tangible considerations such as politics and finances were not on the list of factors considered, though Goff acknowledged that capital costs will be a key factor in decisions about nuclear plant construction. 

He cited a study showing the majority of people who live near nuclear power plants consider them good neighbors. And there is hope that a concerted buildout of new nuclear plants will create economies of scale that limit the cost of new nuclear construction, which has seen exorbitant cost overruns. 

For coal-burning plants, which are being retired or scheduled for retirement at a steady rate, the study looked only at sites with a nameplate capacity of at least 600 MW that are active or were retired after 2019. It assumed retired plants had not been converted to natural gas and that their licenses to provide power to the grid were still in effect. 

Replacing coal with nuclear in a timely fashion could benefit the surrounding communities economically and environmentally and take advantage of existing workforces. A 2022 DOE report delved further into the opportunities and challenges that would surround such conversions. 

Goff stressed that this new analysis is preliminary. “Utilities and communities will need to work closely together to make the decisions on whether to build a new plant,” he wrote. 

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MISO, SPP Try Again to Find Joint Seam Projects

After five fruitless attempts to agree on joint transmission projects across their seams, MISO and SPP will use what they call a “blended joint model” in parallel with existing SPP and MISO regional models.

The RTOs’ staffers told stakeholders during a Sept. 9 Interregional Planning Stakeholder Advisory Committee meeting that their Coordinated System Plan (CSP) study, required every two years by a joint operating agreement, will identify near-term upgrades that “incrementally enhance” transfer capability and produce multiple benefits across the two grids. The study will include reliability, economic and transfer analysis using forward-looking models and assumptions (10- and/or 20-year models), they said.

“The hope is that we have some mutually beneficial projects that we can both agree to recommend approval and ultimately share costs and construct,” SPP’s Clint Savoy said. “That’s the way the current process works today, or that’s the way it’s envisioned in the JOA.”

Five previous studies have failed to produce any joint projects over differences in allocating costs. That led the RTOs to try a different approach with the Joint Targeted Interconnection Queue project, which identified a $1.86 billion portfolio of five projects that could support up to 28 GW of interconnecting generation on both sides of the seam. The Department of Energy last year awarded the portfolio $464 million under its Grid Resilience and Innovation Partnerships program. (See DOE Announces $3.46B for Grid Resilience, Improvement Projects.)

Under the blended model, MISO will use its 2023 Long-Range Transmission Planning reliability and economic model sets and SPP will run the 2025 Integrated Transmission Planning’s same model sets. Staff will use three of four base seasonal models (winter peak, summer peak, average load and light load).

The RTOs both want a multi-benefit style project type and cost allocation to draw on a broader set of benefits for project recommendations, they said. Savoy said FERC Order 1920, which requires transmission-planning regions use at least a 20-year horizon, has provided something of a guidepost for the RTOs to follow.

“We hope this new approach will let us look into additional drivers for projects other than just economic or reliability benefits, if you will, maybe consider different assumptions as we are developing, the list of needs that we want to fix,” he said. “And so what we hope is a better outcome to look more proactively, maybe have a broader set of issues that we’re looking for or benefits to consider, rather than just the traditional economic reliability and public policy.”

The two staffs will continue to develop the study’s scope, incorporating stakeholder feedback, and share it with stakeholders when complete later this year. The 2024 CSP will run through 2025.

The RTOs will have to file a waiver request with FERC requesting permission to use the blended study process. They said they will partner with states and stakeholders to identify and file any needed changes to their JOA and tariffs.

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Webinar Examines How FERC Could Use Interregional Transmission Study

Congress and FERC will need to act to update the rules on interregional transmission planning, and likely permitting, if NERC’s Interregional Transfer Capability Study is going to be of any use, experts said on a webinar hosted by Americans for a Clean Energy Grid.

The study is only the second thing Congress has ever requested from NERC, after it called for the creation of the Electric Reliability Organization in the Energy Policy Act of 2005, said John Moura, director of reliability assessment and system analysis. NERC recently released its initial results, but the final report is not due to FERC until Dec. 2. (See NERC Examines Transfer Capability in Draft ITCS Installment.)

