Search
`
November 16, 2024

Posted on

Report Quantifies OSW Supply Chain Constraints

The offshore wind sector will need a $100 billion supply chain investment to meet the 2030 targets that policymakers have set, a new analysis finds.

Wood Mackenzie’s report issued this month, “Cross Currents: Charting a Sustainable Course for Offshore Wind,” explores the disconnect between the desire to build offshore wind and the ability to manufacture the components. It compares a baseline increase in generation capacity of up to 30 GW per year with policymakers’ goals of up to 77 GW per year. To accomplish this, much more money must be plowed into the supply chain: $27 billion by 2026, and more than $100 billion by 2030, the report finds.

This bumps up against investor hesitation because of low margins and uncertainty of project timing in the offshore wind sector, the authors say.

Suggested solutions include extending the planning process beyond 2030, building better supplier-develop partnerships and capping turbine size to pause manufacturers’ race to build ever-larger machinery.

The report finds this “arms race” is particularly damaging, shortening the timeframe to recover investments and recoup research-and-development costs, increasing the cost of installation and repairs and rendering expensive equipment and facilities obsolete if they can handle a 12-MW turbine but not its 15-MW successor or the 18-MW prototype under development.

It also notes that 24 GW of projects scheduled to come online in 2025-2027 have secured a subsidy or power purchase agreement but have not made a final investment decision. Multiple projects are delayed worldwide as they seek to renegotiate offtake contracts to reflect their rising costs.

Delays, Constraints

Chris Seiple, vice chair of power and renewables at Wood Mackenzie and co-author of the report, said governments’ commitment to offshore wind is clear but the supply chain will be an impediment to achieving their targets.

“Nearly 80 GW of annual installations to meet all government targets is not realistic,” Seiple said in a news release. “Even achieving our forecasted 30 GW in additions will prove unrealistic if there isn’t immediate investment in the supply chain.”

Another factor, Seiple said, was an oversupply that followed a supply chain buildout a decade ago, depressing profitability.

“Burned once, current suppliers are cautious in their investment plans, and the lack of profitability is hampering their ability to fund manufacturing capacity expansion — ultimately stalling innovation in the sector.”

Given the decade-plus time needed to realize a return on investment, there is hesitation by manufacturers to supercharge a buildout that peaks in 2030 and then subsides. To counter this, the authors suggest not setting the 2030 goal too high and creating a clear post-2030 road map.

The report excludes one major player in the offshore sector — China — because it relies largely on a domestic supply chain and because that supply chain largely has not extended abroad. But that could change as Chinese companies look to expand their markets, the authors note.

2026 Estimates

The report’s estimated need for $27 billion in investments by 2026 is closely focused — not on a full supply chain buildout, just what is required for installation, foundations, towers, blades and nacelles. None of this can come from the onshore wind supply chain, they noted, because of the size differential.

Installation of equipment offshore is the largest gap, the report finds, because half of the fleet of ships is too small to handle the next generation of supersize turbines. More than 20 new vessels are needed, at an estimated cost of $13 billion.

Foundations — massive steel tubes driven into the seabed — are needed in greater number and larger size. But scaling up manufacturing capacity is more challenging than with other components because of their sheer bulk, and because of the customization needed for individual sites.

The towers that stand on the foundations are getting larger and more complicated as the turbines that sit on top of them grow more powerful, rendering some factories obsolete. Many plans have been announced to expand them or build new ones, but only a third have reached a final investment decision.

Nacelles are the bright spot in the report, deemed the least likely to become a supply chain bottleneck because of the firm commitment manufacturers have made to expanding production capacity. The sticking point might be coordinating expansion of the suppliers of all the components of a typical nacelle.

Blade manufacturing requires ongoing investment because of demand growth and retooling to produce longer blades. Manufacturers are sustaining losses or limited profit as a result and have committed to only a fraction of the $4 billion investment needed in new factories, which typically have a three- to five-year lead time.

The authors also note that the supply chain has become highly concentrated in the past decade — to the point that the top three manufacturers of foundations, towers, blades and nacelles account for 67%, 70%, 93% and 96% of their markets, respectively. This allows them greater influence on pricing and timing in their industries.

Posted on

SPP Sets New Summer Peak as Great Plains Roast

SPP set a new record for summer peak demand Monday, the first of several that could come this week with a heat dome settled over the Great Plains.

The grid operator, which serves a 14-state footprint in the middle of the country, registered a peak demand of 56.18 GW at 4:27 p.m. (CT). That broke the previous mark of 53.24 GW set last summer by nearly 6%.

The record came as SPP was operating under a conservative operations advisory, declared because of the extreme heat, high load forecast and low wind forecast. The RTO issued another conservative operations advisory Tuesday. It also remained under previously declared resource and weather advisories; both have been extended until 8 p.m. Friday.

None of the advisories require public conservation and have been issued to raise awareness of potential reliability threats.

“It’s possible we may set another record,” SPP spokesperson Meghan Sever said in an email. “Stay tuned.”

Demand within the footprint hit 54.63 GW Tuesday afternoon, according to GridStatus.

About 143 million people in the country’s heartland were under heat alerts Tuesday. The National Weather Service is expecting high-temperature records to fall throughout the week, as the oppressive heat continues into next week.

