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November 16, 2024

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NYISO Stakeholders Advance Rules on Ambient Ratings, Internal Controllable Lines

RENSSELAER, N.Y. — NYISO’s Business Issues Committee on Wednesday approved tariff revisions to align day-ahead market (DAM) congestion settlement procedures with ambient-adjusted ratings (AARs). 

FERC Order 881, issued in December 2021, mandated transmission providers evaluate their transmission capacity based on real-time environmental conditions, such as air temperature, wind speed and solar radiation (RM20-16). The order requires transmission providers to use AARs for short-term transmission requests — 10 days or less — for all lines impacted by air temperature. Seasonal ratings will be required for long-term service. (See FERC Orders End to Static Tx Line Ratings.) 

NYISO’s proposed revisions aim to resolve inconsistencies between AAR rating limits used in the DAM and those assumed in transmission congestion contract (TCC) auctions.  

This included changes to calculations of the congestion rent impacts of uprates and derates and the creation of a new category of qualifying events resulting from differences in the DAM ratings required by Order 881 and those assumed in TCC auctions.  

FERC partially rejected NYISO’s initial July 2022 compliance filing, saying that some of the ISO’s revisions fell outside Order 881’s scope, certain terms were inadequately defined and the ISO was non-compliant with the timeline requirements of the order. (See FERC Approves Batch of Line Ratings Compliance Filings.) NYISO is awaiting a decision on its second compliance filing, submitted in June 2023. 

NYISO’s ability to adjust its transmission line ratings in real time has become increasingly important to maintaining grid stability and efficiency, especially as the grid integrates more intermittent energy sources and climate change leads to more variable weather patterns. 

The proposed changes now move to the Nov. 29 Management Committee for final approval. The ISO plans to implement the changes alongside its compliance proposals already accepted by FERC.  

Internal Controllable Lines

The BIC also voted Nov. 15 to recommend the MC’s approval of energy market, capacity market and market mitigation rules for new “internal controllable lines” (ICLs).  

Clean Path New York (CPNY), a 175-mile, 1,300-MW HVDC line, will be the first ICL in the New York control area. CPNY, which was selected under the New York State Energy Research and Development Authority’s Tier 4 renewable energy certificates program, will deliver renewable power generated upstate into New York City. 

The ISO’s revisions will optimize ICL flows based on economic dispatch to serve loads at the least as-bid cost. Bilateral energy market transactions will not be permitted to source to or sink from an ICL. 

The lines will be eligible for day-ahead bid production cost guarantee (BPCG) payments and for real-time BPCGs only if they are dispatched out-of-merit for reliability. They also will be eligible for day-ahead margin assurance payments when scheduled out-of-merit or derated for system security or to permit the ISO to produce additional operating reserves. 

ICL bids will include an operating range and up to an 11-step dollar/MWh curve based on CPNY’s willingness to be paid or to pay to transmit energy between its two terminals. They will be limited to a maximum bid of $1,000/MWh and a minimum bid of -$1,000/MWh. 

Both day-ahead and real-time settlements will be based on the price differentials between the injection and withdrawal buses, and line losses. 

The ISO said it is proposing a flexible capacity market design without tying supply to specific generators. An ICL must hold unforced capacity delivery rights to be a capacity supplier; it would transmit pooled capacity, sourcing in the NYCA and sinking in a locality. 

Because HVDC lines can ramp up and down as fast as 1,000 MW per second — versus the 10-20 MW per minute averaged by a typical 1,000-MW generator — ICLs’ ramp rates may be subject to limits to protect system stability. 

No new market mitigation measures will be required for ICL’s functionality but the ISO will develop a new conduct test for uneconomic production.  

Mark Younger, president of Hudson Energy Economics, asked about NYISO’s proposal to set ICL deviation charges — fees assessed to market participants for differences between their scheduled and actual energy generation or consumption — at 1.5% of the ICL’s upper operating limit. 

Michael Swider, senior market design specialist at NYISO, explained that the deviation tolerance was reduced from 3% because the operations team determined the lower threshold to be more appropriate.  

Assuming approval by the MC, NYISO plans to file its revisions with FERC in early 2024. 

BIC Election

The BIC elected Timothy Lundin, transmission regulatory policy manager for LS Power Grid NY, as the committee’s new vice chair.  

Lundin currently chairs the Electric System Planning Working Group’s but will leave that position at year’s end.  

October Market Operations

NYISO Senior Principal Economist Nicole Bouchez presented the October market operations report, noting significant declines in natural gas and distillate prices and average monthly energy costs. 

October’s average energy cost was 56% lower than the previous year, falling from $89.47/MWh to $39.44/MWh. Natural gas and distillate prices saw year-over-year reductions of 72.2% and 27.2%, respectively. The month’s LBMP also decreased to $28.10/MWh, lower than September’s $36.92/MWh and last October’s $53.11/MWh. 

Bouchez mentioned the delayed development of an operating protocol for the Long Mountain phase angle regulator (PAR) installation, also known as the Dover PAR, due to ongoing court challenges (2023-50796). The timeline to complete an agreement for this 345-kV intertie between NYISO and ISO-NE remains uncertain. 

Project Prioritization Proposal

At the Nov. 15 Budget & Priorities Working Group meeting, Kevin Lang, partner at Couch White representing the City of New York and Multiple Intervenors, proposed major changes to NYISO’s project prioritization process that seek to shorten the process, improve stakeholder coordination and enhance overall efficiency. 

Lang suggested shifting project prioritization to later in the year to allow for more accurate assessments of project costs and resource availability and facilitate a smooth transition into the subsequent year’s work. He acknowledged this could increase NYISO staff workloads but said the benefits would outweigh the extra effort 

The proposal was well received, with both Younger and Anthony Abate, lead energy market advisor for the New York Power Authority, commending Couch White for striving to improve these processes. They agreed that more information would enable better decision-making.  

Lang encouraged stakeholders to send comments or suggestions to klang@couchwhite.com. He said he plans to present an updated proposal that incorporates submitted feedback in January 2024. 

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Stakeholder Soapbox: Let the Market Determine the Fate of EVs

Advocates of various energy technologies have long argued that major barriers, either government or market derived, stifle the development of their favored technology. They then infer that the current level of their preferred technology is suboptimal, necessitating some form of governmental intervention.

That seems to hold true for New Mexico Gov. Michelle Lujan Grisham, who wants state tax credits and mandates on the purchases of electric vehicles (EVs). New Mexico already has a stringent clean car rule that requires that by 2031, 82% of all new vehicles delivered to the state be zero emission. Her agenda is a double whammy for gasoline/diesel-powered vehicles: make EVs more economically attractive with taxpayer-funded subsidies and restrict the number of gasoline/diesel-powered vehicles New Mexicans can buy. She is essentially forcing EVs on New Mexicans faster than what they prefer.

