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November 14, 2024

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NYISO’s 10-Year Forecast: Challenges Ahead, but No Immediate Needs

NYISO released its 2023/32 Comprehensive Reliability Plan (CRP) on Nov. 29, finding no “actionable reliability needs” for the next decade, but warning of narrowing reliability margins. 

The biennial-CRP serves as the ISO’s 10-year strategy map for New York’s electric system, outlining emerging risks and recommending actions the state can take to ensure grid reliability. It encompasses demand forecasts, resource adequacy, infrastructure development and renewable energy integration. The CRP is the culmination of NYISO’s reliability planning process and assesses the feasibility of solutions proposed in the annual Reliability Needs Assessment (RNA). 

The draft CRP, which received NYISO stakeholder approval earlier this month, was presented throughout the year. (See “Comprehensive Reliability Plan,” NYISO Operating Committee Briefs: Oct. 11, 2023.) 

The CRP concludes that the system should be reliable, assuming demand and weather conditions align with NYISO’s forecasts. However, delays in key projects like the Champlain Hudson Power Express (CHPE), increased electric demand, additional generator deactivations due to state regulations, unplanned outages or extreme weather events could necessitate new reliability measures in next year’s RNA. 

The critical risk outlined in the CRP is the on-time completion of the 1,250-MW HVDC CHPE project, which will bring hydropower from Québec to New York City. If delayed beyond its expected May 2026 completion, reliability margins could become “deficient for the ten-year planning horizon,” leaving New York City unable to meet demand from 2026 onwards. 

Without CHPE, statewide summer reliability margins become deficit by 2025. | NYISO

The plan also anticipates a notable increase in peak demand driven by the electrification of transportation and buildings, along with the addition of large loads, especially in upstate New York.  

This growing demand becomes even more pressing since about 3,300 MW of fossil fuel plants, which tend to meet demand during extreme conditions, are expected to retire due to the Department of Environmental Conservation’s peaker rule starting in May 2025. This is a particular concern for New York City, which heavily relies on natural gas. 

NYISO recently announced plans to extend the operation of two natural gas peaker plants beyond their 2025 retirements to address a 446-MW shortfall in New York City identified in the second quarter Short-Term Assessment of Reliability. (See NYISO to Keep Gas Peakers On.) 

The CRP cites the 2023 Fuel and Energy Security study, which predicts that New York will transition from a summer to a winter peaking system as electrification increases and become increasingly reliant on dual-fuel generation resources in winter. This poses a future challenge, especially as many fossil fuels plants expected to retire soon would have been key to meeting peak winter demand. 

The CRP recommends introducing new dispatchable emissions-free resources (DEFRs) and inverter-based resources (IBRs), constructing additional transmission, integrating more distributed energy resources (DERs), and expanding demand response and energy efficiency programs. 

In an Oct. 23 memo commenting on the draft CRP, Potomac Economics, the ISO’s Market Monitoring Unit, recommended market design changes to encourage the development of flexible resources and the integration of intermittent renewables to maintain reliability. (See Providers See ‘Mixed Signals’ on Demand Response in NYISO.) 

Summer extreme weather events represent a risk to statewide system marginal deficiency. | NYISO

Risk Factors

While identifying no immediate reliability needs requiring action, the CRP says that generation retirements could outpace resource additions, which it says could result in a transmission security deficit exceeding 600 MW in New York City by 2033. It says the state’s 2019 Climate Leadership and Community Protection Act, along with other public policy initiatives, significantly accelerated generator retirements. 

Even with projects like CHPE, meeting peak demands during extreme winter conditions could become a challenge as early as the winter of 2027/28 due to increased building electrification, electric vehicle growth and the addition of large energy loads like data centers and microchip fabrication plants. 

The CRP warns of potential power deficits in future winters, with a projected shortfall of 6,000 MW by winter 2032/33, which could be compounded by gas shortages and extreme cold snaps. 

Extreme weather events such as heat waves and storms also represent significant risks, potentially leading to increased electrical demand and more frequent generator outages. An extreme heat wave could cause a statewide deficiency of over 2,500 MW by 2025. 

The plan encourages continued interregional collaboration, predicting NYISO will likely have to increasingly rely on its neighbors to meet demand during above-average loads. 

Road to 2040

New in this year’s report is a section titled “Beyond the CRP — Road to 2040,” which assesses the impacts of public policies on New York’s electric grid and fuel mix, outlining steps needed to meet the state’s climate targets amidst reliability, generation and transmission risks. 

NYISO estimates New York will require between 111 GW and 124 GW of capacity by 2040, with at least 95 GW coming from new generation projects or modifications to existing plants. However, the CRP says this may not even be enough, warning “the sheer scale of resources needed to satisfy system reliability and policy requirements within the next 20 years is unprecedented.” 

The section notes a significant portion of this new generation will be IBRs, which are subject to meteorological conditions and also willl need to be supplemented with other resources like energy storage and DERs. 

The section emphasizes the need for DEFRs to provide energy and capacity over long durations, especially during low output from intermittent resources, and to replace the attributes of retiring synchronous generation. Resources with the attributes needed for DEFRs are not yet commercially available, prompting the New York Public Service Commission to explore potential technologies such as hydrogen, bioenergy, nuclear power and carbon capture (15-E-0302). 