“The ITCS is really an unprecedented study, both in scale and magnitude of what we have to look at,” Moura said. “It’s a U.S.- and Canada-wide technical assessment that looks at the power transfers between regions, and then also makes recommendations to increase those transfers based on reliability needs.”

Once FERC gets the report in December, it will open it up for comments, which will put it before a much larger group of stakeholders, Moura said. Though Congress directed the study, Canadian representatives wanted their own version, which will be published in the first quarter of 2025, he added.

NERC found greater needs for transfer capabilities in some regions compared to others, with Moura presenting a color-coded slide with green, yellow and red for increasing regional needs. While the red and orange areas would benefit from more transfer capacity, Moura noted that the green and gray regions still require work to maintain reliability.

The study assigned “prudent” transfer capability between regions, which means how much is required to meet load under extreme conditions, Moura said.

In doing the study, NERC had to use the same metrics for different regions, which is not how it operates in its own regional planning efforts, so it could accurately assess transfer capabilities. One key finding of the studies is that increasing interregional transfer capability is not enough to ensure reliability.

“I think the results are pretty clear: Adding transfer capability to a minimum level is not sufficient in resolving reliability issues for some areas,” Moura said. “And for other areas, adding transfer capability where it’s not needed would not appear to be economically prudent, without much benefit to reliability. Also, transmission is only one option and only one solution.”

Transfer capability can help with reliability issues in some regions, but so can adding new generation — especially types that are not subject to the same common mode failures plaguing generator availability, Moura said. Higher transfer capabilities will require significant planning and systemwide reinforcements, he added.

Nicole Luckey, Invenergy senior vice president of regulatory affairs, said the current rules are not working.

“There are no holistic interregional transmission planning or cost allocation processes in place today, aside from what was laid out in Order 1000, which I think we all can acknowledge isn’t necessarily working now,” Luckey said. “We’re all really looking forward to the folks in the transmission development community seeing what FERC does with NERC’s study.”

One question is whether the commission will stick to purely reliability benefits or consider others in that effort, she added.

American Electric Power owns utilities in four different ISOs and RTOs, and many of its territories are located along market seams, so it has had a front-row seat to view how Order 1000’s interregional process has failed, said Stacey Burbure, vice president for FERC and RTO strategy. A key reason is that different regions consider transmission with different metrics.

“When you’re comparing apples and oranges, it’s not always intuitive what the right solution is, which is why coordination simply hasn’t gotten us there,” Burbure said. “The RTOs are on different timelines. They’re looking at different inputs. So, moving towards a more standardized approach, with respect to that engineering information, is going to be critical in order to get the right transmission built.”

FERC should take steps with interregional transmission like it did in Order 1920 with regional planning, so the different regions are examining interregional lines on the same basis, she added.

Brattle Group Manager Joe DeLosa agreed that FERC would need to get more common metrics in place to make interregional planning successful, but he also noted that planners currently use models of the system in normal conditions.

The National Renewable Energy Laboratory “has recently said that about half of the benefits of interregional transmission come from the most stressed 5% of system hours,” DeLosa said. “And so, if your interregional coordination/planning, especially for economics, doesn’t take a look at those hours, you’re going to be overlooking large portion of potential interregional benefits, and you’re not ultimately going to develop the appropriate projects.”

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PJM Asks FERC to Eliminate Energy Efficiency from Capacity Market

PJM has filed governing document revisions that would remove energy efficiency from its Reliability Pricing Model (RPM), in line with stakeholder endorsement of an Independent Market Monitor proposal to eliminate EE from the capacity construct (ER24-2995).

The Monitor has argued EE can’t participate as a capacity resource because the load reductions already are accounted for in PJM’s load forecast, and that capacity market revenues to program providers constitute an uplift payment with no corresponding reliability benefit.

Ahead of the Aug. 21 vote, EE providers argued the load forecast does not account for EE installations made possible by RPM revenues and that hastily moving to a vote to bar an entire resource class would curb consumers’ ability to mitigate rising capacity costs. (See PJM Stakeholders Endorse Elimination of EE Participation in Capacity Market.)

The tariff and Reliability Assurance Agreement (RAA) revisions would come with a Nov. 6 effective date, which would preclude EE participation in the 2026/27 Base Residual Auction (BRA) set to begin Dec. 4.