Perhaps the most pathetic part of her agenda is that she hopes to trim down the number of gasoline/diesel-powered vehicles in the state without knowing whether that is what the residents of New Mexico want. (Car owners are wary of EVs for various reasons, including: their high upfront costs; range anxiety, i.e., their fear of not making it to the next charging station; and their inherent skepticism of new technologies.) How arrogant is that? She is telling New Mexicans that as governor, she knows better what types of vehicles they should purchase than they do. She is ignoring the wishes of her constituents to purchase different vehicles: Today, only about 1% of the vehicles in New Mexico are EVs.

She desires to fundamentally reshape the car industry via regulations, mandates and subsidies. Added to the insult is her requirement that taxpayers pay for her “all-electric” scheme when the majority of residents don’t stand to benefit.

So far, purchasers of EVs are mostly in the high-income category, and that will likely hold for the foreseeable future. That means tax credits and other subsidies will benefit the well-to-do and be paid for by folks who are less financially well off. One study remarked that “The US academic literature indicates that up to 90% of EV purchase incentives adopted by the federal government have flowed to the richest one-fifth of households.”[1] This also suggests many of the purchasers would have bought an EV in the absence of government incentives. This behavior means (1) the reduction in greenhouse gas (GHG) emissions attributable to the incentives are overstated and (2) the incentive is essentially a windfall gain to higher-income households paid for by less-well-off ones.

And what is in it for the residents of New Mexico and other jurisdictions inducing EV purchasers with subsidies and mandates? Zilch! What almost always gets ignored is the fact that no matter how many EVs New Mexicans or people in other jurisdictions buy, the effect on climate change is negligible.

A mandate to require that a certain percentage of vehicles be EVs represents a policy with intrinsic distortions. It is a highly blunt instrument, draconian and expensive relative to other ways to mitigate GHG emissions (which is the manifested rationale for the governor’s all-electric mandate).

Probably most serious, banning or artificially restricting goods or services reflects governmental action that dictates consumers find a substitute that presumably is inferior to the alleged objectionable product that is banned, or else such action would not be necessary. A ban forces consumers to do something they otherwise would not do. For example, vehicle owners could hang on to their old, less fuel-efficient vehicles longer than otherwise — a perverse outcome that could lead to higher GHG emissions.

By reducing options for vehicle owners, driving will become more expensive in New Mexico. Perhaps this is the intent of those who are anti-car. As warned by energy expert Mark Mills of the Manhattan Institute, “they’re coming for your cars.”

Government controls over GHG emissions directly affect goods and services, such as electricity and transportation, whose costs will likely escalate. If controls include banning or severely restricting fossil fuels like gasoline, the costs could be substantial. We have an abundance of fossil fuels at affordable prices, which explains why over 80% of the world’s energy still comes from fossil fuels. This raises the question of whether we want to or can wean ourselves from fossil fuels over the next two or three decades without suffering severe economic consequences.

The governor’s actions presume that EVs are a winning technology — but this is highly presumptuous, as there is much uncertainty over the future of EVs. Mandates carry risks. Mandates require policymakers to pick winners and losers, which is inherently almost impossible, and often results in failure, given the limited knowledge of policymakers (which, of course, they don’t want to acknowledge) and their propensity to serve special interests. The problem is particularly acute for new technologies with a high level of uncertainty over cost and performance. For example, a policy that mandates EVs as a preferred option can turn out disastrously if the price of gasoline falls sharply or if EVs fail to develop economically and technically as advocates hope.

A better way to make EVs more attractive to consumers is to have them compete against gasoline/diesel-powered vehicles. When regulating or legislating away their main competition, it becomes more likely that EVs will continue to be inferior to gasoline/diesel-powered vehicles. This is just one example of the unintended consequences sprung from a policy whose prime intent is to promote a particular technology.

What is particularly perplexing is the rationale behind the governor’s intent to accelerate the purchase of EVs by New Mexicans through tax credits and mandates. She argues that the tax credits will make EVs more affordable to middle- and low-income households. But one cannot ignore the evidence showing that the subsidies will disproportionately benefit the wealthy at the expense of those less well off. So far, 90% of EVs in the U.S. have been purchased as a second or third car by high-income households. [2]

It’s not even clear that replacing gasoline/diesel-powered vehicles with EVs will have a positive environmental effect. Similar to many other batteries, the lithium-ion cells that power most electric vehicles rely on raw materials (like cobalt, lithium and rare earth elements) that have triggered grave environmental and human rights concerns. Cobalt has been especially problematic. The environmental effect, of course, also depends on what energy sources are used to produce electricity. Currently, much of the electricity generated at night (when charging occurs for most EVs) comes from fossil fuels.

Even if EVs lower GHG emissions, studies have shown they are an inefficient way in terms of the costs per unit of avoided emissions. Other alternatives, such as nuclear power and natural gas are more cost-effective. One study claimed that EVs are among the most expensive tools government can use to lower GHG emissions, measured as dollars spent to achieve a given amount of GHG reduction.[3] What would seem to be a preferred social policy is to impose an efficient tax on GHG and tailpipe emissions.

I believe that what is driving EV frenzy is the anti-fossil fuel agenda or virtue signaling (by both EV purchasers and EV advocates). EV advocates probably know EVs would have a minuscule effect on climate change but long to see the extinction of fossil fuels; I can’t think of a more plausible explanation.

To wit, most climate activists view fossil fuels as a barrier to achieving deep-decarbonization targets deemed essential to protect against alleged catastrophic climate change. They consider electrification of buildings and transportation with clean energy sources as part of a policy portfolio to achieve these targets. What they don’t say is that their proposals for government intervention will fail a cost-benefit test and are regressive by benefiting the well-to-do at the expense of others. How can they then defend their pro-EV advocacy with such anti-social results?

I want to conclude by saying that I think EVs are a remarkable technology that I hope will succeed on its own without government assistance. Both for equity and economic-efficiency reasons, government inducements — whether to hasten the number of EVs or charging stations through perverted policies — are a bad idea. Governments can better spend taxpayers’ monies. EVs have a promising future. Technological advancements in batteries and the other sides of production, as well as in charging stations, will ultimately decide the fate of EVs, as they will determine consumers’ demand for EVs and manufacturers’ profits from EVs. Their success is more likely if government steps out of the way and allows EV providers to address market demands to lure consumers with price reductions and better vehicle performance — not with subsidies and mandates.

Kenneth W. Costello is a regulatory economist and independent consultant.

 

[1] Fraser Institute, https://www.fraserinstitute.org/sites/default/files/review-of-electric-vehicle-consumer-subsidies-in-canada.pdf.

