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July 21, 2024

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Demand Growth Takes Center Stage at NARUC Summer Policy Summit

WEST PALM BEACH, Fla. — The return to demand growth in the electric power industry has been a major theme this year, and it dominated the discussion at the National Association of Regulatory Utility Commissioners’ Summer Policy Summit last week. 

“We’re hearing more and more about the increase of load and demand on our system every day,” FERC Chair Willie Phillips said. “Not just regular run-of-the-mill increases. … We’re talking about sharp, material increases on our system.” 

The issue varies regionally, with some areas already feeling a tighter supply-and-demand balance because of the growth in data centers, reshoring of manufacturing, electrification of home heating and transportation, and increasingly extreme weather, Phillips said. 

Thousands of Houston-area customers were without power for a week at the peak of summer after Hurricane Beryl, while other parts of the country were facing major heat waves, with D.C. seeing triple-digit temperatures as NARUC was meeting. 

Conservative estimates have demand growing nationally about 1%/year, which over the next five years could add up to 5,000 TWh of new demand. FERC has issued a series of major rules, including Order 2023 on interconnection and Order 1920 on transmission planning and cost allocation, that Phillips said would help the situation. Order 1920 will help expand transmission to deal with those new drivers of demand while maintaining reliability and affordability, he said. 

“I know that not every commissioner in this room has embraced Order No. 1920, or 1977,” Phillips said. “Not every commissioner on FERC has embraced No. 1920.” 

But the industry needs to start moving forward on planning for the future, as demand is growing, and Phillips said the order’s focus on long-term planning with a broad set of benefits will get much-needed steel in the ground. 

“We have to consider grid-enhancing technologies as well,” Phillips said. “So, there is a requirement both in Order Nos. 2023 and 1920 to consider grid-enhancing technologies as we build out our system.” 

Order 1920 was the subject of dissent from FERC Commissioner Mark Christie, whom Phillips called his friend from before their time as federal regulators. Phillips was on the D.C. Public Service Commission when Christie was on the Virginia State Corporation Commission, and the two neighboring state regulators regularly worked together at NARUC and the regional Mid-Atlantic Conference of Regulatory Utilities Commissioners. 

Christie spoke at the conference after Phillips, and he basically agreed on the dominant theme of the event, though he framed it as reliability and said it was the states — much more so than FERC, or the ISOs and RTOs — that had the power to ensure it going forward. FERC does oversee reliability standards for the bulk power system, but it has limited authority when it comes to actually building needed infrastructure. 

Section 215 of the Federal Power Act says FERC has no authority to order the construction of any utility asset, whether generation or transmission, Christie said. 

“That’s the states; you are the IRP [integrated resource plan] planners,” he added. “When it comes to resource adequacy … that’s under state jurisdiction. You’re the ones who decide what generator units are going to get built. You’re the ones who decide what generator units are ultimately going to be retired.” 

RTOs’ primary role is to run the system and to make sure they can balance the grid, which is important. The organized markets will say when they see trouble brewing on the reliability front; Christie said many of their communications on those lines in recent years showed a brewing crisis for the grid. 

“Yesterday at 4:30, PJM peaked on this hot day; PJM peaked at about 153 GW of load. … They had 9 GW in reserve. That’s 6%,” Christie said July 16. 

July 15 was one of the hottest days of the year, and despite PJM using almost all its generation to meet the day’s demand, the RTO is expecting to lose up to 50 GW in the coming years, Christie said. “That arithmetic does not work.” 

Other RTOs are also forecasting retirements and seeing thinner reserve margins, which Christie said is a recent phenomenon. For most of his tenure on the SCC, Virginia’s utilities would come in with load growth projections that nobody believed because they were always flat from the previous data, and the numbers were coming at a time when PJM was very long on capacity. 

That changed toward the end of Christie’s tenure at the SCC and has continued during his tenure on FERC. Virginia has been home to “Data Center Alley” for decades, and while that used to be focused around the D.C. area, it has stretched down I-95 to Richmond in recent years, Christie said. 

“When you are doing load forecasts now, you’ve got to really get those things right,” Christie said. “And then you’ve got to take seriously what they are showing.” 

Demand Growth Projections

Grid Strategies President Rob Gramlich presented his organization’s report released late last year about the change in demand growth trends. (See Grid Planners Predict Sharp Increase in Load Growth.) 

The five-year load growth forecast doubled in one year, Gramlich said, with some regions like Dominion Virginia Power and ERCOT seeing higher load growth than the average. The new load is coming from reshoring manufacturing, data centers and electrification. Data centers alone may contribute 1% demand growth annually. 

Addressing that demand growth will require enhancing the distribution and transmission systems, as well as ensuring the grid has enough energy around the clock and important reliability services like inertia and ramping, Gramlich said.  

While 1% load growth does not sound like that much, it is double what had been the norm in recent years, and over time, it can really add up, said former FERC Commissioner Tony Clark, senior adviser at Wilkinson Barker Knauer. The numbers also vary significantly by region. 

“This is a paradigm shift that is probably perhaps not unlike the paradigm shift we saw with fracking and availability of natural gas in terms of impact on the industry itself,” Clark said. “So, it’s a big deal.” 

The new demand growth is coming at a time of traditional generators retiring, and the replacements tend to be renewables, which offer plenty of energy, but not nearly the same amount of capacity as traditional power plants, Christie said. 

Clark brought up the same issues about replacing retiring generation, and he argued that no “silver bullet” exists to deal with the projected gap as demand grows. 

“In all probability, to me, it looks like probably some sort of mix of natural gas and renewables in the near-term future because that’s what we have available today,” Clark said. 

Other options, like long-term storage, small modular reactors or other kinds of advanced nuclear, are not immediately available, so serving the demand reliably is going to be a real challenge, he added. 

The Impact of Vehicle Electrification

While forecasts always carry uncertainty, some of the load growth is already baked in, with Alliance for Automotive Innovation CEO John Bozzella saying California’s rules on vehicle mileage, which have been adopted by states representing 40% of the market, will require 35% of their vehicles be electric in the coming years. 

But many consumers have started to sour on electric cars because charging infrastructure has not kept up with demand. According to AAI’s latest report, as of the first quarter this year, the U.S. had 167,213 charges for 4.7 million electric vehicles, for a ratio of 28 to 1, while 1 million are needed by 2030 to meet projected demand. 

McKinsey & Co. has found that 46% of current owners are likely to switch back to gas-powered vehicles (compared to 29% globally), and the biggest reason is the lack of public chargers, Bozzella said. 

The impact on the grid of electrifying medium- to heavy-duty vehicles represents much bigger loads. Environmental Defense Fund Attorney Cole Jermyn said fleet managers are planning to transition a year or two ahead of time, which is shorter than most utility planning cycles. 

