FARMINGTON, Pa. — The Mid-Atlantic Conference of Regulatory Utilities Commissioners’ (MACRUC) 28th Annual Education Conference last week at the Nemacolin Woodlands Resort focused on interregional transmission planning, resource adequacy and the risks posed by extreme weather.

Panelists on June 27 discussed the resource adequacy concerns PJM outlined in its “Energy Transition in PJM” white paper released in February. (See PJM Board Initiates Fast-track Process to Address Reliability.)

PJM Vice President of State Policy Asim Haque said the analysis found concerns around the balance between generator deactivations and new entries. As it considers how to address those challenges, he said PJM must balance the interests of member states and regions with diverse priorities.

“I do think that this is overarchingly an engineering problem that we all need to try to collectively solve together,” he said.

Glen Thomas, president of the PJM Power Providers (P3) Group, said that when the Reliability Pricing Model (RPM) was adopted, there was an expectation that the value of capacity would clear at the cost of new entry (CONE), which is currently about $300/MWh. Recent auctions, however, have been clearing much lower, which he said sends a signal for generation to retire.

That has resulted in few new resources being built and generators deactivating, including the 2.2-GW Homer City coal generator in Pennsylvania shuttering this month, Thomas said. He argued that the dynamic has contributed to a decline in reserve margins over the past several years, from above 20% to falling into the single digits.

“You should not be sending a retirement signal knowing what we know now,” he said.

Thomas said improving the outlook for reliability will require revising how PJM accredits resources to ensure the amount of capacity they are able to offer is accurate to their reliability contribution and reworking the market seller offer cap (MSOC) to allow generators to represent their full risk as a capacity resource.

Haque said there has been agreement that the current clearing price is not sending appropriate price signals. PJM’s Board of Managers initiated the Critical Issue Fast Path (CIFP) process to solicit stakeholder proposals to overhaul the capacity market, with the goal of submitting a proposal to FERC in October. (See PJM Continues CIFP Discussion of Seasonal Capacity Market Proposal.)

“The goal should not be to increase prices; that should not be the goal of any market construct. The goal as we see it should be to continue to provide resource adequacy” while keeping costs effective for consumers, Haque said.

Ohio Public Utilities Commissioner Dan Conway said decarbonization is an important focus of his job, but maintaining reliability is his “first and last.” As thermal resources, especially coal-fired, have retired, he said the new resources coming online lack the same reliability attributes and present a looming risk of more regular curtailments and shortfalls.

He said he believes the competitive model formed by PJM offers the best path forward, saying that neighboring MISO is largely vertically integrated and is closer to the edge than PJM.

Vistra CEO Jim Burke said the thinking around renewable resources has shifted from a technology supplementing existing thermal resources to displacing them. As that transition continues, he said far more nameplate generation will need to be developed to replace the same amount of capacity, owing to renewables’ lower accreditation.

“The scale of this is one of the biggest things that I’d just like to emphasize. We’re nowhere near a one-to-one trade,” he said.

While much of the discussion in PJM has been on the pace of new development, Burke said ERCOT has seen a large amount of investment over the past 20 years but continues to have reliability concerns during peak loads, noting that Texas was experiencing a heat wave straining the grid as the conference was ongoing.

“We’re $100 billion in, and we’re still checking the app everyday,” he said, referring to ERCOT’s mobile dashboard.

Interregional Transmission Spotlighted

During a June 26 panel on interregional transmission planning, discussion centered on how new transmission buildout — especially between RTOs — could address growing risks from extreme weather.

The Brattle Group’s Joe DeLosa III said the company’s analysis has found that additional transmission could have provided about $1 billion in value during the December 2022 winter storm — also known as Winter Storm Elliott — paying itself in just the four days of the storm. Despite the benefits, he said new lines largely aren’t being built in part because the multidriver approach doesn’t capture independent transmission needs, and the sequencing of how needs are considered creates a patchwork of regional projects.

Resolving cost allocation disputes poses a challenge to transmission development, but DeLosa pointed to MISO’s planning process as a success in realizing benefits that are greater than the costs. For it to work in the Mid-Atlantic, he said close collaboration will be needed between states, RTOs and FERC.

Jeff Dennis, deputy director for transmission at the U.S. Department of Energy’s Grid Deployment Office (GDO), said his staff are focused on exploring improvements that can be made beyond the RTO-level, such as siting, permitting and other processes that can be streamlined to get transmission built without compromising on environmental justice communities.