“After years of experience, coupled with a careful review of what energy efficiency sellers have been including in their offers, it has become obvious to PJM, and a sector-weighted super majority of the PJM members, that the current paradigm is no longer appropriate,” PJM wrote in the Sept. 6 filing. “Under the current framework, energy efficiency projects are compensated at the relevant RPM auction clearing price on the supply side even though energy efficiency capability has already been incorporated into the load forecast in aggregate and reduced the amount of capacity that needs to be procured in the RPM auction.”

To avoid double counting the benefits of an EE installation — through both reduced capacity procurement and BRA revenues to the EE provider — PJM instituted the addback process in 2016, which removes EE that clears a capacity auction from the supply stack and increases the load forecast by a corresponding amount. Consumer advocates argued that undermines the ability for EE to displace capacity resources and drive clearing prices lower, while the Monitor argued it is an unnecessary uplift mechanism.

A proposal offered by the New Jersey Division of the Rate Counsel on Aug. 21 would have eliminated the addback with the aim of allowing EE to clear in capacity auctions akin to generation and demand response resources, while the main motion previously endorsed by the Market Implementation Committee would have tightened the measurement and verification (M&V) requirements and mandated a sole causal link between capacity market revenues and EE installations. Both were rejected before the Monitor proposal was endorsed.

In its filing, PJM wrote that state-mandated EE programs will continue to deliver benefits to consumers in the form of reduced capacity costs even in the absence of RPM revenues. Exelon sought amendments to the MRC proposals to add governing document language differentiating utility EE programs from third-party providers driven purely by PJM revenues.

“Energy efficiency projects will continue to receive economic benefits via reduced wholesale costs and the natural incentive of lower energy costs,” the filing said. “There is simply no reason the same energy efficiency should be simultaneously compensated for capacity revenues based on the same underlying project that also receives a reduction in demand costs.”

Petition Urges Technical Conference on EE

A group of EE trade groups and advocates jointly filed a petition with FERC urging it to open a technical conference on RTO rules around EE. Filing as the Alliance to Save Energy, the petition is signed by the American Council for an Energy-Efficient Economy, California Efficiency and Demand Management Council, Energy Efficiency Alliance of New Jersey, Institute for Market Transformation, Keystone Energy Efficiency Alliance, Metrus Energy, Midwest Energy Efficiency Alliance, National Association of Energy Service Companies and National Association of State Energy Officials.

The Aug. 29 petition states EE can effectively rise to the challenges posed by rising demand, the clean energy transition, transmission upgrades and backlogged interconnection queues in a manner that resources requiring long interconnection and construction lead times cannot (AD24-12).

“Energy efficiency offers significant advantages, including reducing the need for new generation and the costly transmission upgrades that come with it,” the coalition wrote. “By lowering demand, it can also free up existing transmission capacity, enabling a more expedited interconnection of additional resources. Moreover, unlike other resources, energy efficiency can be implemented without depending on the interconnection queue, resulting in substantial time and cost savings.”

The rule changes proposed by PJM and several complaints filed by the Monitor and market participants go beyond one RTO to implicate EE across the nation, the coalition wrote. Acting without cross-RTO guidance from FERC since it accepted PJM’s market design for EE in 2009 (ER05-1410), individual RTOs and their stakeholders have created a patchwork of market designs, the petition states.

“It is imperative that any changes to market rules affecting the participation and eligibility of EERs, which could jeopardize their role in these markets, stem from a thoughtful, holistic process led by the commission — not by one-off actions from individual RTOs,” the petition says.

Four panels are envisioned as part of the technical conference, including:

    • Energy Efficiency in Wholesale Markets Today, focusing on current market structures and models for EE participation.
    • Reconciliation with Load Forecast, looking at how EE interacts with RTO load forecasts and whether market eligibility should be tied to inclusion in forecasts.
    • Eligibility, Measurement, Verification and Standards, considering whether a causality principal should be an element of participation, as well as how capacity contributions can be quantified.
    • Value Proposition of Energy Efficiency, focusing on EE compensation and its effectiveness as a supply resource.

American Efficient Pushes Back on Allegations of Tariff Violations

American Efficient is defending itself from accusations the company violated the PJM and MISO tariffs in the design of its mid- and upstream energy efficiency (EE) programs, which provide rebates to manufacturers, distributors and retailers for offering qualifying products (EL24-113).