“If they’re a large fleet, that’s a multi-megawatt load that, depending on the grid infrastructure, can take several years — well longer than the fleet actually knows their plan — to complete the substation, the feeder or transformers, or whatever it is that they need to actually bring their chargers online,” Jermyn said. “So, … the pace of the electrification is creating this disconnect that requires proactive efforts to prepare for.” 

FERC Chair Willie Phillips addresses NARUC’s Summer Policy Summit. | © RTO Insider LLC

It is possible for utilities to proactively plan for major fleet electrification because they are in specific neighborhoods, whereas light-duty vehicles are spread around utility territories, he added. 

While estimates vary for how quickly both consumers and businesses will electrify their vehicles, even the low-end predictions represent significant new loads, said Ben Shapiro, manager of RMI’s Carbon-Free Transportation team. 

“Utilities understandably want to be sure, to the extent possible, that they’re going to get cost recovery,” Shapiro said. “And they don’t have a ton of incentive to be more proactive in this space under the existing paradigm.” 

That requires reducing the uncertainty to improve decision-making, shifting to a more targeted approach to addressing future load growth, and finding new ways to mitigate and share risk across parties, he added. 

One area that can help improve load forecasting is “vehicle telematics” that show utilities where fleets are driving and parking now to inform future charging needs, Shapiro said. Another policy that would help is ensuring that the existing infrastructure is used efficiently to help avoid overbuilding distribution system upgrades. 

The federal Joint Office of Energy and Transportation, which combines the efforts of both departments on the transition to EVs, has a plan to start working on expanding electrification around the country, said Jean Chu, an analyst for the office. 

“Our intention is to capitalize public and private investment to accelerate the industry activity and to signal the utility and electric utility and hydrogen market to plan and deploy the necessary generation, transmission and distribution projects,” Chu said. 

The plan would prioritize areas likely to be early adopters of medium- and heavy-duty vehicle electrification first, and then link those regions together along the existing highway network. Once the biggest areas are connected in the next decade, the departments would shift their focus to electrifying the rest of the country, Chu said. 

Data Center Expansion

Constellation Energy has the largest competitive retail business serving the commercial-and-industrial sector, but Chief Strategy Officer Kathleen Barrón said they do not have any better idea of what future demand will be than others presenting at NARUC. 

Hydrogen was supposed to be a major driver of load growth, but issues around tax credits have at least delayed that, and the shift toward electrification has also waned in recent years. Now the latest issue is data centers scaling up as new technologies require more capacity from them. The Electric Power Research Institute released a report on data centers recently, and its forecasts vary widely, Barrón said. (See EPRI: Clean Energy, Efficiency Can Meet AI, Data Center Power Demand.) 

“Some of the developers are looking at different sites for the same project, so I think that they contribute to a little bit of double counting,” Barrón said. 

Data center developers are taking a page from the renewable industry, where they propose multiple projects to find out where it is cheapest to plug into the grid, with more expensive alternatives never coming to fruition. 

“But in general, of course, we do see greater load growth moving forward than we have historically,” Barrón said. “So the question is, how do customers plan to meet that demand? What we’re seeing is an increasing number of them looking to power their operations with zero-carbon electricity.” 

Policies are pushing the industry cleaner, but many large data center customers want to go even further and power their operations with 24/7 clean electricity, she added. Constellation can meet their demands in a variety of ways, including linking multiple large customers as off-takers under power purchase agreements with new renewables, and it also owns and operates the largest domestic fleet of nuclear reactors. 

The demand for data centers needs to be met with states offering incentives to site them in their jurisdictions and the federal government seeing the issue of artificial intelligence technology as a key national security issue, Barrón said. 

While AI technology is more energy intensive than traditional internet use, Briana Kobor, Google’s head of energy market innovation, noted that data centers are used every time customers surf the internet on their smartphones and are involved in huge parts of the economy generally. 

“In 2020, the digital economy accounted for over 10% of U.S. GDP and [employed] nearly 8 million people,” she added. 

AI might currently be dominated by chat bots and the production of “funny pictures,” but the technology could revolutionize how humanity deals with some of its biggest problems, Kobor said. 

About 4% of PJM’s overall load goes to serve data centers, as it is home to a large share of the 2,700 facilities around the country, with many of them in Northern Virginia, but also other areas the grid operator serves, such as Columbus, Ohio, said Jason Stanek, the RTO’s executive director of government services. 

While some of the projections could be influenced by speculative data centers, load is growing in ways that were unexpected just a few years ago. PJM is increasingly focused on figuring out exactly where the new data centers are actually going to plug into the grid, and it has surveyed the local delivery companies in its footprint to get better data in its load forecasts. 

“We ask our utilities within PJM to report back whether or not we need revisions to reflect large customers coming on board,” Stanek said. “The question is whether or not these data centers are shopping around; we’ll see multiple data centers show up.” 

The data PJM gets back from its member utilities will be included in a new forecast that is released in January 2025, he added. 

Google agrees that there is likely some duplication in the amount of data center demand being projected, and it is important to get the numbers right; as a customer it wants to avoid overbuilding the system, Kobor said. 

“We have a shared interest in making sure that we do not end up with an overbuilt system and get stranded costs at the end of this, just like any other ratepayer,” she added. “So I encourage folks to continue that conversation with us as we continue down this journey. And I think we are likely in a point of greatest uncertainty, and we’re going to start to see greater clarification as we move forward.” 

Getting that clean supply from the grid can be complicated for data centers, which have a shorter development time than it takes to build new generators, interconnect them to the grid and expand transmission to deliver new power to load, Barrón said. That has driven interest in data centers and other large customers to link up directly to nuclear plants and avoid using the grid altogether. 

The issue of data centers connecting directly at nuclear plants is pending in a case at FERC, in which Constellation has intervened to argue that the commission should let such deals happen — though others have said it could bring up issues around cost shifting and eventually even reliability. (See Talen Energy Deal with Data Center Leads to Cost Shifting Debate at FERC.) 

Locating at nuclear plants also avoids “NIMBYism” because they are always built on large swaths of land. Such deals also avoid building out the transmission and distribution systems to accommodate major new loads, avoiding socializing those costs to other customers. 

Nuclear plants are currently benefiting from a tax credit that has prevented additional retirements, but that is going to sunset in eight years, and forecasters expect nuclear retirements will resume when it does, Barrón said. 

“If you have a customer that was willing to commit to long term, you wouldn’t have to be concerned about that,” she added.

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BPA Stepping up Participation in Pathways Initiative

The Bonneville Power Administration is ramping up its engagement with the West-Wide Governance Pathways Initiative, an executive with the federal power agency said July 18.

That means BPA will shift from a previous stance of mostly monitoring developments in the Pathways Initiative to fully participating in its looming efforts to change California law to relax some provisions of CAISO’s state-run governance and shape a new “regional organization” (RO) to oversee a Western electricity market based on the ISO’s Western Energy Imbalance Market (WEIM) and Extended Day-Ahead Market (EDAM).