[2] Energy Institute at Hass, https://energyathaas.wordpress.com/2021/09/20/three-facts-about-evs-and-multi-vehicle-households/.

[3] International Monetary Fund, https://www.imf.org/en/Publications/fandd/issues/2019/12/the-true-cost-of-reducing-greenhouse-gas-emissions-gillingham.

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Northeast States Detail Early Efforts on Interregional Tx Collaborative

States in the Northeast are working together to expand interregional transmission with a focus on coordinating the connection of offshore wind facilities to the grid, according to speakers on a Wednesday webinar hosted by Advanced Energy United. 

Representatives from states working on the Northeast States Collaborative on Interregional Transmission spoke about the first months of their work since the effort was launched in June with a letter to the Department of Energy. 

“We still are in early days of the collaborative,” said Jason Marshall, deputy secretary of the Massachusetts Executive Office of Energy and Environmental Affairs. “But I think with as much expertise as we have in the room, focused in one place, we really do have a unique opportunity to chart a path forward toward greater interconnectivity.” 

While the collaborative has a focus on helping to connect offshore wind, Abe Silverman, director of the Center on Global Energy Policy’s Non-Technical Barriers to the Clean Energy Transition initiative at Columbia University, said the benefits of transmission go well beyond that. Transmission has helped regions better manage recent reliability events such as last December’s winter storm, he noted. 

“This is about money at the end of the day for a lot of folks,” Silverman said. “And so, as we think about building this coalition between various states — both states with really aggressive carbon policies and states with less interest in that — we really need to talk about the money piece of it, and transmission can be enormously cost saving as well.” 

The initial letter was signed by the six New England states, New York and New Jersey, which all have similar energy policies, but some of their neighbors are very different. Preethy Thangaraj, who advises New Jersey Gov. Phil Murphy (D) on energy policy, said that the states in PJM have very diverse energy policies — ranging from states like hers with strong net-zero goals, to West Virginia, where no such laws are on the books. 

The best example for multistate transmission expansion is MISO’s Multi-Value Projects, where every state got some kind of benefits, which helped connect a lot of wind power to the grid, said Silverman. 

“But it was really looking at all of this sort of value stacking of benefits that transmission gives you,” he added. 

MISO is a very large RTO, but it is a single region, while the states in the planning effort stretch across three separate markets: ISO-NE, PJM and NYISO. That means they will need to go through interregional planning, which, despite Order 1000 being on the books for a decade, has not taken off. 

Most interregional transmission lines have been backed by specific developers to ship renewables long distance, while those that have cleared the FERC planning processes have dealt with really “crisp issues,” such as the loop flows around Lake Erie more than a decade ago that impacted reliability across several markets, Silverman said. 

“The amount of true interregional planning, where you sort of look at the needs of one region and optimize it by building transmission to another region and look at their benefits and costs as well, is a relatively new concept, or at least it hasn’t really been activated,” said Silverman. “So, we talk about it a lot, but what we really need is for FERC, and to some extent the DOE, and I think the states, to come together and say: ‘OK, you know, we’ve talked about this for a while, we now need to go ahead and actually do it.’” 

The New England states especially have worked together on energy issues several times in the past, but really focusing on the transmission needed to help reliably and affordably to meet their clean energy goals is a new effort, said Bruce Ho, senior policy adviser for the Connecticut Department of Energy and Environment. And this time they need some help. 

“Ensuring this effort is successful really does critically depend on the support and interactions we have with the federal government and particularly the Department of Energy,” Ho said. “The transmission vision buildout we’re thinking of crosses state borders; it’s inherently federal.” 

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ISO-NE Study Highlights the Importance of OSW, Nuclear, Stored Fuel

ISO-NE presented the final stage of its Operational Impact of Extreme Weather Events study to stakeholders at the NEPOOL Reliability Committee (RC) on Nov. 14, shedding light on how changes to the 2032 resource mix could affect reliability in the region.

The analysis built upon findings for the winter of 2032, which were originally presented to the RC in August. The new results stemmed from additional tests — or “sensitivity analyses” — based on stakeholder requests, which included adjustments to the load profile, clean energy additions, and fossil fuel and nuclear retirements.

The sensitivity analyses assessed the 2032 grid under a worse-case scenario based on historical weather patterns from a 21-day stretch in the winter of 1961, which had the highest average system risk of all similar periods considered.

The analysis used the 2023 Capacity, Energy, Loads and Transmission (CELT) report’s load forecast for 2032, with a resource mix built around the results of Forward Capacity Auction 17. It assumed the presence of the New England Clean Energy Connect transmission line, which is under construction in Maine but has faced extensive legal and political challenges.

The results “reveal a range of energy shortfall risks and highlight the increasing energy shortfall risk between 2027 and 2032, said Stephen George of ISO-NE. George qualified that the findings “are useful for highlighting directional changes in energy shortfall risk under various assumptions; [the] results should be considered in the context of the specific assumptions made and the attributes of the Jan 22, 1961, 21-day event.”

The baseline case and the sensitivity analyses looked at shortfall with and without the Everett LNG import terminal in service. (See FERC, NERC Leaders Voice Concern About Loss of Everett Marine Terminal.) Counterintuitively, the modeling indicates that the presence of Everett marginally increases energy shortfall by enabling greater injections of LNG into the gas network and causing the region to run out of its LNG stockpile more quickly.

However, ISO-NE has cautioned that this aspect of the model should not be considered a perfect representation of future LNG stockpiling behavior.

The analysis found that replacing 1 GW of fossil resources with additional offshore wind capacity reduced the projected shortfall by 37 to 42% compared to the baseline scenario. In contrast, limiting the total offshore wind capacity to 1,600 MW — compared to the 5,600 MW assumed in the baseline scenario — increased the shortfall by 165 to 193%.

The offshore wind industry in New England has seen several major project cancellations over the past year, and industry experts have expressed their worry that this could push the in-service dates of the next wave of projects in the region into the 2030s. (See Long-term Optimism Meets Short-term Concern at Offshore WINDPOWER 2023.)

The study found that replacing a gigawatt of fossil fuel generation with onshore wind and utility-scale solar also improved reliability, but to a lesser degree. Onshore wind was associated with a 25% reduction in shortfall, while solar was associated with a 3 to 5% shortfall reduction. However, replacing the same amount of fossil fuel generation with two-hour-duration storage was associated with an 11 to 19% increase in shortfall.

The analyses modeled only two-hour-duration battery storage resources; ISO-NE received requests from stakeholders to look at longer durations but was limited by the study’s time constraints.

“Future modeling enhancements will enable the incorporation of longer-duration storage,” George said.