And although NYISO has identified several major public policy transmission projects to deliver renewable energy efficiently across the state, further development is needed to serve renewable generation pockets. 

The Road to 2040 also discusses the need for a more resilient power system against climate change impacts and extreme weather, appropriate market price signals and ensuring new resources can provide essential grid services like operating reserves, ramping or voltage support. 

The section acknowledges the need for New York to adapt its planning strategies to guarantee future reliability and maintain energy markets flexible enough to respond to evolving grid and environmental conditions. 

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Region Still Split as BPA Approaches Day-ahead Market Decision

The Bonneville Power Administration is pulling back from its ambitious schedule for choosing which Western day-ahead market it will join, officials with the federal power marketing administration said during a workshop Nov. 29.

But those officials also indicated BPA still plans to issue a decision on whether it will sign up with either CAISO’s Extended Day-Ahead Market (EDAM) or SPP’s Markets+ sometime early next year.

When BPA launched its process for deciding between the markets in July, staff said it would propose a “policy direction” in the form of a “record of decision” on the issue shortly after SPP filed its Markets+ tariff with FERC in February, following a series of five stakeholder workshops.

The decision would cover two points: whether BPA would participate in a day-ahead market, and which of the two it would join, staff said. (See Regulators Propose New Independent Western RTO.)

Some industry stakeholders criticized the timeline for being overly aggressive and expressed concerns that the timing of the decision suggested an implicit bias in favor of Markets+. Others said the pacing was necessary to ensure that BPA — and the Northwest at large — had a strong influence on the direction of electricity market developments in the West. (See NW Stakeholders Divided on BPA Timeline for Day-ahead Decision.)

The critics may have partly gotten their wish during BPA’s fourth workshop on the issue, when agency officials revealed that while they’ll be sticking to the original timeline for issuing a decision in the first quarter of 2024, they intend to alter the content of that decision.

That record of decision is now likely to cover whether BPA has the statutory authority to join a day-ahead market, while potentially conveying a “leaning” on what market the agency is favoring by that time, Russ Mantifel, the agency’s director of market initiatives, said during the workshop.

Mantifel acknowledged the level of uncertainty around the issue and said BPA still has “limited information” on which to base a decision.

“I would say that the timing of this is still up in the air, right? Like, there’s literally no market that somebody could join. Right now, EDAM has not been approved. There’s no tariff yet for Markets+,” he said, pointing out that SPP is still surveying potential participants on “even what it would look like to start making the commitment” to that market.

Mantifel pointed to other, internal matters that BPA must deal with before making a decision on whether to join a market, including the impact on its rates, tariffs and contracts with power and transmission customers.

“I think it’s fair to expect that that policy direction will establish our authority to join a market and will establish the business case for pursuing a market,” Mantifel said.

“Our customers and regional leaders have expressed to us the importance that our market engagement needs to be consistent with our statutory obligations. We’re right there with you,” said Suzanne Cooper, BPA senior vice president of power services.

Cooper pointed to another factor that might be prompting BPA to ease up its timeline: stakeholder requests that the agency more deeply evaluate the “cost advantages” of a single Western market.

In that vein, she said, the agency continues to monitor developments around the West-Wide Governance Pathways Initiative (WWGPI), which seeks to establish an independent entity to oversee an RTO that would include CAISO and build on the grid operator’s existing market services without subjecting non-California members to the ISO’s state-run governance. BPA has not been participating in that effort. (See West-Wide Governance Pathway Group Digs into its Work.)

“We have heard and definitely acknowledge the requests that we’ve heard for taking some more time for additional analysis and to allow the Pathways concept to develop,” Cooper said. “We’ve heard also from many entities, including within our public power customers, that desire for BPA to maintain our current timeline.”

To Lean or Not to Lean

A representative from a key group representing many of those public power customers asked BPA for more clarity on the process that will follow the first record of decision.

Lauren Tenney Denison, director of market policy and grid strategy at the Public Power Council (PPC), noted that in the “multiphase” process that BPA followed in its decision to join CAISO’s Western Energy Imbalance Market, “it was pretty clear what was being decided and what was still open for discussion.”

“What is the expected action that will happen after the leaning is issued at the end of this process?” Denison asked.

“I think that is still up in the air,” Mantifel said. “The processes for joining the markets themselves are still somewhat fluid as opposed to EIM.”

Fred Heutte, senior policy associate at the Northwest Energy Coalition, advised BPA not to include a “leaning” in the first record of decision. NWEC has been a consistent advocate for a single Western market that includes California.

Reading from comments that NWEC submitted to BPA a day earlier, Heutte said, “The BPA day-ahead market policy should provide principles and a road map for assessment, analysis and modeling to inform BPA’s decision about joining a day-ahead market. Given the wide range of implications for market selection, we strongly urge BPA not to proceed with a leaning on day-ahead market choice at this time.

“We feel that any leaning, whichever direction this goes, not be included with day-ahead market policy, because it really belongs with the decision process.”

Mike Linn, director of market analytics at the PPC, took the opposite view.

“We think that because of the nature of Bonneville’s system, Bonneville’s decision or leaning would be very informative to other Western prospective participants, and [I] just want to kind of re-emphasize that we do think that is a key element and something to include.”

Mantifel defended BPA’s inclusion of the leaning.