The Independent Market Monitor has accused several EE market participants of not meeting the RPM participation requirements and has requested FERC prohibit future participation and require revenues be returned. The commission’s Office of Enforcement (OE) also has opened an investigation into American Efficient specifically. (See Monitor Alleges EE Resources Ineligible to Participate in PJM Capacity Market.)

In its response to a 1b.19 notice from the OE — which notifies parties to an investigation that the office intends to recommend an administrative proceeding or civil action — American Efficient wrote that neither the Monitor’s complaint nor the OE investigation had substantiated claims of fraud. While the open investigation is confidential, FERC publicly posted American Efficient’s response to the 1b.19 notice, an executive summary of the response, a primer with background about the company and its request for a technical conference, and materials PJM submitted about the stakeholder process.

In the primer, American Efficient wrote that allegations that the company had engaged in fraud are unsubstantiated and the details of its program were reviewed and approved of by RTO staff.

“While the Market Monitors in PJM and MISO have strong policy preferences that EERs be removed from the markets, they are not arguing (nor could they, based on the record) that American Efficient misrepresented its program when seeking approval,” the company wrote. “Instead, the allegations go directly to the fundamental features of American Efficient’s EER program. There is no support for the allegation in the Preliminary Findings that American Efficient had a scheme with an intent to defraud the markets when the features were transparently presented to the RTOs, scrutinized by RTO staff, and subsequently approved.

“Put simply, an enforcement action based upon fundamental features of American Efficient’s EER program that MISO and PJM knew and approved of would be inequitable.”

In the executive summary, the company argued that PJM’s statements in the stakeholder process that the tariff does not require a link between capacity market revenues and EE programs run against the OE’s allegations. American Efficient said its PJM subsidiary Affirmed Energy followed the tariff as written and the OE is seeking to hold it to prospective rule changes.

“The plain text of the tariffs alone demonstrates that OE is wrong — EER providers are not required to pay end users, contract with end users, or prove that end users bought energy efficient products solely because of the provider’s program,” the company wrote. “Now that PJM has publicly stated its views about the tariff, affirming American Efficient’s position and rejecting OE’s position, that should conclusively settle the matter — OE has been wrong all along.”

The materials PJM provided to the OE state the tariff interpretation the RTO offered throughout the stakeholder process is in contradiction with the OE’s allegations.

“Through this process, PJM has clearly communicated in both verbal comments and public documents its view of the current rules — a view that is in direct contradiction to the Office of Enforcement’s assertions about the requirements of PJM’s tariff,” the RTO wrote.

In its filing to eliminate EE, PJM again stated there is no requirement that there be a causal link between capacity market revenues under the status quo rules and EE programs and that it is seeking only to bar EE participation for future auctions.

“PJM seeks to apply the proposed market rule change on a prospective basis and is not proposing to unsettle RPM auction results or undo any existing energy efficiency resource commitment under the current tariff and RAA rules,” PJM wrote. “The filed rate doctrine precludes retroactive changes for past actions where legal consequences have attached. As a result, energy efficiency resources that cleared the RPM Auctions for the 2025/2026 delivery year will need to follow through on their commitments and submit compliant post-installation measurement and verification plans in advance of that delivery year to substantiate their cleared quantities.”

In its 1b.19 response, American Efficient also wrote that the OE is singling out the company for a “market-wide policy matter” that should be resolved by rule changes rather than enforcement actions. The company repeated recommendations that FERC hold a technical conference to discuss how EE participates in capacity markets, focusing on whether they should be a supply-side resource, how capacity contributions can be measured and verified, and the rules around ownership of capacity rights to EE savings.

In addition to the allegations made regarding its participation in PJM’s capacity market, American Efficient wrote that MISO had found deficiencies in the capacity offered by its subsidiary Midcontinent Energy following an audit in 2021. While the company disputed the filing, Midcontinent opted to not seek to offer capacity in MISO’s market once the OE had supplied notice of its investigation.