In a study the GDO plans to release this fall, investment trends and wholesale price differentials were used to identify constraints, with preliminary results suggesting that new transmission would provide significant value when storms are stressing the grid.

Looking at scenarios with high clean energy penetration and high load growth, the study’s preliminary results find that there is significant need for interregional capacity transfer capability, particularly between the Midwest and Mid-Atlantic. As much as double the current transfer capability could be needed, as well as additional interchange between the Mid-Atlantic and Southeast.

Barbara Tyran, of the American Council on Renewable Energy, said much of the U.S.’ solar and wind potential lies between the Mississippi River and the Rocky Mountains, but only a fraction of it could currently be connected with load centers on the coasts with existing transmission.

FERC’s Jessica Cockrell said cost allocation has to balance planning and the needs of merchant generation to avoid eroding the value of projects. When considering how capacity transfer can be mandated between regions, she said that operational agreements can be reached to determine the share of capability on each line that can be used to flow power from one RTO to another.

David Townley, director of public policy for CTC Global, said grid-enhancing technologies such as reconductoring, dynamic line ratings, fast power flow controllers and energy storage can be used to get more out of existing infrastructure without needing to get new developments through the siting and permitting processes. One of the challenges with installing those technologies is a lack of understanding among utilities in how they can be used, he said.

Utility Executives Discuss Extreme Weather Impacts

Executives from some of the largest utilities in the Mid-Atlantic discussed how extreme weather could impact their operations, as well as how differing policies across the states in which they operate interact together and with federal law.

Dominion CEO Robert Blue said the company was able to maintain service throughout its PJM footprint during Elliott, but it implemented load shedding in other regions. That experience has led it to consider adding LNG storage to some of its large gas-fired generators to address some of the fuel security issues seen during the storm.

Exelon CEO Calvin Butler Jr. said the number of severe weather events has tripled in its region, especially microbursts that come in with minimal warning and put tens of thousands of customers without power. He said improvements in communications have reduced response times, and drones are now being used to detect obstacles that could prevent crews from using a route to access a repair site, aiding in sending the right equipment to where it’s needed.

“What we are finding is the storm forecasts are less and less predictable,” he said.

John Crockett III, president of LG&E and KU Energy, said wind storms are also posing an increasing challenge. High winds during Elliott contributed to three hours of load shedding, along with issues with an interstate pipeline causing some gas generation to be unavailable. A storm in early March brought wind speeds exceeding 60 mph and left around 400,000 customers without power.

Butler said Exelon’s decision to shift to multiyear planning in some states has allowed greater transparency and collaboration, with more detail than annual rate cases. The intervenor process is also changed with multiyear plans, allowing discussion of how rates interact with the policy goals of a state or intervenor.

While the federal government has made billions available to promote its climate and reliability goals, Butler said its actions haven’t always matched its ambitions. Both there and at the state level, legislation is interacting with decades-old regulatory frameworks, which he said can sometimes impede policy goals.

Lightning Round Discussions on Key Issues

During a series of lightning round discussions, several speakers shared their thoughts on the potential of green hydrogen, congressional bills addressing permitting authority, how investors view the state of the energy markets, and an upcoming report on coordination between the gas and energy industries being written by the North American Energy Standards Board (NAESB).

Bank of America’s Julien Dumoulin-Smith said investors are expecting costs for wholesale energy, interconnection and new generation — particularly offshore wind — to generally rise in the PJM region over the coming years.

He predicted that there will continue to be ample capital available for new developments, but the cost of capital is likely to rise with interest rates. Offshore wind installation costs, for example, could double because of interest rates, while concerns linger about whether the ships and logistics required to put the turbines in place are sufficient for looming projects.

“There’s clearly capital available in both debt and equity capital markets, and I think you’re going to see a lot of traditional equity getting raised in lieu of debt in this environment,” he said.

With rising interconnection costs and a growing gap in the valuation between clean and thermal assets, he said some resources are now worth just the value of their interconnection, reducing their prospects for continued operations.

“In this day and age, I don’t think you’re going to see a lot of tolerance if there are operational issues. If you see other issues on gas plants today, you’re going to see people favoring to take them out,” he said.

Constellation Discusses Hydrogen Development

Constellation Energy Executive Vice President Kathleen Barron said hydrogen offers a potential solution to several areas of the economy that have proved challenging to decarbonize, but remains uneconomical for the time being.

“We have proven technology; we know how to do this; companies are actually already doing this at one of our sites in New York, using nuclear energy to make hydrogen using electrolysis,” she said. (See related story, Constellation Gives Details on First-in-nation Pink Hydrogen Production.) “The problem is the cost of doing that is about three to four times what a customer is going to be willing to pay to use hydrogen as a substitute for natural gas.”