“I worry that just making a statement generally about a day-ahead market without recognizing the reality of the fact that there are two options that people are making decisions on … might not reflect the practical reality that entities are facing at this point in time in terms of needing to be in a position to make commitments,” he said.

The Nov. 29 meeting left lingering question about exactly what BPA will provide to stakeholders in the first quarter of 2024.

“BPA is on track to issue a proposed policy decision with respect to participation in day-ahead markets early next year,” agency spokesperson Doug Johnson told RTO Insider. “BPA indicated that it would continue to address stakeholder comments in its public process to evaluate day-ahead market participation.” 

Johnson said BPA has “committed to provide a timeline of what decisions would be made and when because some decisions would take place in different processes, such as our rates and tariff proceedings.” 

BPA tentatively plans to hold its final day-ahead workshop Feb. 1, but the date is subject to change.

(Editor’s Note: This article was originally titled “BPA Delays Decision onDay-ahead Market Choice.” BPA requested the title be changed to reflect the fact that the agency still intends to issue a proposed policy direction related to day-ahead markets in early 2024.)

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BLM to Consider Changes to Western Transmission Corridors

The Bureau of Land Management is seeking public input on potential changes to several of its designated West-wide energy corridors, sites that are preferred locations for transmission and other energy transport projects on federal lands. 

The changes now being considered include additions, deletions or revisions to about 673 miles of seven designated corridors, BLM said in an announcement Nov. 30. The changes would involve amendments to 19 resource management plans in seven states: Arizona, California, Colorado, Nevada, New Mexico, Utah and Wyoming. 

The bureau said the changes are intended to “support transmission siting to speed clean energy production across the West.” Other goals of the project are improving reliability, relieving congestion and strengthening energy security. 

“Transmission is a vital piece of moving our country to a clean energy economy,” BLM Director Tracy Stone-Manning said in a statement. “These updates will help plot a course for successful transmission deployment in order to bring renewable energy to markets across the West.” 

The work will be funded with $1.2 million from the Inflation Reduction Act. 

BLM has scheduled four in-person and two virtual public meetings in January to hear comments on the proposals. 

The West-wide energy corridors are also known as Section 368 corridors, a reference to the section of the Energy Policy Act of 2005 that directed federal agencies to designate the corridors. 

The idea behind the corridors is to facilitate transmission development while minimizing impacts to natural, cultural and historic resources across the West. In addition to electric transmission lines, the corridors may be preferred sites for oil, gas and hydrogen pipelines. 

The corridors were first designated in 2009, covering about 6,000 miles across federal land in 11 Western states. But the Wilderness Society and other environmental organizations challenged the corridors’ approval in court. As part of a 2012 settlement agreement, BLM agreed to work with other agencies to reexamine the corridor designations. 

The settlement agreement included “siting principles” for agencies to consider when evaluating corridors. One principle is to look at whether the corridors facilitate connections to renewable energy resources as much as possible while also considering other sources of energy generation. 

Other principles were siting of corridors to provide “maximum utility and minimum impact to the environment,” promoting efficient use of the landscape and identifying appropriate uses for specific corridors. 

As part of its corridor reexamination, BLM conducted a series of regional reviews to look at new information and hear from stakeholders. The regional reviews were compiled into a final report released in April 2022. 

The final report includes recommendations for corridor additions, deletions and revisions. Several of the proposed additions would co-locate a corridor with existing transmission lines.  

For example, a new corridor aligned with the planned Santa Fe transmission line in New Mexico could potentially facilitate the transmission of renewable energy from northeastern New Mexico to the Four Corners energy hub. 

Another recommended corridor addition, along an existing 230-kV transmission line and the proposed Cross-Tie line, would provide a continuous east-west corridor through Nevada and Utah.  

This would facilitate the transmission of high-capacity renewable resources from Wyoming and Utah to southern Nevada and California and give Utah and Wyoming customers access to excess solar energy from CAISO, according to the report. 

But topography and the presence of the Utah Test and Training Range could make the changes challenging, the report acknowledged. 

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NERC Troubled by Responses to IBR Alert

Many generator owners (GOs) are not following NERC‘s recommendations for improving the performance of inverter-based resources (IBRs), and new reliability standard projects and other regulatory actions may be needed to enhance these generators’ reliability, according to the findings of a Level 2 alert the ERO released Nov. 30. 

NERC issued the alert in March, providing a series of recommendations that GOs were “strongly encouraged to adopt.” (See NERC Issues Level 2 Alert on IBR Issues.) Recipients were required to respond to a series of questions about their grid-connected solar facilities (if any). While the topic of the alert was solar subject to NERC standards, the ERO said in Thursday’s report the recommendations may be applicable to other IBRs including wind and battery energy storage systems. 

Entities initially were required to submit their responses to the alert by June 30, but NERC said it had received only 15 submissions by the due date, which the ERO called an “unprecedented and unexpected low response rate.” As a result, the deadline was extended to July 31. By the end of the extension, NERC received 1,149 responses, for a response rate of about 97%.  

A total of 217 entities reported owning one or more grid-connected solar facilities. The greatest number of positive responses, 85, came from entities in WECC. SERC Reliability followed with 59, and the Texas Reliability Entity came next with 45. Also, 18 entities in ReliabilityFirst reported having applicable resources, followed by eight in the Midwest Reliability Organization and just two in the Northeast Power Coordinating Council.  