A second complaint seeks the elimination of EE from the RPM and argues that the addback violates PJM’s tariff — a position also taken in a complaint the New Jersey, Maryland and Illinois consumer advocates filed. A complaint submitted by CPower alleges PJM overstepped in issuing guidance ahead of the 2025/26 BRA that tightened the auction participation requirements, substantially curtailing EE participation.

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PJM Stakeholders Voting on Hourly Reserve Notification Times

PJM’s Reserve Certainty Senior Task Force (RCSTF) is voting on a PJM proposal to add hourly differentiated notification times to the RTO’s day-ahead (DA) energy market. (See “Hourly Notification Times,” PJM MRC/MC Briefs: Aug. 21, 2024.) 

During a Sept. 5 task force meeting, PJM’s Joe Ciabattoni said generation notification times have become an important input for determining reserve eligibility, especially for offline, non-synchronized resources.  

The vote is being conducted virtually through Sept. 12, with expedited endorsement sought at the Markets and Reliability Committee and Members Committee on Sept. 25. The tightened schedule would allow for the changes to become effective for the upcoming winter. 

Hourly notification times can only be submitted in the real-time (RT) market, creating a discrepancy that Ciabattoni said can lead to units being assigned a DA reserve commitment that they cannot carry with their RT notification times. 

Joel Romero Luna, senior analyst with the RTO’s Independent Market Monitor, said the main use case for changing hourly notification times is to allow gas-fired generators to reflect pipeline restrictions that cause them to become less flexible. He said the Monitor has guidelines for how generators should use notification times to reflect gas nomination cycles, so there shouldn’t be much variety in how notification times are used. 

The change would require revisions to Manual 11: Energy & Ancillary Services Market Operations and Tariff Attachment K. 

Rebecca Stadelmeyer, Gabel Associates’ director of RTO services, suggested that the proposed language allowing hourly notification times used to commit non-synchronized and 30-minute reserves be consistent with references throughout Manual 11 and suggested replacing the 30-minute reserve with secondary reserves. Ciabattoni said PJM will consider the amendment. 

Task Force Shifting to Long-term Work Areas

PJM’s Danielle Croop said the RTO is not planning to rework a proposal to replace the 3,000-MW target for 30-minute reserve procurement with a formula that accounts for forecast peak loads and gas contingencies. Following the MRC’s rejection of the package in July, stakeholders told PJM they were uncomfortable with the lack of tariff language to accompany the change. (See “Stakeholders Endorse Reserve Rework, Reject Procurement Flexibility,” PJM MRC Briefs: July 24, 2024.) 

Croop said PJM believes the status quo language allows the change by pointing to the manuals to determine the reliability requirement. In the absence of further direction from stakeholders, she said it is not clear how PJM should proceed. 

Task Force Chair Lisa Morelli said in future meetings, the working group will pivot to its long-term work, which includes creating reserve product participation requirements and incentivizing resource flexibility. 

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FERC Approves $3B BlackRock Deal for Global Infrastructure LLCs

FERC on Sept. 6 approved a deal in which BlackRock seeks to buy all the limited liability company interests in Global Infrastructure Management for $3 billion in cash and 12 million shares of BlackRock Funding (EC24-58). 

Global Infrastructure owns or controls 6,937 MW of generation in CAISO, 606 MW in PJM, 463 MW in ISO-NE, 787 MW in SPP and generation outside RTO/ISO markets. The company also is trying to buy 50% interest in North East Offshore, Revolution Wind and South Fork Wind, which are developing offshore wind off the Northeast, and it has investments in FERC-regulated natural gas infrastructure. 

BlackRock is a publicly traded investment management firm that controls gas-fired resources in various parts of the U.S., including 3,374 MW in PJM, 1,042 MW in Arizona and 945 MW in Georgia, as well as other facilities that fall under FERC jurisdiction. 

The application drew a joint protest from Public Citizen, and the Private Equity Stakeholder Project and Sierra Club separately protested it.

The two firms’ capacity overlaps in CAISO and PJM, where, after the deal is completed, BlackRock would control 10 and 2.2%, respectively, of generation in those markets. The percentage in California was high enough to require the applicants to run a delivered price test, which showed the combination lacks a material competitive effect on CAISO’s market. 