However, the stepped-up involvement in Pathways doesn’t signal a change in BPA staff’s “leaning,” issued in April, recommending that the agency choose SPP’s Markets+ over EDAM when it opts to join a day-ahead market, according to Doug Marker, an intergovernmental affairs strategist at BPA. (See BPA Staff Recommends Markets+ over EDAM.)

“This does not represent a change in our staff recommendation, nor an endorsement of EDAM or the Pathways conclusions, but we feel it’s important to be involved to understand the issues that are shaping the structure of Pathways,” Marker said during a BPA day-ahead markets workshop.

“At the end of the day, should this be successful — and obviously we share the objective for bringing independence to CAISO market governance — we will have customers who are served through the markets that are governed through this process, and we will at least be a neighboring entity for the market,” he said.

Marker said BPA declined to participate in Step 1 of the Pathways effort, which crafted a plan to elevate the authority of the WEIM’s Governing Body to the greatest extent possible without altering California law, because it was heavily involved in drafting a tariff for Markets+. SPP filed the proposed tariff with FERC in late March. (See SPP Files Proposed Markets+ Tariff at FERC.)

CAISO last month kicked off the stakeholder process for adopting the Pathways Step 1 proposal, and Marker noted that BPA had submitted comments after the first meeting in that effort. (See CAISO Kicks off Stakeholder Process for Pathways Initiative.)

BPA is expanding its engagement just as Pathways begins to pursue parallel “work streams” in Step 2 of its effort. (See Busy Summer Ahead for Pathways Initiative.) Marker said the agency assigned staff to four of the initiative’s six newly created workgroups, including those dealing with CAISO tariff analysis, stakeholder processes, RO governance and public interest issues, “which is really talking about the role of a states committee and possibly consumer advocates in the governance structure for the RO.”

“We’ve said we want two viable options, and so we are participating from the perspective of improving the viability of the EDAM alternative,” he said.

‘Material Difference’

Marker said it’s important to BPA that Pathways’ discussions “be done as transparently as possible,” echoing a criticism that some stakeholders have shared with RTO Insider: that much of the effort has been developed in closed-door meetings, punctuated by monthly public progress reports. (Pathways participants have pointed out that all votes by the group will be held publicly.)

“So, we urge the Pathways’ Launch Committee to make the workgroup meetings open. It was a decision for us to participate even if the meetings are not open, but we think that the open meetings improve the transparency and the ultimate strength of the proposals that emerge from it,” Marker said.

That last comment prompted a sharp response from Launch Committee Co-Chair Pam Sporborg, director of transmission and market services at Portland General Electric.

“I’ll note that Pathways is not a decision-making body,” Sporborg said. “We’re a temporary volunteer group that is coming together to suggest ideas and concepts to formal decision makers across the west, to the CAISO board, California elected officials and to the broader West. We’re not drafting a tariff like Markets+. We’re not a formal stakeholder process. We have turned over our recommendations to that formal [CAISO] stakeholder process, which is ongoing, as you noted.”

Sporborg pointed out that BPA has participated in efforts with a similar process of public and non-public meetings, such as the Western Power Pool’s Western Resource Adequacy Program (WRAP) and Western Transmission Expansion Coalition (WestTEC).

“It seems interesting to call out Pathways uniquely, given that Bonneville’s participation in those other structures that really have a steering committee focus and do hold those kinds of private coordinating meetings with separate and intentional opportunities for public engagement,” she said.

BPA Director of Market Initiatives Russ Mantifel, who’s been leading the agency’s day-ahead markets process, countered that he thinks the process for developing Markets+ was transparent from the beginning, with publicly noticed meetings and open invitations to any concerned parties.

“In terms of WRAP and WestTEC, I don’t think it’s Bonneville that is asking for those things not to be public. In addition to [the Western Markets Exploratory Group], as well, we were open to everything being open,” Mantifel said, adding that Bonneville is required to be transparent and that “raising the bar” on transparency “is what we should be doing.”

“I also think that the Pathways Initiative is explicitly trying to develop a market that will set the prices for every consumer in the Western Interconnection,” he continued. “… At least that’s what we’ve heard: is that the goal is to create a single market and the benefits are assuming a single market that’s serving load to every retail load in the West. So, I think that that is a material difference.”

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MISO Closing in on Final, $25B LRTP; Monitor Repeats Reservations

CARMEL, Ind. — MISO’s $25 billion, mostly 765-kV long-range transmission package for the Midwest region is nearing finalization, while the Independent Market Monitor continues to doubt the necessity of the projects. 

The Monitor is penning a memo spelling out his concerns with MISO’s assumptions behind its long-range transmission planning. 

Despite that, the lines are advancing to MISO’s business case testing, where they will be analyzed against its nine benefit metrics. MISO will release the business case for the portfolio in September. 

“The benefits metrics process has been well reviewed,” Executive Director of Transmission Planning Laura Rauch told the Organization of MISO States’ board of directors July 16. She said MISO solicited extensive stakeholder feedback and is “fairly comfortable” with the metrics it is advancing. 

Rauch said MISO will hold multiple workshops with stakeholders to go over the business case for the new batch of LRTP lines. 

“We’re at the stage, using an airplane analogy, where we’ve landed and we’re on the tarmac,” Director of Economic and Policy Planning Christina Drake told stakeholders on a July 17 teleconference. 

MISO has yet to factor in the cost of underbuild projects into the second LRTP portfolio. 

Drake said MISO’s first, $10 billion LRTP portfolio in MISO Midwest minimized the need for underbuild projects to support the second portfolio. MISO uses the term “underbuild” for the secondary, lower-voltage transmission upgrades necessary to support a 765-kV network in the Midwest region without worsening existing constraints. 

While MISO considers its benefit metrics a done deal, the Monitor still harbors serious concerns over the metrics and says two should be outright deleted. (See MISO IMM Knocks LRTP Benefit Calculations; RTO Poised to Add More Projects.) 

This month, IMM David Patton said he scheduled meetings with MISO planners to outline his concerns with the metrics, though he acknowledged little progress on a compromise. 

“I don’t think the MISO board understands how serious these concerns are,” Patton said told the Board of Directors’ Markets Committee on July 11. “We haven’t seen a lot of movement to address either the concerns on the [second transmission future] — which we view as very unrealistic — or MISO’s benefits process.” 

Patton said he remains hopeful that MISO is open to altering its project portfolio to assemble the “most least-regrets” collection of transmission projects. 

He called MISO’s second transmission planning future “completely inconsistent” with its new, availability-based capacity accreditation and its invitation for members to develop resources with more steadfast attributes. 

MISO is using its second transmission planning future as a basis for this LRTP portfolio. It assumes that by 2042, the RTO will manage 466 GW of installed capacity with a fleet that emits 96% less carbon pollution than it did in 2005 and have a 145-GW peak load that occurs in January rather than July. 

Patton said MISO’s goal of least-regrets transmission planning is only possible when it uses “valid benefit metrics and explores the gamut of possible futures.” 