Difficulties Obtaining Needed Data

All but three utilities with grid-connected solar resources submitted responses to the alert’s questions by the extended deadline, despite “anecdotal comments [that] indicated that the data was difficult to obtain,” NERC said. GOs reported needing “significant assistance from OEMs [original equipment manufacturers] or consultants,” but OEMs and consultants themselves said they also had problems getting needed information from GOs and each other. 

The quality of data submitted was questionable even though most worksheets were technically complete, the report said, with analysis of the responses showing “significant and numerous instances of misunderstanding … the information requested.” In one case, a GO said its inverter manufacturers had not “experienced instances of inadvertent tripping at other facilities” even though its equipment had been “documented to be involved in past major disturbances.” 

NERC said it developed the worksheet questions based on input from industry groups and experience from multiple IBR events analyzed by the ERO Enterprise, under the assumption that GOs “would have the requested information available to submit with relative ease.” That such issues exist within the submissions casts “doubt on the accuracy and quality of the submitted modeling data used in reliability studies,” which also would come from GOs, the ERO added.  

NERC’s analysis of the data indicated widespread deviations from the ERO’s guidance. For example, about 2,260 grid-connected solar facilities have voltage and frequency protection settings within the “no-trip zone” defined by NERC’s reliability standard PRC-024-3 (Frequency and voltage protection settings for generating resources). While the standard allows for protection settings to border and enter the no-trip zone in some circumstances, NERC said the facilities in question are “at an elevated risk of tripping during [grid] disturbances.” 

The ERO also found that less than a third of solar facilities’ protection settings were based on the maximum capability of the equipment, indicating that “there is significant underused ride-through capability across the” electric grid and raising concerns about the availability of reliability services as traditional generation sources are retired. Additionally, about 27% of the solar fleet by MW is not configured with NERC’s recommended ride-through settings, though the report acknowledged that many of these facilities may be older and not capable of being modified. 

New Standard Actions Recommended

NERC concluded many GOs and generator operators are providing “only the minimum [performance] as explicitly stated in FERC orders, regional requirements, and NERC reliability standards,” which can put the grid at risk of losing significant amounts of resources and essential reliability services. 

One reason for the shortcomings identified by the ERO is the lack of uniform performance requirements for solar facilities. NERC said its Inverter-Based Resource Performance Subcommittee (IRPS) is developing a standard authorization request (SAR) to update FAC-001-4 (Facility interconnection requirements) and standardize performance requirements across North America. Two other standard projects — Project 2020-02 (Modifications to PRC-024) and Project 2023-02 (Performance of IBRs) — are expected to help with the performance deficiencies as well. 

NERC also faulted “systemic deficiencies in the availability and understanding of facility information,” and recommended the IRPS draft a new SAR to introduce commissioning requirements for GOs of IBR facilities. The ERO further said its concerns about the quality of modeling data should be addressed as soon as possible. 

NERC said it will issue another Level 2 alert next year to gather modeling and study information from GOs and transmission providers, and to “share recommended practices regarding modeling and study enhancements.” A Level 3 alert will follow “in the first half of 2024” with essential actions for GOs to address high-risk IBR issues. 

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FERC Upholds Ruling on ISO-NE’s IEP Payments

FERC has upheld its ruling on a series of updates to ISO-NE’s Inventoried Energy Program (IEP) which could result in larger payments for generators to keep stored fuel on-site as a grid reliability backstop (ER23-1588).

The commission initially approved ISO-NE’s changes in early August, despite protests from consumer advocates and environmental organizations. (See FERC Approves Updates to ISO-NE Inventoried Energy Program.)

The changes shift the IEP from fixed payment rate format to indexed rates and are intended to “align the program with current market conditions,” according to ISO-NE. The IEP compensates generators for storing up to three days’ worth of stored fuel and covers the winters of 2023-24 and 2024-25.

Climate organizations argue the changes amount to an unnecessary subsidy for fossil fuel generation. The Sierra Club, Union of Concerned Scientists and Conservation Law Foundation filed for a rehearing in early September.

“The order approves significantly increased incentive payments to oil and gas generators with no assurance that these incentives will change those generators’ behavior in ways that improve reliability,” the organizations wrote in their request. “The commission failed to assess whether the benefits to consumers justified the costs.”

FERC denied the request by default due to the lack of timely action in October. In the Nov. 30 order, the commission upheld its ruling while responding to the arguments of the rehearing request.

“The proposed tariff revisions represent a just and reasonable means of updating the program payment rates to ensure that the Inventoried Energy Program provides appropriate incentives and compensation for market participants to participate in the program,” the commission wrote.

FERC also disagreed with the climate groups about how the IEP will affect generators’ behavior, concluding “ISO-NE’s proposed indexed rates are expected to change market participants’ behavior in the manner intended.”

In the rehearing request, the climate organizations argued most relevant generators already are required by their capacity supply obligations to be available to produce energy, making additional payments from the IEP unnecessary.

FERC disagreed, writing that “the capacity supply obligation does not require the same behavior that the Inventoried Energy Program is designed to incent.”

While the climate groups argued recent ISO-NE studies indicate that “even in a severe winter, there is negligible reliability risk, in part due to increased deployment of wind and solar resources,” FERC said ISO-NE’s winter reliability analyses cited by the environmental groups “actually underscore the important role of the Inventoried Energy Program in providing winter reliability in New England.”