The joint protest argued otherwise, saying BlackRock should have to include any utility in which it holds 10% or more voting shares, which represents more than 20 firms. BlackRock said its shares in those firms are covered by an effective blanket authorization from FERC and it does not control them. (See BlackRock Decision Unearths FERC Wariness of Investor Influence on Utilities.) 

FERC agreed with the applicants’ findings that the deal would not impact horizontal market power and agreed that BlackRock does not need to include its investments covered by the blanket authorization in the analysis. 

BlackRock does not exercise any control over those utilities, so it does not need to include their generation in the delivered price test, FERC said. 

The joint protest argued the application is silent on how BlackRock can manage its passive ownership of voting shares of utilities that compete with its active, direct holdings. They argued FERC should conduct a formal reassessment of the blanket authorization as part of its review of the deal with Global Infrastructure. 

FERC said under the blanket authorization, BlackRock agreed it would not exercise control over the day-to-day management of any covered utilities. It would be required to file a separate application if it sought to exercise direct control over the management or operations of a utility outside of that authorization, as it did with the Global Infrastructure deal. 

“We decline to reassess BlackRock’s blanket authorization in this proceeding or to hold a hearing on BlackRock’s blanket authorization at this time,” FERC said. “Questions about the conditions applicable to BlackRock’s blanket authorization are beyond the scope of this proceeding.” 

‘Economic Reality’

Commissioner Mark Christie wrote a concurrence to the order saying he’s long been concerned about huge asset managers like BlackRock seeking to acquire interests in utilities. (See FERC Reconsidering Blanket Authorizations for Investment Companies.) 

“The influence that large shareholders, BlackRock or otherwise, can potentially exert across the consumer-serving utility industry should not be underestimated,” Christie said. “Such horizontal shareholdings pose the threat of decreased innovation, reduced competition and ultimately higher prices to consumers, as well as the prospect of chilling investment in exactly the new generation resources we need to meet increased demand for power and to enhance the reliability of the grid. So this is an issue that deserves much greater scrutiny, as I have stated before.” 

BlackRock already owned passive shares in IPPs in California and is expanding its active control over more of them, but FERC cannot examine the issues cited in the protests due to the blanket authorization. 

“You do not need a Ph.D. in economics to see the potential for anticompetitive conduct and outcomes when an investment entity like a huge asset manager seeks to own generation assets that will be — or should be — competitors,” Christie said. “Market power is an ever-present concern, and one rule I taught my law students is that any seller with market power will use it. That’s not a moral judgment, just economic reality.” 

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CAISO Interconnection Enhancements Proposal Still in Flux

The issue of how to allocate transmission plan deliverability (TPD) for projects with long lead-time network and reliability upgrades remained the center of discussion at a Sept. 4 CAISO Interconnection Process Enhancements Working Group meeting. 

The stakeholder group focused in part on whether to retain or do away with TPD allocation Group D. (See CAISO IDs More Challenges in Refining Interconnection Process.) 

CAISO allocates TPD to projects separated into four groups. Group A is for customers with executed power purchase agreements and those in the current queue cluster that are load-serving entities serving their own load. Group B includes those actively negotiating a PPA or on a shortlist. Group C is for those that have received commercial operation for the capacity-seeking TPD.  

Group D consists of interconnection customers electing to be subject to the Generator Interconnection and Deliverability Allocation Procedures (GIDAP) section (8.9.2.3) in CAISO’s tariff. Being part of that group comes with certain requirements that the ISO and stakeholders considered potentially too restrictive. An interconnection customer in Group D cannot request suspension under the ISO’s Generator Interconnection Agreement (GIA), delay providing its notice to proceed as specified in its GIA or delay its commercial operation date (COD) beyond the date in its interconnection request.  

In the Track 3 revised straw proposal, CAISO proposed eliminating Group D.  

Bob Emmert, CAISO senior manager of interconnection resources, said cluster 14 of the CAISO interconnection queue included many projects that were unable “to get an allocation through the PPA path or shortlisted path, so they went and chose the allocation group D path.” 

“So, a lot of capacity was allocated to those projects, which is actually impacting the [number] of projects that can be studied in cluster 15,” Emmert said. “We didn’t think that was really the best way to go — to, each year, give out some conditional type of allocations through allocation group D and then kind of shortchange the next cluster group on the number of projects that can be studied.”  