MISO has proposed using nine benefit metrics to establish a benefit-to-cost case for the portfolio, including avoided capacity costs, capacity savings from reduced line losses, congestion and fuel savings, reduced transmission outage costs, energy savings from reduced losses, lower risks during extreme weather, mitigation of reliability issues, avoided transmission investment and decarbonization. 

Patton has said it is not appropriate for MISO to place a value on decarbonization when the government already does through tax credits. He also has said the RTO should not presume that the lines will save members money on additional capacity that would otherwise have to be built. 

At the workshop, MISO was adamant that the second LRTP portfolio will accommodate Midwest members’ fleet transition plans and load growth. 

MISO said on a 20-year horizon, the Midwest should also see $3.2 billion in adjusted production cost savings, an 8.5% (20.4 million MWh) reduction in curtailment, savings to the cost of serving load and decreased price separation. The RTO also said LRTP II resolves 60% of the Midwest’s 200-kV and above constraints that could trigger contingencies and more than 70% of thermal violations for all voltage levels. 

miso LRTP

The Louisiana Public Service Commission in session in June | Louisiana PSC

Xcel Energy’s Drew Siebenaler said his utility’s ambitions now more closely resemble MISO’s third, 20-year transmission planning future, not the second. He asked whether MISO would test the second LRTP portfolio against its most aggressive, third planning future, as rapid load growth and fleet transformation have made it appear the most probable. 

Drake said MISO remains committed to testing the second portfolio against the “low-end bookend” and using the second transmission planning future. But the RTO is aware that the portfolio will not enable all the generation contemplated in the future. She said that’s why MISO will pursue a companion portfolio next year, with proposed lines likely popping up in the western portion of MISO Midwest. 

La. and Miss. Regulators Open Offensive Against Order 1920

Meanwhile, Louisiana and Mississippi state regulators have called on the 5th U.S. Circuit Court of Appeals to examine FERC’s recent landmark transmission planning rule. 

Attorneys for the Louisiana Public Service Commission and Mississippi Public Service Commission filed a petition for review July 15 of FERC’s Order 1920 (24-60355). 

Both state commissions claimed they are “aggrieved” by the order, which requires transmission providers to conduct transmission planning on 20-year horizons every five years. 

Former FERC Commissioner Allison Clements has said the commission used MISO’s existing planning as a model for portions of the wide-ranging transmission planning rule. (See MARC 2024 Displays Mixed Feelings on Transition Feasibility.) 

Louisiana and Mississippi, both part of MISO’s South region, have not been the focus of MISO’s LRTP planning efforts yet. The RTO has so far only proposed multibillion-dollar LRTP portfolios for its Midwest region. MISO, clean energy groups, MISO South state regulators and Entergy are currently in disagreement over how LRTP cost allocation should be handled in the South. (See related story, Clean Energy Orgs Push Entergy Players to Consider Broader Cost Allocation.) 

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PJM MRC/MC Preview: July 24, 2024

Below is a summary of the agenda items scheduled to be brought to a vote at the PJM Markets and Reliability Committee and Members Committee meetings July 24. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider. 

RTO Insider will be covering the discussions and votes. See next week’s newsletter for a full report. 

Markets and Reliability Committee

Consent Agenda (9:05-9:10)

B. Endorse proposed conforming revisions to Manual 12: Balancing Operations to implement provisions of a package to establish fuel assuredness requirements for black start resources approved by stakeholders last year. The changes would add two exemptions from penalties for fuel-assured black start resources that fall below their minimum fuel inventory due to capacity calls or storage inspections, as well as reworking the verification process. The revisions being voted on July 24 were inadvertently left out of the language approved last year despite being included in the approved package matrix. (See “Stakeholders Endorse Revisions to Manual 12 for Black Start Fuel Requirements,” PJM OC Briefs: July 11, 2024.)

Issue Tracking: Fuel Requirements for Black Start Resources

C. Endorse proposed revisions to Manual 13: Emergency Operations drafted through the document’s periodic review. The changes clarify communication processes between RTO control rooms, adding language that local load shed directives do not initiate a performance assessment interval (PAI), and remove member actions stating that gas generation owners should notify PJM of whether they have or plan to procure fuel to meet day ahead reserve commitments.

Endorsements (9:10-10:50)

1. Enhanced Know Your Customer (9:10-9:30)

PJM’s Anita Patel and Eric Scherling will present more stringent “know your customer” requirements that would require some members to provide more information about key decisions makers, owners and beneficiaries. The proposal was endorsed by the Risk Management Committee on May 21. (See “First Read on Expanded ‘Know Your Customer’ Rules,” PJM MRC/MC Briefs: June 27, 2024.) 

The committee will be asked to endorse the proposed solution and corresponding tariff revisions. 

Issue Tracking: Enhanced Know Your Customer (KYC) 

2. Performance Impact of the Multi-Schedule Model in the Market Clearing Engine (9:30-9:50)

Constellation Energy’s Adrien Ford is set to make a motion for the committee to endorse a joint PJM/GT Power Group proposal to establish a formula to select one offer into the energy market for each resource to be forwarded to the Market Clearing Engine (MCE). The proposal is intended to facilitate PJM’s goal of implementing multi-schedule modeling without causing a significant increase in MCE computation times. The proposal to be voted on July 24 was turned down by the MRC in December when the committee endorsed a different PJM proposal, which ultimately was rejected by FERC. (See “Stakeholders Discuss Path Forward on Multi-Schedule Modeling,” PJM MIC Briefs: June 5, 2024.) 

The committee will be asked to endorse the proposed solution and corresponding revisions to the tariff and Operating Agreement. 

Issue Tracking: Performance Impact of multi-schedule model in Market Clearing Engine (MCE) in nGEM Enhanced Combined Cycle (ECC) and Energy Storage Resource (ESR) models 

3. Reserve Certainty (9:50-10:10)

PJM’s Emily Barrett will present two proposals to rework how PJM determines its reserve procurement targets and how those resources are deployed. The first would replace the static 3,000-MW 30-minute reserve requirement with a formula that takes load forecasting, forced outage rates, the largest active gas contingency and the primary reserve requirement into account. It also would permit PJM to increase the 30-minute, synchronized or primary reserve requirements independently of the other two. The second proposal would send reserve deployment instructions through resources’ basepoints as the primary notification that they are being called on to provide reserves. (See “First Read on 2 PJM Proposals to Revise Reserve Markets,” PJM MRC/MC Briefs: June 27, 2024.) 

The committee will be asked to endorse the proposed solutions and corresponding tariff, Operating Agreement and manual revisions. 