The baseline scenario did not include nuclear retirements, but the sensitivity analysis found that retirements would increase shortfall in all scenarios considered. Replacing all nuclear capacity with the same amount of renewable qualified capacity led to a 50 to 76% shortfall increase. George noted that retiring nuclear resources without corresponding renewable replacements would also significantly increase the region’s reliance on oil and LNG.

Regarding fossil fuel resources, the study found residual fuel oil (RFO) resources to be especially helpful to maintaining grid reliability. Replacing all RFO resources with the same amount of renewable qualified capacity led to a 19 to 36% increase in shortfall.

“Energy from resources that burn stored fuels will continue to be important in terms of minimizing energy shortfall as the region transitions to higher penetrations of renewable resources,” George said.

The study found that the retirement of 1.5 GW of gas-only generators had minimal effects on the projected shortfall because of the limited amount of natural gas available during the study period. Replacing these retiring resources with an equal amount of renewable nameplate capacity decreased shortfall by 24%.

Increasing the level of electricity imports also made a significant dent in the projected shortfall; a 50% increase in imports coupled with the elimination of the cap on maximum transfer capability reduced shortfall by 66%. Demand response also boosted reliability; an added gigawatt of active demand response capacity cut shortfall by 38 to 39%.

Finally, changes to the overall load profile had a significant effect on the shortfall. Increasing the load by 10% led to a 156 to 192% increase in shortfall, while decreasing load by 10% reduced shortfall by 84 to 87%. A 20% increase in behind-the-meter solar reduced shortfall by 7 to 10%.

ISO-NE hopes to release a final report covering the results from all phases of the study in late November or early December. Following the final report, the RTO plans to use the results to begin work on a “Regional Energy Shortfall Threshold,” which will establish “the region’s acceptable level of reliability risk.”

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RMI Unveils Initiative to Lower Carbon Footprint of Homes

Clean energy transition nonprofit Rocky Mountain Institute on Nov. 14 kicked off a “soft launch” of HomebuildersCAN, a new network to accelerate decarbonization of the residential construction sector.  

The industry stakeholder group, which launches fully in January 2024, will bring together homebuilders of all sizes to lower the embodied carbon in new homes and improve reporting of Scope 3 greenhouse gas emissions — indirect emissions in a company’s supply-chain. 

“We have three overarching goals with HomebuildersCAN. One is to increase performance on embodied emissions for new homes, figuring out where we are today and how do we map to zero as quickly as possible,” said Chris Magwood, an embodied carbon and residential construction expert at RMI (founded as Rocky Mountain Institute) overseeing the initiative. 

“Our second goal is to bring alignment across the sector so that builders are approaching this the same way. Finally, for the homebuilders themselves, we want to be supporting and encouraging them to adopt and scale profitable climate smart building practices,” he said. 

Along with improving the practices and reporting within the industry, the initiative aims to bring a shared and cohesive approach to embodied carbon to the wider ecosystem of regulators, lenders, energy efficiency programs and others, Magwood said.  

HomebuildersCAN will help builders learn about embodied carbon and develop the capacity to incorporate embodied carbon reductions into strategic plans and reports, Magwood said.  

“What we don’t want this organization to be is another labeling program, so we’re not looking to get into the business of certifying homes. We want to support homebuilders in tackling embodied carbon issues in their practice,” he said. 

The Climate Action Network (CAN) for homebuilders’ goals span from education to advocacy, and it will provide a standardized table for consistent reporting at an individual building, community or portfolio level. The industry already has several green building standards such as LEED, Passive House and HERS, and HomebuildersCAN’s reports are intended to be complementary and reference existing programs where used. A proposed annual reporting template will help companies report their impact as a whole. 

The group will help homebuilders include carbon reduction in their strategic plans, Magwood said. 

“Once the program is up and running in 2024, we’ll be working with the builders to help them get on to an embodied carbon reduction pathway. That’s going to start by providing a lot of assistance to benchmark where their embodied carbon emissions are right now and then help institute a five-year plan,” he said. 

Inaction on Climate Change as the Biggest Competitor

Several North American homebuilders joined HomebuildersCAN prior to its official launch and shaped the reporting tools and other program features. 

“We don’t see our builder down the street as our competitor anymore. We see inaction on climate change as our biggest competitor,” said Phil Squires, corporate vice president of sustainability and procurement at Mattamy Homes, the largest privately owned homebuilder in North America. “We all face the same challenges regarding design, supply, execution, tracking data and, ultimately, affordability.”  

While the homebuilding industry has taken large strides toward improving home energy efficiency over the last few decades, Squires said, dealing with embodied carbon is relatively new and there is urgency in understanding and driving down that embodied carbon.  

“We see our homes today as carbon sources and through partnerships like HomebuildersCAN, we’re hoping that we can turn that into carbon sinks,” he said.  

The creation of HomebuildersCAN was prompted in part by local governments adopting climate action plans, said Aaron Smith, CEO of the Energy and Environmental Building Alliance (EEBA).  

“One of the studies we did said that most builders didn’t know it was good to have less carbon in their home,” said Smith. HomebuildersCAN will help educate those builders about why there’s a need to reduce embodied carbon in homes and how they can reduce it. 

Part of the challenge for homebuilders, Smith said, is that many products do not have Environmental Product Declarations (EPD), a declaration of the carbon embodied in a material, making it impossible for the builders to accurately measure the embodied carbon footprint of the homes they build. 

The initiative will encourage the use of the Embodied Carbon in Construction Calculator (EC3) developed by Stacy Smedley of Skanska and Phil Northcott of C Change Labs and integrated into two existing Carbon Action Networks focused on the global building industry: OwnersCAN and MaterialsCAN.  

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EPSA Releases Policy Principles for Energy ‘Expansion’

The Electric Power Supply Association (EPSA) has released a set of policy principles it hopes will inform legislators and regulators as the grid transitions to cleaner supplies and greater demand from electrification.

Many in the industry refer to the “energy transition,” but EPSA CEO Todd Snitchler said in an interview Nov. 14 the changes also include an “energy expansion,” as electricity takes on new sources of demand including transportation and heating.

“Consumer adoption of new, electrified devices, heating and cooling systems, vehicles and industrial processes will drive further demand for electricity, and accurate wholesale pricing is needed that sends demand signals to customers to respond flexibly, economically and reliably,” says EPSA’s fifth principle.

The first principle is an endorsement of wholesale competition, the development of which enabled the independent power producer business model of EPSA’s members. It says competitive wholesale markets are the most effective tool to achieve policy objectives by encouraging private capital deployment and innovation at the lowest costs, while shifting risks to investors — not consumers.

“Hopefully, this will encourage policymakers to think about these issues as they’re making decisions about policy choices and resources and timelines,” Snitchler said. “Because it’s very easy to say you want a certain outcome; it’s much more difficult to achieve it, and we hope these will help inform the ‘achieving’ part of those policy goals.”