“The winter analyses rely on the assumption that the Inventoried Energy Program will ‘operate as intended’ and that the Inventoried Energy Program will fulfill its purpose of enhancing reliability,” FERC wrote.

Casey Roberts, senior attorney at Sierra Club, wrote in a statement that the organization is disappointed with FERC’s ruling.

“Rather than raising costs for ratepayers across the region to pay polluting oil and gas generators, ISO-NE should instead focus its efforts on building a reliable, lower-cost electric system by bringing more wind and solar online and ramping up energy storage,” Roberts said.

Roberts added that the Sierra Club “will continue to review FERC’s order as we consider our next steps moving forward.”

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Senate Energy Committee Examines State of Advanced Nuclear Reactors

The Senate Energy and Natural Resources Committee on Thursday looked into the state of advanced nuclear reactors just weeks after NuScale Power and Utah Associated Municipal Power Systems terminated a once promising pilot project. (See Pioneering NuScale Small Modular Reactor Project Canceled.) 

Both the Infrastructure Investment and Jobs Act and the Inflation Reduction Act gave billions of dollars to the sector for demonstration projects and commercialization incentives, said committee Chair Joe Manchin (D-W.Va.). 

“Despite all of the federal and private sector support, we’re witnessing struggles and hesitancy in getting advanced nuclear projects off the ground,” Manchin said. “There are large design, cost and regulatory uncertainties associated with first-of-a-kind nuclear technology — which is why we’ve now created numerous federal programs to help reduce these risks. But someone will need to go first, and unfortunately many of the utilities I’ve spoken with won’t get in the game until others have done it first.” 

The recently canceled Carbon Free Power Project was going to be constructed at the Idaho National Laboratory by NuScale, featuring 60- to 77-MW modules that could be scaled up as the municipal power agency’s needs grew, said lab Director John Wagner. 

The project got $771 million in funding from the federal government that taxpayers will not get back, as it was picked for the grant in a noncompetitive process, unlike other advanced nuclear pilots by TerraPower and X-energy, Manchin said. 

“I can’t speak to the procurement process, and so on and so forth,” Wagner said. “I can speak to … a lot was accomplished with that project, despite the fact that it was ultimately decided to be terminated. A design certification for an advanced small light water reactor was accomplished; experience with the licensing process; experience with developing the supply chain.” 

While the project offered a chance to test out the regulatory process, in his written testimony Wagner said the industry has to end the “era of constructing paper reactors.” 

“The Carbon Free Power Project was suspended because of economics,” Wagner wrote. “A lack of subscriptions was directly related to the cost issues surrounding deployment of first-of-its-kind technologies.” 

The Department of Energy’s “commercial liftoff” report for advanced nuclear gave several recommendations to enable a “committed orderbook,” said Wagner: cost overrun insurance, tiered grant financial assistance, government ownership, and government-enabled off-take certainty. (See DOE Reports Highlight 3 Technologies to Decarbonize US Economy.) 

Utility executives have indicated they do not want to go first on developing new nuclear technology, especially given Southern Co.’s experience with the Vogtle plant and its massive cost overruns, said Manchin. He asked the witnesses how to overcome that resistance. 

The next reactors will benefit from the investment and production tax credits from recent legislation, but that is not enough to get the first reactor built, said Jeffrey Merrifield, a former Nuclear Regulatory Commissioner and chair of the U.S. Nuclear Industry Council’s Advanced Nuclear Working Group. 

“That’s where I think there needs to be a backstop program,” Merrifield said. “So that if there are timing delays [or] cost overruns, there can be a sharing of that cost and not burden that single company, whether it’s a utility or an industrial user, for putting their neck out and trying to move forward with the technology.” 

Utilities are not the only private companies looking into advanced nuclear, with Dow Vice President for Energy and Climate Edward Stones saying his firm is interested in using small modular reactors to replace the combined heat and power systems it uses at its factories. The firm has to produce 10 GW of electricity, heat and steam for its 25 major manufacturing sites around the globe. 

Dow is working with X-energy to build four SMRs at its Seadrift facility in Texas, with plans to start construction in 2026 and be operational by 2030. 

“The project will provide the Seadrift site with safe, reliable, zero-carbon-emissions power and steam as the existing energy and steam assets reach their end of life,” Stones said. “The project is expected to reduce the site’s emissions by 440,000 MT CO2e/year.” 

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COP28: The World Can’t Afford an ‘Orderly’ Energy Transition

DUBAI — The energy transition will be messy, but mistakes along the way are essential as the world attempts to solve the complex and broken ecosystem that caused climate change, leaders from the industrial and financial sectors said at a McKinsey panel on the net-zero transition.

The panel took place in COP28’s Green Zone, a short walk from the Blue Zone, where governments and NGOs are negotiating commitments and reporting on progress toward the Paris Agreement.

“The idea of orderly transition is a wrongheaded idea,” said Lord John Browne, managing director of climate growth equity fund General Atlantic and co-founder of BeyondNetZero. “It’s testing and trying: no one has the answer.”

This “test and try” approach to solving the energy transition can be seen in everything from incentives to financial structures to supply chains, he said. Governments and industry make mistakes in almost all aspects of the transition, but a poorly designed incentive with unintended consequences is better than no action at all, and those actions help figure out what does work, he added.