But some stakeholders were concerned about eliminating the group, given the long timelines for developing transmission.  

“The prospect of requiring a short list or PPA to secure deliverability when the resource may not be able to come online and secure deliverability for approximately 10 years is problematic because contracting that far into the future increases risks,” said a presentation given by the American Clean Power Association-California (ACP-CA) during the meeting.  

Group D was initially created to give off-takers more assurance for an allocation within the procurement process. Rather than having to wait for the results of the next TPD allocation cycle, some projects will already know they have an allocation, providing increased certainty for LSEs. In light of that benefit, Emmert reversed the ISO’s initial suggestion to get rid of the group and instead suggested removing its restrictions and retaining it.  

“The pro in this is … it works well for the process where people are negotiating a PPA and they know whether they have an allocation or not if they follow through with a PPA in time,” Emmert said. “The con is it will impact the next cluster by reducing the number of projects that would be studied.”  

‘Conditional Deliverability’

In its presentation, ACP-CA offered a proposal to revise the treatment of Group D, which could be a middle ground between retaining and doing away with the group.  

“We share the concerns that have been expressed and the issues CAISO has raised around long development timelines for transmission projects and upgrades and aligning those with reasonable commercial timelines,” said Caitlin Liotiris, a principal at Energy Strategies, who spoke on behalf of ACP-CA. “We also recognize the importance that Group D has played in the commercial process to date, and so are kind of eager to consider an alternative approach to Group D that might continue to provide some of the benefits of the past, perhaps with some additional timeline considerations to help better align the interconnection and TPD allocation timelines with more realistic and achievable commercial milestones.”  

ACP-CA’s proposal involves retaining Group D and renaming it “conditional deliverability,” making any deliverability allocated to this group “conditional.”  

The conditional deliverability allocated would not reduce the calculation of deliverability available for future clusters under the zonal approach and the 150% zonal limits.  

Priorities would be assigned to conditional deliverability allocations, where the first group of projects with this allocation in each TPD allocation cycle would be given first priority, and so on. The priority positions would tell off-takers the likelihood of the project receiving a “standard” group A, B or C deliverability allocation. Rules for determining which projects would be able to convert from conditional deliverability would still need to be established, Liotiris said, such as how to prioritize projects with a PPA over those short-listed or whether to use a scoring methodology.  

The ISO said it would need more time to consider whether the proposal could be implemented as part of the interconnection process.  

“I think the ISO team needs to come together and discuss this a little bit more,” said Danielle Mills, CAISO principal of infrastructure policy development. “I think there may be some changes to the study process involved in implementing a proposal like this, but it’s probably a little early for us to explain what those would be until we think about it a little further.”  

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Study: HVDC Needs Standards to Take off in US

HVDC transmission lines can help efficiently connect offshore wind power, meet growing demand onshore and link together the balkanized grid, but before their use can be expanded in the U.S., the OSW industry needs to set some standards, according to a joint company survey.

DNV’s HVDC Standards joint industry project (JIP), which finished its first phase in April, was convened to identify deficiencies in standards for HVDC. DNV worked with Atlantic Shores Offshore Wind, EDF Renewables, Equinor, Invenergy, National Grid Ventures, Ocean Winds, PPL TransLink, WindGrid, RWE, Shell and TotalEnergies.

The firm launches JIPs when a need crops up in the industries it covers for firms to come together and work on a common issue. While HVDC lines have been growing in the U.S., the domestic industry and regulators still lack key standards to deal with how the technology impacts the grid, DNV Principal Consultant Morgan Putnam said in an interview.

“If you look at Europe, there’s a lot of work that’s been done over the last decade to think through the various ways that an HVDC transmission system can operate and the various services that it can provide to the grid,” Putnam said. “And in order to be able to enable those services, you have to define certain aspects of what the system will and will not do, so that you understand how it will impact the rest of the grid. … We really haven’t thought through that for the North American grid.”

The AC backbone of the grid has been in place for over a century, so the country has not had to look at basic standards for it in generations, he added.

Putnam said the JIP’s work is expanding to a “much larger effort” with the Department of Energy, National Renewable Energy Laboratory, RTOs, utilities and others. DOE will be funding a study process that lasts several years to identify gaps in standards, come up with a plan to fill them, and then implement that plan and remove barriers to wider use of HVDC.