EPSA also says existing dispatchable resources will be needed to keep the grid reliable, even as they operate less often.

“As you see a greater penetration of renewable resources, you’re going to continue to see a need for natural gas, because of the performance characteristics it has,” Snitchler said. “It will be required when the sun isn’t shining, or the wind isn’t blowing, or you have other interruptions to non-dispatchable resources. Dispatchable resources that can respond quickly, power up and remain operational, like natural gas, are going to be profoundly important because they will be the difference between the lights staying on and us having a power outage.”

Such power plants will run less often, but they will be important to maintaining reliability when they do run. Some of the market reforms will be required to ensure plants that are vital for reliability but get fewer and fewer chances to earn money from the energy markets stay online.

“Market-based solutions, like a flexibility product, or a quick-ramping product, or something that will ensure that those resources are able to earn sufficient revenue to remain on the system, when they are needed, is going to be how we’re going to have to think about it,” Snitchler said.

Stepping back, system planning is based on parameters the industry came up with in the middle of the last century, but the grid already has changed significantly, with more on the way, so new planning methods must be developed.

In the past, EPSA focused on trying to limit the impact of subsidies on wholesale power markets, but since the Inflation Reduction Act added billions of dollars more, those debates are in the rearview mirror, Snitchler said.

“We just have to figure out how to incorporate that into the policies” needed to achieve policymakers’ objectives, he added.

Many of those subsidies and the plans to decarbonize the electric industry rely on moving past natural gas eventually. While EPSA technology is agnostic, the resources that could replace gas-fired power plants aren’t ready to do so at scale, and it’s uncertain when they will be.

“In the event that we can have the breakthroughs that will help us get to where small modular reactors can be the generation resource of the future, that would be great,” Snitchler said. “The challenge is those technologies are talked about today like we are on the cusp of having it tomorrow, and it appears that we’re farther away than that.”

Just last week, NuScale Power had to cancel a proposed SMR in Utah, while other technologies like clean hydrogen have yet to be developed at the scale and price needed where they would brgin to replace natural gas. (See Pioneering NuScale Small Modular Reactor Canceled.)

Competitive markets often are where new technologies are deployed once the economics make sense, but retiring natural gas plants too early will increase reliability risks, Snitchler said. Should there be a major crisis because of policy, it easily could lead to a backlash against the energy transition.

Polling consistently shows consumers value reliability when it comes to the grid, Snitchler said.

“If we’re moving too quickly, in any one direction, and that results in power outages, or crises that happen, public support will pretty quickly erode,” he added. “So, I think that’s something that we need to be mindful of as we go through this process, because it’s not going to happen overnight, and we need to be thoughtful about how we get from here to the ultimate destination.”

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White House Releases Climate Assessment, $6B for Resilience Projects

According to the fifth National Climate Assessment (NCA5) released Tuesday, a person born in North America in 2020 will experience more climate hazards on average than a person born in 1965. 

A 2-degree Celsius (2.7-degree Fahrenheit) increase in global temperature could mean that over their lifetime, that 2020 baby could experience a potential doubling of wildfires, hurricanes and drought and a tripling of heatwaves, along with other increases in flooding and crop failures. 

At the same time, the southeastern states could experience 25-50 more days a year with temperatures over 95 degrees Fahrenheit, while most of the country could see annual precipitation rise 5-10%. A 4-degree Celsius rise in temperatures could kick that increase up to 15%, according to the report. 

Extreme weather already is taking a major toll, with 18 events — wildfires, tornados, floods, winter storms and hurricanes — causing more than $1 billion in damages each in 2022, the report says, and each of those events had an impact on the U.S. electricity system.  

Extreme heat or cold increases electricity demand while also potentially decreasing the grid’s ability to provide vitally needed power, according to NCA5.  

Winds, floods, ice and wildfires can take down power lines, while extreme heat can reduce the grid’s transmission and distribution capacity.  Cloudy or stagnant weather can reduce wind and solar production, while extreme winter storms can freeze gas supply systems, and droughts can cut hydropower output.  

The report also includes a hopeful assessment of climate action, supported by the policies of the Biden administration and the billions in clean energy and resilience funding in the Infrastructure Investment and Jobs Act (IIJA) and Inflation Reduction Act (IRA).  

The report’s chapter on energy supply, delivery and demand notes that “federal, state, local, tribal and private-sector investments are being made to increase the resilience of the energy system to climate-related stressors.  

“Ongoing investments will need to include improvements in energy-efficient buildings; technology to decarbonize the energy system; advanced automation and communication and artificial intelligence technologies to optimize operations; climate modeling and planning methodologies under uncertainties; and efforts to increase equitable access to clean energy.” 

The administration backed up that ambitious vision with an announcement of $6 billion in funding for a range of clean energy and resilience funding, as outlined in a White House fact sheet.  

The Department of Energy is opening the second round of funding for its Grid Resilience and Innovation Partnership (GRIP) program that will offer $3.9 billion from the IIJA for projects that “will modernize the electric grid to reduce impacts from extreme weather and natural disasters, increase capacity and unlock renewable energy resources.” 

The first round of GRIP funding, announced last month, awarded $3.46 billion to 58 grid improvement projects. 

EPA soon will announce a $2 billion funding opportunity through its Environmental and Climate Justice Community Change Grants program. With dollars from the IRA, projects will focus on community-driven efforts to “deploy clean energy, strengthen climate resilience and build community capacity to respond to environmental and climate justice challenges,” the fact sheet says. 

The Interior Department will get $100 million in IIJA funds for water infrastructure upgrades for drought resilience in the West, part of which will be used for hydropower upgrades.  

Choices Made Today

The release of NCA5 likely is a strategic move as the U.S. prepares for the United Nations Climate Change Conference (COP28) kicking off in the United Arab Emirates (UAE) in just over two weeks. Ahead of the conference, the U.S., European Union and UAE are trying to rally support for a global pledge to cut greenhouse gas emissions by tripling renewable energy generation by 2030, according to a Reuters report. 

A key message of the U.S. report is that the degree of warming, and its effects on Americans, will depend on choices made now.  

The energy sector is pivotal because while changes in technology can reduce emissions, they also can increase system vulnerabilities as demand increases and shifts, the report says. Climate change could drive major increases in power demand, according to the report. The western U.S. could see demand jump 50% by 2050, while demand in the eastern part of the country could rise 30-40%. 

Between 2050 and 2100, those increases could soar by as much as 200% in the Southwest and by 150-175% along the East Coast.

Portfolio of mitigation options for achieving net zero by 2050 | NCA5

 

The report’s potential solutions for promoting energy system resilience include the adoption of microgrids and storage to reduce the risk of power outages, adopting building codes that increase efficiency and cut energy demand, and decarbonizing the grid with zero-emission technologies.  