Accepting and embracing the three steps forward, one step back nature of the transition is essential, said Tom Linebarger, former CEO and chairman of Cummins, because without it, “it causes people to wait for the perfect solution, for some technologists to deliver something that’s going to be free for everybody and really perfect.”

Lord Browne and Anne Finucane discuss climate financing on McKinsey’s stage in the Knowledge Hub at COP28 | © RTO Insider LLC

“We’re going to be disappointed by the side effects of everything from batteries to hydrogen manufacturing. There are going to be things that we didn’t predict, there are going to be things that don’t work the way we want,” Linebarger said. But “if we don’t get started, we don’t solve those problems.

“The question is, how do you move when you know you’re going to make mistakes? How do you get going to take a step forward? That’s really the challenge in front of corporations, investors, people who are trying to advance the cause.”

Too many corporations wait for the risk to be removed, particularly in industries where commodity prices drive decisions, but Linebarger said companies must act in the short run, with the expectation they’ll learn and win over time.

Investing in the energy transition also means accepting that work will need to be redone over time, Browne said. For example, early wind farms are being redone with more powerful turbines, and solar farms built today will be redone when more powerful panels reach the market.

Even with alignment about the problems and commitments being made by governments at COP28 to solve them, there’s a $2 trillion shortfall of the $4 trillion a year needed to reach climate goals, said Anne Finucane, chair of Rubicon Carbon. “You can figure your way to $2 trillion through the market, just based on 20% equity and 80% financing” that’s typical from banks, private equity firms and asset managers. “The question is what to do about the other $2 trillion.”

Carbon taxes are seen as a necessary tool, but there’s no consensus on whether they should be voluntary or required, and whether voluntary carbon taxes are underpricing carbon.

Panelists said private sector funding alone wouldn’t be sufficient to close the investment gap, and that public and private partnerships are essential. “This is a catalytic moment because it will push governments to do the right thing,” Lord Browne said.

Mapping a Path to Net Zero

The panel coincided with McKinsey’s release of a new report: “An Affordable, Reliable, Competitive Path to Net Zero,” which argues for “not one objective, but four interdependent ones: emissions reduction, affordability, reliability and industrial competitiveness.”

Designing an achievable path is critical, said Daniel Pacthod, senior partner at McKinsey, because the world is far from achieving the Paris Agreement targets. “We’ve seen this in the global stock takes: we’re not going to be remotely close to where we want to be. We are closer to 2.5 degrees in, more than 1.5.”

The report looked at seven principles for decarbonization and said applying two principles — deploying lower-cost solutions and using R&D and other measures to double the expected rate of cost declines — “could substantially improve the current trajectory of emissions and help limit warming to what the Paris Agreement envisions.”

While the potential of a pathway based on those principles is hopeful, the report also warned that “a poorly executed transition could make energy, materials and other products less affordable, compromising economic empowerment. It could also make the supply of energy and materials less secure and resilient, and it could render some countries and companies less competitive. If that happened, progress toward net zero itself could stall.”

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Whitmer Signs Climate Bills, Including 100% ‘Clean Energy’ Goal

Michigan Gov. Gretchen Whitmer (D) signed a sweeping package of climate legislation into law Nov. 28, setting a 100% “clean energy” target for 2040, expanding energy efficiency programs and making it easier to site renewable projects. 

The seven bills Whitmer signed in a ceremony in Detroit codify many of the goals she set two years ago in her Healthy Climate Plan and add the state to the ranks of those pledging to reach net-zero carbon emissions in less than a generation. 

Whitmer said the bills, passed earlier in November by the Democratic-controlled legislature, would reduce utility bills and create thousands of new jobs. (See 100% Clean Energy, Renewable Siting Bills Heading to Mich. Governor.) 

“With today’s bills, we define the future. As Michiganders, we know we have a responsibility to face climate change head-on, not only to make lives better today, but to make sure life goes on centuries from now,” she said. 

The package includes the Clean Energy and Jobs Act, controversial legislation (HB 5120 and HB 5121) that gives the Public Service Commission power to approve sites for new large-scale renewable energy projects if local governments otherwise try to prevent them. Local government organizations have opposed the measures, setting up the possibility of a court challenge. 

Also signed by Whitmer was the Clean Energy Future Package: 

    • SB 271 expands the current 15% renewable energy standard to 50% by 2030 and 60% by 2035. It also requires 80% “clean energy” — including renewables, nuclear and natural gas with 90% carbon capture — by 2035 and 100% by 2040. The law also sets a 2,500-MW storage target for 2030 and increases the cap on distributed generation such as rooftop solar from 1% to 10%. 
    • SB 273 requires utilities to boost their EE savings from 1% to 1.5% and sets the first-ever requirement for EE programs for low-income residents. 
    • SB 502 requires the PSC to consider environmental justice, climate, affordability and reliability in its decisions on utility integrated resource plans. 
    • SB 519 creates a Community and Worker Economic Transition Office in the Department of Labor and Economic Opportunity to help retrain auto, energy and construction workers who lose jobs because of the switch to electric vehicles and efforts to reduce greenhouse gas emissions. 
    • SB 277 codifies an existing state rule allowing farmers to remain enrolled in the state farmland preservation program even if they rent their land for solar farms. 