Issue Tracking: Reserve Certainty and Resource Flexibility Incentives 

4. Enhancements to Deactivation Rules (10:10-10:30)

Philip Sussler, of the Maryland Office of People’s Counsel, and Clara Summers, of the Illinois Citizen Utility Board, will present amendments to the Deactivation Enhancements Senior Task Force (DESTF) issue charge to expand its scope to include proposals that create more cost-effective alternatives to reliability-must-run (RMR) contracts, which are offered to generators whose requested deactivation would prompt transmission violations. The widened scope also includes education about alternative transmission technologies that could allow violations to be resolved faster and processes in use by other grid operators. (See “Consumer Advocates Seek Wider Scope for Deactivation Task Force,” PJM MRC/MC Briefs: June 27, 2024.) 

The committee will be asked to approve the amended issue charge. 

Issue Charge: Enhancements to Deactivation Rules 

5. Review and Endorsement of IRM and FPR results for 2026/27 Delivery Year (10:30-10:50)

PJM’s Josh Bruno will present revised installed reserve margin (IRM) and forecast pool requirement (FPR) values for the 2026/27 delivery year to reflect market design changes made since the 2023 Reserve Requirement Study (RRS) was completed. Drafted through the Critical Issue Fast Path (CIFP) process last year, the market changes include accrediting nearly all resources through a marginal effective load carrying capability (ELCC) approach and alterations to the IRM and FPR formulas.  

The committee will be asked to endorse the IRM and FPR results upon first read at this meeting. Same day endorsement may be sought at the Members Committee. (See “Stakeholders Endorse Revised RRS Values,” PJM PC/TEAC Briefs: Feb. 6, 2024.)  

Members Committee

Endorsements (2:40-3:00)

Bruno will present revised installed reserve margin (IRM) and forecast pool requirement (FPR) values for the 2026/27 delivery year. 

The committee will be asked to endorse the new figures upon first read. 

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Michigan Utilities Call for Opt-Out on MISO DER Affected System Studies

CARMEL, Ind. — A band of Michigan utilities wants the option to decline MISO’s affected system-style studies on distributed energy resources, arguing the RTO’s studies create an unnecessary layer of bureaucracy and hinder DER expansion.

Consumers Energy, DTE Energy, ITC Holdings and Wolverine Power approached MISO at the July 17 Planning Advisory Committee, asking for an opt-out provision on the RTO’s affected system studies for DER additions that might impact the transmission system.

Wolverine Power Vice President of Regulatory Affairs Tom King said the Michigan-based parties believe MISO’s DER affected system study process limits efforts to integrate DERs on the grid.

Last year, MISO decided it would evaluate the need for a review of DERs when they can inject 5 MW of power at the substation level during system peak load and if they can force a 1% change in line loading. Transmission owners screen for the 5-MW injection capability, while the RTO ascertains whether the DERs could influence a 1% line-loading change.

If the DER is shown to impact both reliability criteria, MISO issues a report that triggers its existing facilities study and could lead to network upgrades. (See MISO Creating Means to Gauge Impacts of DER Interconnections.)

At a July 17 Planning Advisory Committee meeting, King said MISO’s DER affected system study process and fee requirements “are burdensome, duplicative of the more comprehensive existing TO studies, create unnecessary costs and have the potential to significantly limit DER deployment.” He said TOs already study the potential for DERs to worsen thermal and voltage issues that MISO tests for. He added that TOs’ studies in many cases are superior to MISO’s.

Transmission owners pay a $60,000 study deposit to MISO per substation that is required to be studied for DER impacts. MISO refunds any portion it doesn’t use for the studies.

“MISO obviously has a fee to perform these studies, which has to be coordinated with the TO and then coordinated or not coordinated with the DER,” King told stakeholders.

King said the Michigan utilities developed their opt-out recommendation with help from Michigan Public Service Commission staffers. He asked that MISO treat DERs as load-serving additions or changes, not as generation that causes third-party impacts to the MISO system. That way, King said MISO could view DER additions as end-user facilities seeking to make “qualified changes” under its facility interconnection studies process.

MISO could step aside for transmission owners to perform their more extensive thermal and voltage analyses, King said. He said TOs would continue to “carefully evaluate trickle-up impacts” on the transmission system by DERs and notify MISO of impacts when they submit a transmission upgrade as part of the RTO’s annual Transmission Expansion Plan to mitigate added stress on facilities.

King said he’d like MISO and stakeholders to prepare an opt-out provision as soon as this fall. He said there’s considerable support for DERs in Michigan, with new legislation designed to encourage more of them. He said that trend is likely to occur in other jurisdictions in the footprint.

Last year’s Michigan Clean Energy and Climate Action package contained a provision to raise utilities’ distributed generation program caps from 1% to 10% of their in-state peak load average of the last five years. King said prior to the legislation, utilities were outstripping the 1% limit.

King also noted that the EPA recently awarded Michigan $156 million to reduce the cost of community and rooftop solar projects for low-income households and that Democratic Gov. Gretchen Whitmer’s “MI Healthy Climate Plan” recommended utilities “increase options for customer-driven renewable energy, such as rooftop solar and voluntary green pricing programs.”

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MISO: Hurricane Beryl Caused Electrical Island in Texas

CARMEL, Ind. — MISO said damage wrought by Hurricane Beryl triggered an overnight electrical island in a Southeastern Texas load pocket.

MISO reported an approximately 400 MW energized island existed in the Southeastern Texas (SETEX) load pocket from late on July 8 into the early morning of July 9.

At a July 18 Reliability Subcommittee meeting, MISO South Manager of Reliability Coordination Jeff Sundvick said Beryl’s damage was extensive enough that a single 345 kV line — Rocky Creek to Crocket — connected the SETEX load pocket to the bulk electric system. Sundvick said despite MISO and Entergy’s best efforts to balance the power flow on the line near zero megawatts in case it also went down to keep the island stable, the line tripped late at night, creating an energized island. MISO and Entergy ultimately resynchronized the island about 3:30 a.m. CT on July 9.

“We worked approximately four to five hours with Entergy to keep the island stable,” Sundvick said, adding that Entergy operators at the Montgomery County Power Station maintained frequency by adjusting power in 1 MW increments.

Sundvick said MISO filed an Electric Emergency Incident and Disturbance Report to document the islanding event with the U.S. Department of Energy.

As the Category 1 storm barreled through Texas and weakened, MISO declared a local transmission emergency for SETEX in the early afternoon of July 8. It initiated a restoration protocol that night after Beryl battered transmission and distribution systems. MISO also declared conservative operations from July 8-10 for the South region.

MISO reported the hurricane caused the loss of 73 lines rated 230 kV or 138 kV. It said “out-of-service transmission infrastructure and a general degradation” of the bulk electric system led it to declare the transmission emergency that lasted until the evening of July 11.

Sundvick said the last remaining outage in Entergy Texas’s service area, the 138 kV Oak Ridge to Porter line, was restored July 17.

Unrelated to the hurricane, the grid operator enacted conservative operations again alongside a capacity advisory July 15 for the entire footprint as hot temperatures, forced generation outages and transfer limitations challenged operators.

MISO also announced it experienced real-time price spikes on June 19 due to a shortage of operating reserves. MISO said the shortage occurred over three pricing intervals as 108 GW of afternoon peak load coincided with a ramping down of wind and solar. The operating reserve shortage led to $1,400/MWh energy prices.