President Biden has set a 2035 goal for the U.S. electric system to be powered 100% by clean energy. But NCA5 predicts that by 2050, solar, wind, nuclear and other renewables will account for only about 75% of U.S. electricity generation, with natural gas and coal still in the mix.  

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Asia-Pacific Energy Leaders See Challenges, Opportunity in Green Goals

SAN FRANCISCO — Policymakers must invest in scaling clean energy solutions if the Asia-Pacific region is to meet climate goals, experts said at the Green Innovation and Sustainable Development Forum held by the US-China Green Energy Council and the APEC Sustainable Energy Center in San Francisco on Nov. 13.

With increasingly expensive extreme weather events brought on by man-made climate change, the cost of rapid action is lower than the cost of inaction, said Anand Gopal, executive director of Energy Innovation.

“It will be $12 trillion cheaper to have a fast transition to net zero than it would be to have no transition,” Gopal said. However, the costs of some of climate solutions are more likely to decline rapidly as they scale, he said, citing Wright’s Law, which says the declines are most likely with products that can be mass-produced and that have lower degrees of design complexity.

Government loan guarantees have proven to be an effective way to get new technologies over early scaling issues, said Nobel Laureate and former U.S. Energy Secretary Steven Chu, who now teaches at Stanford.

“The fact that a government can come in and guarantee a loan, just in case the project defaults, will drive the cost of capital way down,” Chu said. That approach has proven its value in driving down the cost of both solar and electric vehicles, he said.

“If you want to get these rapid price drops, policymakers should trust that these will happen with clean technologies and that they will eventually save their constituents money,” Gopal said. “Leaning in early on policy, doing it in such a way that knowing that your actions will lead to a cleaner and cheaper energy future for your citizens, is very important.”

APEC’s Energy Working Group Drives Regional Action

The forum was held ahead of the Asia-Pacific Economic Cooperation (APEC) Summit, where leaders of APEC’s 21 member economies will convene to discuss a range of economic issues. APEC has an energy working group that explores regional energy issues.

“The work of APEC’s energy working group matters because APEC economies account for 56% of world energy demand, 58% of world energy supply and 68% of world electricity generation,” said Rebecca Fatima Sta Maria, executive director of the APEC Secretariat.

APEC economies account for 60% of global CO2 emissions, and 19 members have committed to achieving zero carbon emissions by 2050 or 2060, Sta Maria said.

Yongxin Zhan, co-chair of Pacific Economic Cooperation Council, said the region, which accounts for a third of the world’s population but 60% of its economic output, was dynamic in its approach to addressing sustainability goals but was still falling short of meeting the UN’s Sustainable Development Goals. Three years ago, APEC member states released the Putrajaya Vision 2040, which focuses on three economic drivers: trade and investment, innovation and digitalization, and sustainable and inclusive growth.

“We have confidence that with the common efforts of APEC member economies, the Putrajaya Vision of an open, dynamic, resilient and peaceful Asia-Pacific community and the green innovative sustainable development could be achieved,” Zhan said.

APEC’s energy working group focuses on the region’s ability to meet two goals, Sta Maria said. “The first is the collective commitment to improve energy intensity by at least 45% by 2035 compared with 2005 levels. The second goal is to double the share of modern renewables in the energy mix by 2030 relative to the numbers from 2010.”

California Plays Outsized Role in Region

While APEC member economies collectively are large, California alone carries significant weight, said David Hochschild, chair of the California Energy Commission, noting the state is home to the world’s largest geothermal plant, stationary battery project and rooftop solar PV system.

Hochschild said that, despite the media tendency to paint California’s economy as a train wreck, over the last 10 years, the state had passed Russia, Italy, France, Brazil and the United Kingdom (‘thank you to Brexit’) and this year is on track to pass Germany to become the fourth-largest economy in the world. “This has been concurrent with the largest decarbonization we’ve ever done. This has been good for our economy.”

Hochschild called California’s current era “The Great Implementation” but sees speedbumps slowing the state’s decarbonization plans.

“The speed of construction of projects is a huge problem in the state,” Hochschild said. “To construct an offshore wind project, for example, is 32 different permits. We need to have as much success on process innovation as we’ve had on technology innovation. We don’t need to do landmark policies. We just need to buckle down and focus on implementation and hire the talent for that.”

California, China Share ‘Really Robust Climate Collaboration’

Despite the Biden administration’s aim to build the U.S.’s clean energy manufacturing capacity, lessening dependence on imports from China, Hochschild sees “really robust climate collaboration” between California and China. He told NetZero Insider that the two economic powerhouses shared learnings in a recent visit to China.

Hochschild said California can learn from China’s strength in offshore wind development (“where China’s built 50% of the global capacity: we’re just getting started on that today”) and high-speed rail, an infrastructure wish list item that California has struggled to deliver.

On the other side, he said, “We can help support China with lessons learned on stationary energy storage where we’re leading the fastest-growing energy storage market in the U.S. We had an opportunity to share with the Chinese our very positive experience of bringing that onto the grid.”

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Stakeholders Approve Bulk of SPP’s Markets+ Tariff

TEMPE, Ariz. — Stakeholders interested in participating in SPP’s Markets+ service offering in the Western Interconnection last week approved much of the draft tariff language they’ve developed together in recent months. 

That tickles SPP attorney Chris Nolen, whose frequent comments about building “the best tariff ever” are being repeated by SPP staff and potential western stakeholders. 

“We’ve moved, in my opinion, more efficiently, faster, better than I thought we would when we had our kickoff meeting,” he said during a break in the Nov. 7-8 Markets+ Participant Executive Committee (MPEC) meeting. “It’s been super impressive how all the market participants, everybody involved at all the stakeholder groups picked up really quickly on how it works, how it runs, how you make comments, how you get changes you want to see in the tariff language. I think we’re in an excellent spot.” 

Arizona Commissioner Nick Myers | © RTO Insider LLC

MPEC members endorsed chunks of tariff language that define how the day-ahead Markets+ will handle market transmission use, congestion management, transmission capacity obligations, market manipulation and confidentiality. The Interim Markets+ Independent Panel (IMIP), composed of three SPP directors, added its approval as well. 

However, the Markets+ Greenhouse Gas Task Force was given up to eight weeks to approve draft language incorporating GHG emissions-related information in the market’s reporting, price formation, commitment and dispatch. The group already has a conceptual framework. 

The Pacific Northwest’s only cap-and-trade program, Washington state’s cap-and-invest initiative, has a Nov. 1, 2024, compliance deadline. By that time, affected entities need to have enough allowances to cover 30% of their 2023 emissions. (See “GHG Issue: ‘Emissions Leakage’,” Markets+ Stakeholders Begin Tariff’s Development.) 