The state Department of Environment, Great Lakes and Energy cited modeling by clean energy consulting firm 5 Lakes Energy that predicted the new policies would create nearly 160,000 jobs, cut household energy costs by at least $145/year and enable the state to obtain $7.8 billion in federal funding. 

The right-leaning Mackinac Center for Public Policy, in contrast, said the policies would “raise individual electricity rates by potentially thousands of dollars per year.” 

Some environmentalists criticized legislators for changing the 100% deadline from 2035, defining landfill gas and incinerated waste as renewable energy, and allowing natural gas generators to remain in operation if they include carbon capture.  

Juan Jhong Chung, co-executive director of the Michigan Environmental Justice Coalition, said the legislation “completely misses the mark.” 

“In fact, it opens the door for more pollution in overburdened communities,” he tweeted. “This package reflects the priorities of the utilities and lobbying groups. EJ communities expected more of Michigan’s Democratic trifecta.” 

But many raved about the package, saying the new laws make Michigan a national climate leader. 

Alli Gold Roberts, senior director of state policy for Ceres, said her group supported the package “in partnership with many businesses.” 

Michigan is “now leading the U.S. Midwest in clean energy adoption,” Jeff Bishop, CEO of energy storage developer Key Capture Energy, told Energy Storage News. “We’re going to be seeing legislation like this all throughout the Midwest, and Michigan is just going to be the start.” 

Passage of the legislation, which was opposed by Republicans, was made possible when Democrats gained control of both houses and the governor’s office for the first time since the 1980s.  

“Gov. Whitmer is trying to build her national profile with the Democrat Party,” House Minority Leader Matt Hall told Fox News. “I think in order for her to build her brand with the far left and the Democrat Party, she felt she had to try to one-up them here in Michigan.” 

The Legislature ended voting for the year on Nov. 9 after two Democratic representatives won mayoral races, leaving the House temporarily in a 54-54 tie. 

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FERC Approves NERC Standards Process Changes

FERC on Nov. 28 accepted NERC’s proposed changes to its reliability standards development process, but it ordered the ERO to submit a follow-up filing by May 2025 to review the effectiveness of the new provisions (RR23-4).

The changes are intended to streamline the development process and allow a faster response to emerging issues. They will primarily affect section 300 and Appendix 3A of NERC’s Rules of Procedure. NERC’s Board of Trustees approved the revisions at its August meeting in Ottawa and submitted them to FERC for approval the following month. (See “Standards Process Changes Accepted,” NERC Board of Trustees/MRC Meeting Briefs: Aug. 16-17, 2023.)

Section 300 of the ROP provides for “public comment, due process, openness and a balance of interests in developing proposed reliability standards,” FERC’s order noted, while Appendix 3A constitutes the ERO’s Standard Processes Manual (SPM), which sets out how standards are to be developed and revised, along with violation risk factors and severity levels, definitions of terms and reference documents.

Board Authority in ‘Extraordinary Circumstances’

Under a newly added section 322, NERC’s board would have the authority to direct the development of a new or revised standard “in extraordinary circumstances, where the board determines a directive is essential to provide for an adequate level of reliability for the” power grid, an event NERC’s petition called “unlikely and unusual.”

Currently, NERC’s board can make such a directive only when the commission or another governmental body has directed the development of a standard but the ERO’s normal development process has failed to satisfy industry consensus.

If the board does decide to authorize the development of a standard, the new section will require it to provide preliminary written notice, with its reasoning for ordering the standard, and set a public comment period of at least 45 days. Standards the board orders under this new authority will be developed using the SPM and subject to the same requirements for public comment and balloting.

Changes to the SPM include creating a tiered system of comment periods, under which the initial 45-day comment and balloting periods would be followed by shorter comment periods of as little as 30 days, when “appropriate for a smaller number of changes affecting a [smaller] number of standards.” The length of the comment period would be determined by the standards drafting team responsible for the project.

In addition, drafting teams will be allowed to conclude a standards action without a final ballot if the previous ballot received approval from at least 85% of the ballot body; the team has “made a good faith effort at resolving applicable objections” and responded to comments in writing; and no further changes are proposed. If no final ballot is conducted, NERC will provide notice of the outcome as if the ballot had been conducted.

Additional revisions to the ROP include retiring section 316, which “commits the ERO to seeking and maintaining” certification from the American National Standards Institute (ANSI) for its standards development process.

NERC observed in its petition that FERC does not require ANSI accreditation, but that the ERO initially used the process to satisfy the commission’s requirement that its rules provide due process and openness. After “15 years of operating in a unique, multijurisdictional framework,” NERC now believes retiring the ANSI requirement will allow more flexibility in its development approach.

FERC Wants Follow-up in 2025

While the commission agreed with improving the speed and flexibility of the standards development process, it also noted the “need for a timely and responsive … process given the rapid pace of change in the reliability and security of the” grid.

To assess the suitability of the ROP revisions, FERC directed NERC to submit, within 18 months of the commission’s order, an informational report on the effectiveness of the changes and whether any further refinements are needed. FERC said the report should include:

    • data on the ERO’s performance since approval, such as a comparison of development times for standards before and after implementation;
    • discussion of how the revised procedures have helped NERC expedite standards on topics such as resource mix changes, cybersecurity and extreme weather;
    • whether and why any standards have been delayed;
    • recommendations for addressing further concerns with the standard development process; and
    • discussion of how NERC has continued to meet FERC’s requirement of a fair and open process.