Barron said the Infrastructure Investment and Jobs Act provides funding for hydrogen hubs to jumpstart the production and transportation infrastructure necessary for mass industrial use of hydrogen, but the “additionality” clause in the law could pose a roadblock. The clause requires that only new clean energy can be used to power the electrolyzers, but she said it would require a doubling of the amount of renewable power currently available and to use that energy only to produce hydrogen.

“We’d need to double the size of today’s renewable grid and use it only to make hydrogen — not use it satisfy state [renewable portfolio standard] programs or to satisfy the EPA rules that are coming. … If we really want to try to tackle emissions in other sectors, and we want to use hydrogen, we’re going to need to use” existing generation, she said.

Nuclear makes hydrogen cost-effective because of its steady supply of power and the existing transportation infrastructure that tends to be in place at those facilities,” Barron said. Nuclear plants also tend to be further from population centers and have land available around them, raising the possibility of placing electrolyzers behind generators’ interconnection meters, a configuration the company has been proposing through the PJM stakeholder process. (See “Discussion Continues on Capacity Offers for Generators with Co-located Load,” PJM MIC Briefs: June 7, 2023.)

NextEra Evaluating Hydrogen Uses

NextEra Energy Resources Vice President of Development Ross Groffman also spoke about how green hydrogen could be used for industrial decarbonization. Some of the initial uses the company is developing projects for are green ammonia production to create agricultural fertilizer and liquid hydrogen as fuel for long-haul trucks and buses.

Hydrogen could also be used in steel and chemical production or blended into the fuel for natural gas generators, he said.

Intermittent resources sited alongside hydrogen could also be used for energy production when generation exceeds the amount of power the electrolyzers consume. Using hydrogen to fuel combustion turbines will play a central role in the future of decarbonizing the grid, Groffman predicted, and the NextEra is already investing in projects to explore technologies.

“It’s an important part of the long-term view of how some of these plants will run. It’s not going to happen in the next year or two; this is longer term, but it will be a key part of how the long-term green grid will perform,” he said.

Congress Considering Siting and Permitting Legislation

Christina Hayes, executive director of Americans for a Clean Energy Grid, shared her views on a slate of bills being considered by Congress that would address how the federal government interacts with siting and permitting of energy infrastructure. Some of the proposed legislation would offer transmission tax credits “as a kind of hook to getting siting and permitting handled more broadly.”

Hayes said there’s also a growing recognition of the need to incorporate community benefits and other impacts on where projects would be developed, both for pipelines and transmission.

With renewable standards now widespread not only among states, but also utilities and corporations, she said many are coming around to the need for more transmission to be built.

When considering the impact to their ratepayers, she said regulators could be more thoughtful when considering approval of transmission projects that would benefit other states, saying those could be viewed as an “insurance policy” for their future reliability.

NAESB Drafting Recommendations on Gas-Electric Coordination

Robert Gee, co-chair of NAESB’s Gas-Electric Harmonization Forum, gave an update on the recommendations being drafted with the aim of improving the coordination between the two industries. He encouraged all interested parties to either submit written comments or participate in the meetings, of which there have already been a dozen.

There are both operational and structural issues that impact the ability for gas generators to procure fuel during emergency conditions, Gee said, leading NAESB to consider creating a commercial standard or emergency protocols.

“Generators are not able to access gas during critical peak periods for a number of reasons. One is that they don’t have firm contracts, generally for economic reasons. Second, there’s inadequate information regarding available pipeline capacity and little to no transparency on certain parts of the system,” he said.

Gee reviewed a handful of the 17 recommendations that the forum is currently considering, which include increasing the transparency and communication around the status of interstate pipelines, ensuring that gas markets are fully functioning around the clock to allow generators to prepare for peak demand during emergency periods, and synchronizing the gas and electric markets to align the electric industry’s day-ahead procurement schedule with how generators procure fuel.

The forum is also considering recommending re-evaluation of whether out-of-market solutions are needed.

“We rely on competitive markets to basically give us the ability and tools to address this issue of trying to access gas during critical peak periods. We think it’s time to reconsider out-of-market solutions; weigh them carefully; see whether they work; see what they offer solutions to,” he said.

Gee said thought also is being given to recommending that two studies be commissioned by FERC and NERC to look at whether markets currently offer proper incentives for generators to procure firm fuel contracts during emergency conditions and to develop more gas storage infrastructure.