A proposed option of making a supplemental filing at FERC once the cap-and-invest program’s rules become clear failed to garner enough support. Washington’s Department of Ecology, which is overseeing the program, has an ongoing rulemaking to be completed next summer. 

Task force chair Mary Wiencke, with The Public Generating Pool, said she expects the rulemaking to be delayed by Ecology’s concerns over Markets+’s final market design. 

“There’s a real cart-before-the-horse and a real chicken-and-egg issue here,” Wiencke said. “Somebody has to go first, and so then the rules in the market design have to be jointly sort of put together. … We need a market design to have rules also. This process is going to be iterative, no matter what.” 

“When you do that four to six weeks, or four to eight weeks, the pressure is really on all of us because we know that there’s a pretty significant consequence if we don’t get there,” PowerEx’s Mark Holman said. “We’re either [filing a supplemental] or we’re into a tariff delay that affects everything in this initiative. I like that pressure being on. I think it’s worked well. We will have different resources that roll their sleeves up and not sacrifice the quality of the solution, but actually get it done.” 

The GHG delay could throw a kink in SPP’s plans to have the tariff complete in December and take it to the RTO’s Board of Directors in February. SPP hopes to receive IMIP approval Dec. 14 before taking it to the board; the tariff would be filed in the first quarter next year, assuming final approval. 

The task force will report on its progress during MPEC’s Dec. 6-7 virtual meeting, which once was a one-day call. 

“We want to have the tariff and all the policy items done by December,” said Carrie Simpson, SPP’s director of seams and western services development. “However, to the extent that we’ve got some stuff that’s still hanging around or there’s a policy item that needs extra time, I don’t know that January’s a [hard deadline].” 

No need to worry about the additional time afforded to the GHG task force, Nolen said. 

“It’s just complex, so it’s taken a little bit when you plug it in to the broader market,” he said. “It’s new. We’ve never had to plug one in yet.” 

Nolen told MPEC if SPP receives the GHG tariff language in mid-January, staff will need only a week to “holistically consider” the tariff and to file at FERC. 

“If we tried to wait and amend the filing after the fact, that brings up some of the complications with pushing this date,” he said. “When the pens go down, we need eight weeks internally to run through that tariff and be sure that we wired everything out to the baseline tariff and everything works.” 

“The degree of collaboration and consensus that’s been required to develop this volume of tariff language this quickly is tremendously encouraging,” Antoine Lucas, SPP’s vice president of markets, said after the meeting. “SPP and the Markets+ participants are striking a remarkable balance between speed and meaningful consideration in developing a market that works for all stakeholders.” 

FERC’s approval of the Markets+ design would begin the market’s second phase of development. At that point, SPP would acquire the necessary software and hardware, participating entities would fully commit to funding the market and they would be integrated into the system. 

Go-live is targeted for October 2026. 

WRAP, RTO West Advance

SPP also celebrated recent “significant” progress with the other prongs of its western expansion. It said an important element of the Western Power Pool’s Western Resource Adequacy Program (WRAP) that it operates became operational Nov. 1, and the grid operator formally kicked off its RTO West development in Denver. 

WPP says the WRAP is the first regional reliability planning and compliance program in the history of the West. Its operations program produces updated forecasts each season to help determine whether participants will have sufficient resources and enables those with a deficit to secure additional resources. 

The RTO said the program will remain non-binding for an undefined time.  

“SPP is grateful for our partnership with Western Power Pool and the opportunity to help assure resource adequacy for their member utilities,” Casey Cathey, SPP’s senior director of grid asset utilization, said in a statement. 

On Nov. 9 in Denver, SPP hosted utilities that have committed to joining as members of its RTO in the Western Interconnection. The grid operator presented its plan to coordinate the utilities’ integration into SPP’s planning, reliability coordination, market and other services before operations are targeted to begin in April 2026. (See WAPA, Basin Electric Commit to SPP’s RTO West.) 

SPP’s senior vice president of operations Bruce Rew, who leads the RTO expansion program, said the kickoff was a result of years of negotiations and planning. 

“We’re eagerly looking forward to the day that these plans come to fruition and we have the opportunity to bolster grid reliability, bring efficiency to planning processes and leverage the full potential of a single interregional market across two interconnections,” Rew said. 

Much of the RTO West’s development will be handled through SPP’s normal stakeholder process, staff said. 

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Will DOE’s Transmission Needs Study Spur New Regional, Interregional Lines?

A key difference between the draft National Transmission Needs Study the Department of Energy released in February and the final version issued Oct. 30 is a new section in the introduction spelling out what the goals of the report are and, equally important, what they are not.

“The objective is to identify pressing transmission needs across the nation,” said Jesse Schneider, a policy adviser in DOE’s Grid Deployment Office (GDO), which authored the report. “However, the study does not prescribe any specific transmission solutions to meet those needs.”

Speaking during a recent webinar on the report, Schneider further stressed “the study findings are intended to inform department transmission priorities, including implementation of funding programs, technical assistance or broader transmission planning programs.” The report is not intended “to supplant or presuppose any existing transmission planning activities,” he said.

Similarly, while the study does break down transmission needs by region, that analysis will be used to “inform” but not designate any National Interest Electric Transmission Corridors (NIETCs) ― areas where transmission constraints and congestion could be improved with federal funding and accelerated permitting. (See What Are National Interest Transmission Corridors and Why Do We Need Them?)

DOE issued a request for information on the process for designating NIETCs in May and, as with the Needs Study draft, received a range of comments. In her opening remarks at the Nov. 8 webinar, GDO Director Maria Robinson said further guidance on NIETC designation would be released by the end of the year. (See States, RTOs Caution DOE on Transmission Corridors.)

Separate from NIETCs, DOE sees the Needs Study as a resource that can be used to encourage entities “to revise their planning processes to incorporate these findings, including consideration of a wider range of transmission benefits [and] portfolios of transmission project evaluation, rather than individual project evaluation,” Schneider said.

Broader planning perspectives also might include “scenario-based planning with longer time horizons to incorporate alternative transmission solutions including grid-enhancing technologies, as well as weather data [that] better reflect future extremes,” he said.

The need to explain the study’s goals and how it should and shouldn’t be used was raised by a number of the 58 groups and individuals who submitted a total of 330 comments on the draft Needs Study. The comments were summarized, with the department’s responses, in an 80-page appendix to the final.

The range of comments and the resulting revisions made to the final study reflect the complexities of grid planning as the U.S. generation mix moves toward cleaner, renewable resources.