Last week, MISO’s Dustin Grethen said MISO expects to encounter shortages more frequently as the system adds renewables and that staff are thinking about the RTO’s “posture” in these events.

“We’re looking at all the factors and evaluating what our options are,” Grethen said.

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Panelists Call for a More Holistic Approach to Advanced Transmission Tech in Mass.

Unlocking the full potential of advanced transmission technologies (ATTs) will be essential to limiting transmission costs associated with the clean energy transition in Massachusetts, a panel of experts said at a forum July 17.

The “pop-up forum” was convened by the Massachusetts Executive Office of Federal and Regional Energy Affairs and coincided with the state legislature’s scramble to pass a climate bill before the end of the legislative session. If passed, the bill appears likely to include language requiring transmission and distribution owners to consider ATTs when proposing new infrastructure.

“You’re taking up the topic at a critical time,” said Sen. Mike Barrett (D), co-chair of the Joint Committee on Telecommunications, Utilities and Energy.

“Where do ATTs figure in?” Barrett asked the speakers in his opening remarks. “We really need to know if we’re talking about something with a major set of implications for New England, or a more marginal set.”

The terms ATTs and grid-enhancing technologies (GETs) refer to a range of technologies aimed at maximizing the capability of existing transmission infrastructure. These technologies can be used to address transmission constraints without requiring major new infrastructure.

“There’s potentially billions of dollars of value here,” said Lakshmi Alagappan of Energy and Environmental Economics (E3). Alagappan focused on five technologies that “exhibit strong potential” in the region: advanced conductors, dynamic line ratings, power flow controllers, storage-as-transmission-only assets and topology optimization.

While FERC Order 1920 requires transmission operators to consider GETs in long-term planning, “there is a much broader opportunity to look more holistically” at the role that ATTs can play, Alagappan said.

Alagappan emphasized the importance of creating standards for software compatibility, amending rules to allow new technologies to participate in transmission solicitations and ensuring that studies account for the full scope of potential ATT benefits.

“Proactively taking these steps now will be critical,” Alagappan said.

Representatives of Eversource Energy and National Grid, which own significant transmission assets in New England and electric distribution utilities in Massachusetts, said some of the technologies are already deployed in the region, but that more can be done to scale up their use.

“We’re not starting from zero, but we’re not at full capacity yet,” said Vandan Divatia of Eversource, adding that the company frequently considers adding advanced conductors when replacing structures for asset condition needs.

Andrew Schneller of National Grid said the consideration of advanced conductors has become “somewhat of a standard,” and noted that the company deployed DLR to achieve a 20 to 30% increase in the capacity of a line in Rhode Island.

Both Schneller and Divatia said tariff requirements for transmission owners to select the lowest-cost solution to isolated issues could be a barrier to deployment. ATT solutions may have a wider range of long-term benefits but still come in as the more expensive solution to the specific issue at hand, Schneller said.

Jacquelyn Bihrle of the Massachusetts Attorney General’s Office said it is “encouraging from our perspective that these technologies are being deployed where possible,” but she said that considering all possible ATT solutions to transmission needs should be “a routine, standardized part of the process.” While Order 1920 “sets a floor” by requiring the consideration of ATTs, “it must be more than a check-the-box exercise.”

Bihrle called for increased accountability and transparency regarding how TOs evaluate ATT solutions. She highlighted the idea of an independent transmission monitor as “one way to achieve that level of scrutiny” and help address the “information asymmetry” between TOs and consumers.

Al McBride of ISO-NE said there may be a role for the RTO to help “explain to people what the likely use cases are for the different technologies.”

He emphasized that ISO-NE solicitations are centered around selecting the lowest-cost solution, regardless of whether a solution is based on new technology or traditional infrastructure.

Separate climate bills recently passed by the Massachusetts House of Representatives and Senate include identical language requiring “due consideration” of ATTs for new transmission and distribution infrastructure.

Following the passage of the House bill on July 17, the bills now go to a conference committee, where legislators will try to quickly formulate a compromise bill to pass and send to Gov. Maura Healey (D) before the end of the legislative session July 31.

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Blade Failure Brings Vineyard Wind 1 to Halt

Construction of Vineyard Wind 1 has paused and operation of completed wind turbines halted as cleanup and investigation of a blade failure continues.

The incident began the evening of July 13, as pieces of one of three blades on turbine AW38 began raining down into the Atlantic Ocean, and culminated in the large remaining chunk of the blade falling July 18.

As a result, a safety perimeter was established at the site and beaches on Nantucket to the northeast were closed.

The facility recently won bragging rights as the largest offshore wind farm operating in U.S. waters, even in its partially completed state. The high-profile failure and widely shared images of it have given fresh fodder to industry opponents proclaiming the danger of the emissions-free power sector that’s establishing a foothold in the United States.

The U.S. Department of the Interior’s Bureau of Safety and Environmental Enforcement (BSEE) said July 17 it issued a suspension order to Vineyard Wind LLC to cease power production until it can be determined if the issues that caused the blade to fail affect any other turbines at the site.

The suspension order halts installation of new wind turbine generators as well. And BSEE also issued a preservation order to safeguard material that might help determine the cause of the incident.

The developer said it had already decided to halt construction and operation when the BSEE orders came down.

Vineyard Wind LLC is a 50-50 joint venture of Avangrid Renewables LLC and Copenhagen Infrastructure Partners. Sixty-two GE Vernova Haliade-X turbines rated at 13 GW will give the project a nameplate capacity of approximately 800 MW and help Massachusetts get closer to its decarbonization goals.

Investigation and damage control continued at the site July 18, with interference from Mother Nature. A band of heavy rain passed south of Nantucket at midday and the National Weather Service issued a small craft advisory due to 4- to 6-foot seas.

Vineyard Wind LLC updated the situation later on its website:

“This morning, a significant part of the remaining GE Vernova blade detached from the turbine. Maritime crews were onsite overnight preparing to respond to this development, though current weather conditions create a difficult working environment. Despite these challenging weather conditions, a fleet of vessels remains at sea managing the situation and working to remove bulk debris. We have deployed additional crews to Nantucket Island in anticipation that more debris could wash ashore tonight and tomorrow as we continue to monitor additional coastal communities.”

The blade was 107 meters long and weighed 70 metric tons.

Vineyard Wind LLC said July 17 the integrity of the blade was compromised, and the chances of it detaching had increased.

Local officials said the remainder fell into the water at 6:40 a.m. July 18 and that a very large piece was submerged.

The developer in its statements has emphasized the role of GE Vernova, which built the turbine and whose subsidiary LM Wind Power fabricated the blade. It said it was staying apprised of GE Vernova’s effort to remove and recover what was left of the blade.