Commissioner James Danly did not participate in the decision.

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Big Savings for Tx Competition Claimed as FERC Considers a New ROFR

The Electricity Transmission Competition Coalition released a report Nov. 29 arguing that getting rid of competitive forces in transmission development would cost consumers hundreds of billions of dollars on the grid buildout. 

“Without competition, consumers are going to be faced with decades of high electricity inflation,” ETCC Chair Paul Cicio said in an interview. “We all know that transmission is very capital intensive, and even with competition, consumers’ electricity bills are going to go up. But with competition, we can avoid up to on average 40% of the cost of new transmission.” 

That 40% figure would involve more transmission competition than has happened so far. While FERC ended the federal right of first refusal with Order 1000 more than a decade ago, since then just 3 to 8% of all transmission lines have been subject to competition, ETCC said. 

Getting a third of all transmission development subject to competition would save $277 billion on the $2.1 trillion in transmission expansion that Princeton University forecast in its often cited “Net-Zero America” study. If all new transmission projects were open to competitive bidding at an average cost savings of 40%, it would save $840 billion on that buildout. 

Transmission lines can get returns on equity of 10 to 12% for periods lasting 40 years, but competitive bidding can push that ROE down, ETCC said. 

“Competitors can say, ‘Well, instead of accepting a 12% return on equity, our bid on this project is 10%,’” Cicio said. “That automatically is a lower cost to consumers, so competition drives down costs.” 

In its Notice of Proposed Rulemaking on transmission planning, FERC went the other way, finding that total elimination of a federal ROFR for incumbent utilities on transmission lines running through their territories led to “flawed incentives” that might prevent the most efficient transmission from being developed. The NOPR would allow a ROFR to be reinstated as long as utilities work with another party on any lines (RM21-17). (See Battle Lines Drawn on FERC Tx Planning NOPR.) 

“The real concern here is that competition, when you put it in the context of transmission, is a much more complicated issue than it would be, say, in the generation side,” WIRES Group Executive Director Larry Gasteiger said in an interview. “And what we’re seeing in reality is that things are taking longer, because the processes are much more involved.” 

The two largest RTO markets offer different experiences in building out regional transmission lately, with Gasteiger noting that MISO, with its high share of state ROFR laws, is often touted as successful with its Multi-Value Project portfolio. 

“So, in my mind, that kind of calls into question this argument that you need to have competition in order to get transmission done, and to get it the cheapest possible way,” Gasteiger said. 

PJM has a much different process, leaving policy-based lines up to the states driving those needs. Its utilities’ spending on local transmission has often been criticized, including in a complaint by the Ohio Consumers’ Counsel (EL23-105). The OCC alleged that Ohio utilities had unjustly spent $6 billion on local supplemental projects since 2017, pushing up electricity rates. 

Ohio’s utilities have responded that the OCC failed to show any evidence that they are overspending on such projects, and that it should be left to the state to oversee them. Both sides of the broader transmission-competition debate have weighed in on the complaint as well, with WIRES attaching a Charles River Associates report on the benefits of local transmission planning to its comments. 

“Notwithstanding the challenges that there may be with getting regional, and even more so interregional, transmission [built], that doesn’t mean we don’t need a lot of local transmission developed too,” Gasteiger said. “So, the fact that we’re actually just getting something done at the local level doesn’t necessarily mean that is bad, or that it is wrong. What it means is that it’s needed, and it’s actually getting accomplished.” 

ETCC did not weigh in on the complaint, but many of its members did. Cicio noted that it highlights another part of ensuring costs are low for customers as the grid expands. 

“There’s the oversight to make sure that we need the project,” Cicio said. “The second part, if we need the project, it needs to be competitively bid, so that it reduces costs. It’s a two-step process.” 

ETCC’s report, titled “FERC’s $277 Billion Electricity Price Hike,” focuses on consumer costs, reporting that the price of electricity has outstripped inflation in recent months, despite declines in the cost of other energy commodities including gasoline and fuel oil. One in five U.S. households have struggled to make a utility payment in the past year, and 26% of homes have experienced energy insecurity, it says, citing data on energy affordability from the U.S. Census Bureau. 

“Even the Federal Trade Commission and the Department of Justice of this Biden administration weighed in, in writing, to FERC saying: ‘FERC, do not back away from competition,’” Cicio said. “And, so, we hope that they will do the right thing and strengthen Order 1000 and require all projects that are 100 kV or larger to be competitively bid.” 

Gasteiger did not push back against the census data, but he did question whether transmission competition would really save hundreds of billions of dollars in future investments. 

“Their savings projections are just that: They’re projections,” he said. “They’re hotly contested. And the track record shows that they’re often not reliable.” 

Ultimately, these questions will be answered by FERC whenever it issues its final rule, he said. 

WIRES does not want to see competition for transmission expanded, arguing that would delay transmission that is successfully getting built under the current regulatory model. Competitive transmission might work for the very-hard-to-build lines that stretch across multiple states to ship renewable power long-distance, or in similar transmission projects that help meet public policies, Gasteiger said. 

“See if you can get it to work, and then build on that,” Gasteiger said. “But if not, don’t just automatically start expanding into areas where we’re actually getting transmission built and jeopardize the ability to get that transmission built as well.”