High-voltage lines operate much better underground or underwater than AC transmission, and the technology offers efficiencies for long-haul overhead lines. Their power density is also higher than AC, meaning more power can flow over less actual infrastructure, DNV Principal Consultant Cornelis Plet said in the interview.

The JIP has identified 25 different standards that need to be defined, including active power control, reactive power control, power recovery requirements, emergency power control and islanded operation.

The standards include issues at the national, regional and local levels. The developers that DNV worked with on the first phase came up with five areas that they want to see addressed the most: offshore design standards, performance standards, reliability standards, ISO/RTO manuals and utility interconnection manuals.

“As we are looking at substantially more HVDC projects going forward, in order to have a more efficient process, we really do want to standardize these 25 functional requirements,” Putnam said. “And, so, what we’ve looked at is in the U.S., there’s about 10 of them where there’s some partial standardization, and then there’s 15 that there’s not any coverage at all.”

Even the partially completed standards include plenty of work because they often address just one of the three to four likely use cases of HVDC transmission, he added.

Getting all the standards in place in the U.S. will require working with multiple agencies who oversee different aspects of the industry, compared to Europe where one grid code offers some standardization even across different countries, Plet said.

“There are a number of different hierarchical organizations that create rules that transmission providers have to adhere to,” Plet said. FERC sets very high-level technical principles; he noted that last year it mandated HVDC as part of the transmission planning process. NERC sets the minimum technical standards for reliability, but Plet noted that many of their rules for HVDC are designed for overhead lines and need updates for subsea and buried cables.

Regional reliability entities have their role to play, as do ISOs and RTOs, which have to come up with ways to handle the technology in their interconnection and operational requirements.

“This is where developers of HVDC links often run into problems because ISOs often don’t know how to treat an HVDC line,” Plet said. “There’s no specific class for it. Is it a generator? Not really, but it sometimes behaves a little bit like one. Is it a transmission line? Also not really, but it does have some of the transmission line functions. So how [do you] distinguish between that and … create some clear connection requirements for HVDC systems that are not conflicting on both ends of the line? … And this includes not only how should it be studied, but also how can it participate in the different power markets.”

One hot topic has been whether an HVDC line designed to ship power from one region to another can participate in the capacity market on the delivery end, he added.

State regulators also have a role to play in that they are ultimately responsible for ensuring that consumers do not pay too much for energy, Plet said. The New Jersey Board of Public Utilities and New York Public Service Commission have mandated the use of HVDC lines for the offshore wind those states have procured, he noted.

Getting the standardization in place is a key hurdle to making HVDC a normal part of system planners’ toolbox; Plet argued that the technology will be vital to expanding the transmission system.

“You need HVDC,” Plet said. “You will not be able to build out enough new transmission capacity without it.”

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NYISO Slightly Lowers Expected 2034 Shortfall

RENSSELAER, N.Y. — NYISO last week updated stakeholders on its draft Reliability Needs Assessment, which still shows an expected capacity shortfall by 2034, though it is slightly less than what was initially presented in July.

The ISO told the Transmission Planning Advisory Subcommittee on Sept. 3 that it had increased its assumption of special-case resource elections by about 200 MW. That resulted in a slightly lower loss-of-load expectation of 0.254 — still well above the required 0.1.

NYISO in July said it expected to be short by at least 1 GW, with an LOLE of 0.283, by 2034. (See Prelim NYISO Analysis: 1-GW Shortfall by 2034.)

The ISO also revised down New York City’s transmission security margin deficit, from 275 MW to 97 MW, by updating its load distribution model.

“We continue to see statewide resource deficiency by 2034,” said Ross Altman, senior reliability manager for NYISO.  “That is still driven by increasing demand, continued additions of large loads and unavailability of gas during winter peak conditions.”

In response to a stakeholder question, Altman said NYISO estimates the statewide resource adequacy need to be about 800 MW, but it “could be as high as 1,875 MW” for transmission security. “It’s very hard to put a number on it,” he said.

The TPAS and Electric System Planning Working Group will review the draft RNA later this month. The Operating and Management committees are expected to vote on it next month, with a Board of Directors review and vote in November.