GE Vernova said in a prepared statement:

“GE Vernova’s top priority is safety and minimizing the impact of this event on the communities surrounding the Vineyard Wind farm in Massachusetts. We continue to work around the clock to enhance mitigation efforts in collaboration with Vineyard Wind and all relevant state, local and federal authorities. We are working with urgency to complete our root cause analysis of this event.”

Another incident with GE Vernova offshore wind equipment occurred May 1 off the English coast at the Dogger Bank Wind Farm, the world’s largest offshore wind facility.

Developer SSE Renewables said May 9 that initial findings indicated the circumstances of the incident were isolated to the one blade that was damaged.

A source with knowledge of the situation said July 18 that a detailed investigation by GE Vernova’s Wind Fleet Performance Management team revealed an issue related to the installation of the blade, that it was immediately corrected, and that it did not recur during installation of the other blades.

The Vineyard Wind incident has garnered steady media coverage, and GE Vernova has taken a hit in the financial markets, with its stock price dropping a combined 11.6% July 17 and 18.

The crippled turbine at Vineyard Wind 1 is part of the first wave of what advocates hope will be thousands of wind turbines spinning off the Northeast coast. Opponents meanwhile have tried and failed and are still trying to block Vineyard and other projects in the courts of law and public opinion.

In a June 25 update, the partners said Vineyard had 10 turbines operational, giving it a nameplate capacity of 136 MW. This edges out its neighbor, South Fork Wind, the only other utility-scale wind farm operating in U.S. waters, which is rated at 132 MW.

They said 47 foundations and transition pieces and 21 turbines had been installed at the Vineyard site.

As of July 17, Vineyard Wind LLC said it had collected several large pieces of debris and 17 cubic yards of smaller debris from Nantucket’s south shoreline. Beaches subsequently were reopened.

The town and county of Nantucket has established a “Vineyard Wind Turbine Blade Crisis Update” page on its website in response. More than 60 people attended the Select Board meeting in person the evening of July 17 and more than 1,600 watched online.

Vineyard Wind CEO Klaus Moeller told the audience that a blade folded the evening of July 13, triggering an alarm and an automatic shutdown of the turbine. The established emergency response protocol then began.

Moeller said the large pieces of debris had been removed to New Bedford for storage. The smaller pieces were being recovered, he said, adding that they are not toxic.

The audience erupted into a bout of exaggerated coughing at this point, until Select Board Chair Brooke Mohr hushed them.

She acknowledged the tension in the room but admonished the audience to hold their questions and criticism.

Roger Martella, GE Vernova’s chief sustainability officer, told the meeting that the company has established a war room in Schenectady, N.Y., as it investigates the incident, and he promised updates.

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Longtime MISO President and COO Moeller to Retire

MISO has announced that its longtime second in command will retire at the end of the year. 

President and COO Clair Moeller will leave the grid operator effective Dec. 31, MISO revealed in a July 18 press release. Moeller joined MISO in 2004, a year before the grid operator opened its energy markets. Prior to that, he was with Xcel Energy for 25 years. 

MISO said Moeller’s transition will begin immediately and he will serve as a strategic adviser for the remainder of the year. 

On Jan. 1, 2025, CEO John Bear will again assume the role of president. MISO confirmed to RTO Insider that it has no plans at this time to open a search for a chief operating officer and will function without one for the foreseeable future. 

The MISO Board of Directors in 2017 promoted Moeller from executive vice president of operations to president and COO. As part of his role, Moeller was prepared to step in and act as CEO if necessary. (See MISO Board Promotes Moeller, OKs 2018 Budget.) It’s unclear where MISO’s executive succession plan stands following Moeller’s retirement; the grid operator had not responded to RTO Insider’s question about that by press time. 

“It is because of our dedicated and hardworking employees and the support of our stakeholders that we have been able to provide reliable power across 15 states and to 45 million Americans,” Moeller said in a press release. “As I reflect on the last 20-plus years, I am so proud of what MISO has accomplished, and I extend my deepest thanks to John, the board and everyone at MISO for the opportunity of a lifetime.” 

“Clair’s contributions to MISO and the greater electricity sector are distinguished and truly remarkable,” Bear said. “Having worked with Clair for more than 20 years, I can say with conviction he has been instrumental in building our organization. His passion, knowledge and unwavering commitment to MISO and our members have helped define the electricity system across our footprint. On behalf of all of us at MISO and our membership, we thank Clair for his invaluable contributions.” 

Moeller led MISO’s grid operations, forward markets, system planning, external affairs and information technology divisions. Going forward, Senior Vice President of Planning and Operations Jennifer Curran and Chief Customer Officer Todd Hillman will report directly to Bear. 

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Audit Faults NY on Climate Act Progress

A new audit by the state fiscal watchdog faults New York’s slow progress toward its climate protection goals and warns that the full cost of the effort still has not been quantified, five years after the goals were signed into law.

State Comptroller Thomas DiNapoli said July 17 the audit by his staff found New York was moving in the right direction but better planning, monitoring and risk assessment are needed.

The audit finds fault with the state Public Service Commission (PSC), which with its staff in the Department of Public Service (DPS) draws up regulations for pursuing the climate goals. To a lesser extent, it finds fault with the New York State Energy Research and Development Authority (NYSERDA), which awards the development contracts that will help achieve the climate goals.

In their rebuttals, the PSC and NYSERDA stand by their efforts. The PSC said the audit discounts much of the work done and overlooks some of the factors that have limited progress. NYSERDA thanked the Office of State Comptroller (OSC) for its detailed analysis and said it has taken steps to address some of the feedback, but it pushed back on other criticisms.

The audit began in early 2022 and encompasses a period when the state’s pipeline of contracted clean energy projects swelled impressively amid strong policy support then collapsed amid strong industrywide headwinds.

The Department of Public Service and NYSERDA predicted in a draft review issued July 1 that the state will fall short, perhaps far short of its first major target: 70% renewable energy by 2030. (See NY Expects to Miss 2030 Renewable Energy Target.)

In announcing the audit, DiNapoli said: “New York has been a leader in its efforts to reduce greenhouse gas emissions and the threats caused by climate change, and identifying existing and emerging challenges will improve the likelihood that we succeed.”

CLCPA Turns 5

Then-Gov. Andrew Cuomo (D) signed the state’s landmark Climate Leadership and Community Protection Act (CLCPA) into law on July 18, 2019, surrounded by supporters of the measure.

Many blue states tout their climate protection and decarbonization efforts, and some even claim to be nation leading. New York’s effort legitimately could be called one of the strongest in the nation at the time — former Vice President Al Gore, who shared the 2007 Nobel Peace Prize for his efforts to protect the planet, joined Cuomo for the signing ceremony.

But New York also would sit near the top of any list of states where renewable energy projects are slow and expensive to complete.

It took more than three years just to produce a scoping plan for the CLCPA. Meanwhile, the clock was ticking on the CLCPA’s legal mandates of 70% renewable energy by 2030, 100% emissions-free power by 2040 and greenhouse gas emissions at least 85% lower than 1990 levels by 2050.