“I think it does send a clear message,” said Rob Gramlich, president of industry consultant Grid Strategies. “It’s a well-done and thorough report citing many dozens of studies. So, I think, as a pure piece of analysis and information, it makes a very strong case. And it is from the Department of Energy, with the authority that entails … and is supported by all the national labs, so that gives it a lot more credibility than just a report.”

The study’s topline findings were no surprise, as Energy Secretary Jennifer Granholm said in a press call preceding the release. “We need to seriously build out transmission in order to improve reliability and resilience, and of course, to lower energy costs and relieve congestion on the grid.”

The study also finds “that of all the different configurations of transmission deployment, interregional transmission results in the largest benefits,” Schneider added during the Nov. 8 webinar, with the caveat that “transmission needs will shift over time.”

The Comments

The report’s broad and general approach — and the department’s insistence on not providing solutions — left some commenters dissatisfied. Utilities, RTOs and transmission developers all argued the report omitted projects and circumstances specific to their transmission planning and operations.

New York Transmission Owners (NYTO), a utility stakeholder group in NYISO, said the report should include four of its latest projects, which are aimed at alleviating price differentials between New York City and upstate areas, an issue raised in the draft.

PJM staunchly defended its performance during the winter storm of February 2021, commonly referred to as Winter Storm Uri, noting it provided “unprecedented amounts of power” to neighboring regions and that any limits in interregional transfers were due to “constraints in neighboring systems.”

ERCOT, on the other hand, urged DOE to treat the effects of Uri as outliers, asserting the report’s call for more interregional transmission to connect Texas to surrounding areas is overstated, given system upgrades it has undertaken since the storm.

DOE’s decision to base the report on existing studies, rather than fresh research ― and the resulting underlying assumptions ― was another flashpoint. While the draft referenced more than 50 reports, DOE was deluged with recommendations for other studies to be included, resulting in the final version reviewing and citing more than 100 reports.

Given the study’s strong focus on interregional transmission, the National Renewable Energy Laboratory’s Interconnections Seam Study ― which looked at the benefits of interregional connections ― was one of the more surprising omissions from the draft, but it was included in the final. Other additions include MISO’s Long-Range Transmission Planning Process and CAISO’s 2022-2023 Transmission Plan.

A lack of up-to-date information on transmission needs on tribal lands was another gap in the draft, according to comments from the Blue Lake Rancheria Tribe, in Northern California. In this case, DOE tapped a still-unpublished survey on tribal access to reliable electricity, which found an estimated 54,000 Native Americans, including Alaska Natives, live without electricity, the majority of them in the Navajo and Hopi nations.

Of those surveyed, 23% do not have access to a centralized power grid, and 65% said existing grid infrastructure could be extended to tribal lands, the report said in a new section on tribal transmission needs.

Multiple commenters also took issue with DOE’s base case for anticipating and modeling future transmission needs, predicting high levels of renewable energy coming onto the grid, but only moderate load growth. Consolidated Edison pointed to the potential effect on demand spurred by New York’s Climate Leadership and Community Protection Act as an example of ambitious state legislation that could drive load growth.

The law calls for New York to cut its greenhouse gas emissions 85% by 2050, with an interim goal of a 40% reduction by 2030.

Advocacy nonprofits similarly called for DOE to factor in the effect on renewable energy and load growth of the Inflation Reduction Act’s clean energy incentives and EPA’s vehicle emission standards, which are expected to accelerate adoption of electric vehicles.

The Edison Electric Institute (EEI) and Public Service Enterprise Group (PSEG) faulted DOE for not taking into account FERC’s proposed rules on transmission planning and cost allocation. According to the Needs Study, EEI argued the proposed reforms “will encourage efficient, cost-effective transmission investment.”

DOE responded to EEI and PSEG by noting the Needs Study is focused on the physical limitations of the transmission system, “not jurisdictional or regulatory limitations.” FERC rulemaking, therefore, is deemed “out of scope,” DOE said. The department does acknowledge the likely effect of state and federal law, adding modeling of high renewable, high load growth scenarios to the final report.

For example, the study shows the Plains region (roughly corresponding with SPP) would need up to 119% more regional transmission under a moderate load growth, high renewable scenario, but possibly over 400% more in a high load growth, high renewable case.

The Impact

As originally authorized in 2005 amendments to the Federal Power Act, the Transmission Needs Study was called the Transmission Congestion Study, looking only at congestion on the grid. But the Infrastructure Investment and Jobs Act (IIJA) expanded the scope of the report to encompass future needs as well as congestion.

As the first such report, the Needs Study was released as part of a series of DOE announcements of new transmission programs funded by the IIJA, highlighting the department’s role as a catalyst for transmission expansion. DOE is using $1.3 billion in IIJA funds to sign on as an anchor off-taker for three interstate transmission projects, chosen in part based on regional analyses in the Needs Study. (See DOE to Sign up as Off-taker for 3 Transmission Projects.)

DOE also recently awarded $3.46 billion in IIJA funds to 58 grid improvement projects, with the largest award, $464 million, going to five transmission lines in MISO and SPP’s joint targeted interconnection queue (JTIQ) portfolio. Reflecting the Needs Study’s call for a portfolio approach to grid planning, the projects are aimed at improving interregional connections and transfers along the MISO-SPP seams. (See DOE Announces $3.46B for Grid Resilience, Improvement Projects.)

The report’s effect outside the department seems more uncertain, especially given the strong regional and local bias in the comments.

On the one hand, the study’s regional profiles are one of its strong points, laying out where more regional and interregional transmission could improve resilience and bring low-cost renewable power to urban and other areas with high electricity rates.

The study’s approach here is aligned with how RTO grid planning appears to be evolving toward the portfolio approach DOE advocates, as seen in the MISO-SPP JTIQ projects and PJM’s Regional Transmission Expansion Plan Window 3 solicitation. That initiative resulted in PJM recommending a range of projects to expand its system for new renewable generation as fossil fuel plants retire. (See PJM Recommends $5B in RTEP Transmission Projects.)

But the study also notes the majority of transmission projects that have been built in recent years are smaller lines aimed at improving local reliability. The proportion of overall transmission installed to address system reliability needs has grown from 44% in 2011 to 74% in 2020. Interregional projects that can provide multiple benefits beyond reliability ― such as getting more cheap, renewable power online ― still face formidable obstacles, including permitting and financing.

Gramlich sees the report as one piece of an incremental process ― including DOE funding, NIETC designation and FERC rulemaking ― that could drive change in transmission planning, permitting and construction.

“The report could encourage state and federal regulators to get busy … with interregional [transmission],” he said. “It can also encourage private developers ― utilities or independent developers ― to work on lines. … I would think developers building in the transmission [regions] that were highlighted in the report would get a boost with all of the stakeholders and all the utility off-takers or other subscribers to transmission lines. I would think this report would be meaningful for them to encourage their participation.”