While New York was planning, drafting and reviewing, the world moved ahead. A global pandemic and a European war drove up costs, rendering untenable dozens of contracts for 11 GW of renewable energy projects.

For the past nine months, New York has been scrambling to regain its lost momentum. It has had partial successes, at a cost in time and money.

Findings, Recommendations

The audit highlights several findings:

    • PSC is using outdated data and at times incorrect calculations for planning purposes.
    • PSC has not started to address all existing and emerging issues that could increase demand for electricity and lower supply.
    • PSC has taken steps to address some risks and issues but has not begun to formally review progress toward CLCPA goals, raising the risk that the CLCPA’s goals will be missed.

New York has not quantified the cost of transitioning to renewable energy, nor provided a reasonable estimate, nor specified a source of funding. This leaves the cost to utility ratepayers who already have faced sharp rate increases over the past two decades and in many cases already are having trouble paying their bills.

The audit highlights several recommendations:

    • Begin the required comprehensive review of the CLCPA, including assessment of progress toward the goals, distribution of systems by load and size and annual funding commitments and expenditures.
    • Continuously analyze risks to minimize impact on ability to meet CLCPA goals.
    • Analyze the expected cost of the clean energy transition and of meeting CLCPA goals, then update that analysis periodically and report the results to the public.
    • Determine how much of this cost ratepayers reasonably can be expected to cover and look for alternative sources of funding.

PSC Response

As is customary, the OSC audit included the response of the audited agencies. The comments by PSC Chair Rory Christian and the counter comments by the auditors added 25 pages to the 29-page audit.

PSC also sent a prepared statement to NetZero Insider:

“DPS is pleased to note that OSC found that the PSC and NYSERDA have taken considerable steps to transition to renewable energy in compliance with the Climate Leadership and Community Protection Act (CLCPA) and Clean Energy Standard (CES), but is disappointed that OSC overlooks several significant steps taken and factors that have impacted progress to date.

“Indeed, in the five years since the CLCPA was enacted, the PSC modified the existing CES to comply with the law, directed NYSERDA to continue undertaking solicitations for new renewable projects in the face of unprecedented and evolving market conditions outside of New York’s control, approved $5 billion in transmission investments to support renewable projects, worked with federal, State and local governments on renewable energy initiatives that have reduced the ratepayer costs of complying with CLCPA (potentially saving ratepayers billions of dollars), partnered with the Legislature to streamline the siting laws for renewables and transmission projects, advanced critical planning proceedings to ensure the energy transition is done in a safe and reliable manner, and expanded utility affordability initiatives.

“Much of this work appears to have been discounted in the OSC report, and the Department’s response highlights several instances where it disagrees with OSC’s findings.”

NYSERDA Response

The audit’s criticism of NYSERDA was narrower, focusing on some of the methodology it used for evaluating bids and awarding contracts. NYSERDA President Doreen Harris’ response to the audit was proportionately narrow, at just four pages.

In an interview, she said:

“The comptroller found us to be in full compliance with the Public Service Commission orders. And ultimately, the recommendations within the audit are almost exclusively already being incorporated within our record keeping and the implementation of our solicitations.”

Harris said goals such as 70% renewables by 2030 are more than aspirational or inspirational; they establish a market size to attract the considerable private sector investment and consumer support that is needed for CLCPA to succeed.

The idea is that a maturation of technologies and markets needs to happen for CLCPA’s goals to be achieved, and the existence of those goals helps these markets and technologies mature.

Harris sees this happening already in registrations for battery electric vehicles, heat pump sales and the installed capacity of community solar in New York.

“Change happens in ways that reach inflection points, inflection points where the market reaches a level of maturity and uptake that it essentially takes off,” she said. “When I look at the data, not even in the super long term but literally over the last couple of years, [it shows] we have reached those inflection points [with] many technologies that are necessary to not only make progress toward these goals, but also be well on our way toward achieving them.”

Despite all the cost escalations and contract cancellations seen in the past year, progress is being made in New York, even if there is less than had been anticipated.

Harris spoke to NetZero Insider on July 17 after helping lead a ceremonial groundbreaking for Sunrise Wind, an offshore wind project that will be among the largest capacity additions to the state’s grid in decades — 924 MW — if it is completed as planned. Its initial contract was among the dozens canceled statewide in 2023 and 2024, but it was brought back into the portfolio in June. (See Empire, Sunrise Wind Back Under Contract in NY.)

More Money

But what of the cost concerns the audit raises?

In July 2023, the PSC commissioners heard the first annual report from DPS staff on efforts to implement the CLCPA. A conservative estimate was offered of money already spent or authorized to meet CLCPA goals: $43.76 billion.

But there was no estimate of how much more would be needed, which took some commissioners aback. (See Energy Transition Costs Give NY Utility Commissioners Pause.)

A year later, Harris did not offer any cost estimate. She pointed instead to the Scoping Plan, an extensively detailed publication stretching 445 pages where cost estimates are buried within calculations — the benefits to society of decarbonizing will be $400 billion to $415 billion greater than the cost, for example.

These figures were derived before the massive cost increases of 2023. And they include assumptions such as $1.9 billion in savings over a 30-year period from decreased frequency of trip-and-fall accidents in low- and moderate-income households.

The auditors are not the first observers frustrated in their quest for a clearly stated price tag.

The unknown costs of implementing the CLCPA became a frequent talking point for John Howard in his recently concluded five-year tenure on the PSC, which neatly overlapped the first five years of the CLCPA’s existence.

“My own personal back-of-the-envelope thinking is about a half a trillion,” he told NetZero Insider, but that is only an estimate, one he had to produce because no one had a hard number for him.

The audit was correct in flagging the risks of not stating the full cost, Howard said.

“Oh, yeah — I mean, they are self-evident. On the issue of cost transparency, look, you’re a reporter. We have several good reporters trying to get these numbers. They just don’t want to be released. They can be known. They can be estimates. But the sticker shock will scare people away, so it doesn’t happen.”

He continued: “The hard numbers are an illusion because you can’t find them. If the Office of State Comptroller can’t find the numbers, well, then who’s gonna find the numbers?”

Howard said the integration analysis used to calculate the negative net cost of implementing the CLCPA is the wrong pitch for New Yorkers.

The costs are being revealed piecemeal, but they are broad and immediate: Utility bills going up 2% for a particular wind farm or 3% for a particular transmission project, for example. The benefits, meanwhile, will be realized unevenly over decades through hard-to-quantify metrics such as reduced asthma symptoms or fewer cases of carbon monoxide poisoning.

“It’s easy to say ‘yeah, we can afford it’ when you don’t tell anybody what it’s gonna cost ya,” said Howard, adding that he does believe climate change is real and needs to be addressed.

“Do it as transparently as possible, because if you’re asking New Yorkers to pay this giant new vig, you need to get them to say yes. By not telling them, it’s the worst thing you could do.”