Sitting almost squarely under the heat dome, parts of Kansas are under an excessive heat warning through Friday. Lawrence saw a heat index of 134 degrees Fahrenheit Sunday and Topeka broke an unofficial record at 127. Other cities in the region have seen, and will continue to see, heat indices approaching 120 degrees.

Sever says SPP expects to have enough generating capacity to meet the demand and its assessments don’t raise reliability concerns. The RTO’s summer reliability assessment indicated a 99.5% probability the system will have sufficient capacity to meet demand.

C.J. Brown, SPP’s director of system operations, said during a recent stakeholder meeting that the alerts and advisories are becoming regular.

“That’s been really challenging. Thankfully, we’ve had good renewable resource penetrations [on peak days],” he said. “We’ve teetered on [energy emergency alert 1] where it’s been really close, and a small contingency might have put us there, but we were able to make it through. That’s what I’m really calling the new normal.”

Tropical Storm Offers Relief to Texas

Tropical Storm Harold gave Texas a bit of a reprieve with rain in the south and cloud cover elsewhere. Average hourly demand failed to reach 80 GW for only the second time since July 29.

Austin had a 45-day streak of 100-plus temperatures broken when the thermometer only reached 99 degrees. However, Dallas extended its streak of 100-plus days to 41 Tuesday after having set an all-time high of 109 last week.

The cooler weather will be short-lived. ERCOT is projecting demand to once again approach record levels through Thursday.

The ISO did set another weekend peak demand mark Sunday at 85.12 GW, not far from the system’s all-time high of 85.44 GW. The ISO was forced to call for voluntary conservation when a large thermal unit went offline.

Posted on

Grid-enhancing Technologies Poised for Growth with Federal Funds

Grid-enhancing technologies (GETs) already have worked in some areas, and they are set to grow with new federal funding opportunities, experts said on a webinar Tuesday hosted by the Clean Energy States Alliance.

PPL had been looking into using dynamic line ratings (DLRs) since 2020, and it went live with several projects starting last October, including one that has expanded the capacity of its Juniata-Cumberland line in Pennsylvania by 18% under normal conditions and 10% under emergency conditions, said Joseph Lookup, director of asset management.

DLRs consider local conditions such as the ambient air temperature, wind speed, the temperature of the conductor and how much the line is sagging to determine how much power can reliably flow through a transmission line. The sensors used in the technology also can measure the health of the conductor.

Upgrading transmission lines is a costly and complex engineering process, but getting DLRs running was fairly easy, Lookup said. It involved installing sensors on the lines, which takes a couple of days, and building out the information technology system needed to bring the data produced back to PPL and PJM’s transmission operators, he said.

“Since we went live in October 2022, we are seeing an average increase … for the normal and the emergency readings,” Lookup said. “And by doing this, it really has hit home with the customers by saving them costs for congestion … that we were able to avoid by making a bigger pipe for the power to flow through.”

PPL’s proposal to use DLRs won out in the market efficiency window of PJM’s planning process as a cost-effective way of improving the grid. The projects were estimated to save consumers $23 million annually by the RTO, but so far, grid conditions have made it so the savings exceed that estimate, Lookup said.

The New York Energy Research and Development Authority (NYSERDA) has been looking into GETs in recent years to determine how much power it can push through its existing grid, said Senior Project Manager Mike Razanousky.

NYSERDA has been looking into DLRs as well, which can be accomplished using the sensors PPL has installed, but also with more remote approaches, such as using lidar to measure the conditions of a line, and installing weather stations. It also has looked into power flow controls such as phase angle regulators, which can change the flow of power to maximize the use of the existing grid, and storage as a transmission asset.

“When we started this work, we didn’t have FERC Order 881, which is now requiring all of us to go to [ambient-adjusted ratings (AARs)] by July of 2025,” Razanousky said.

AARs take into account only local air temperatures; Order 881 also opened a docket to study requiring DLRs around the country. (See FERC Orders End to Static Tx Line Ratings.) WATT Coalition Executive Director Julia Selker noted that the latter offers more efficient use of existing transmission because wind is a bigger factor in transmission lines’ ever-changing capacity than air temperature.

NYSERDA is working with Avangrid on the demonstration of a mobile unit that can measure its transmission system’s conditions, and Central Hudson Gas & Electric is installing a permanent system at a substation, Razanousky said.

Another option for helping increase efficiency on the grid is deploying storage as transmission assets; NYSERDA is working on a study that will look into the question, Razanousky added.

The Infrastructure Investment and Jobs Act included up to $14 billion over five years for states and utilities to try out all kinds of GETs, Selker said. The money can help bring the technologies from the pilot level to be used broadly across the entire country.

The grants are available for both states and the industry under various programs, and Selker said the Department of Energy should announce the first ones shortly.

“To put forward a grid-enhancing technologies proposal, you really have to partner with both a technology vendor and a utility to identify needs and impacts and what stage the utilities are at in adopting these technologies,” Selker said. “So, I really encourage you to do that groundwork; find out what’s feasible.”

The more recent Order 2023 on interconnection queues also requires consideration of GETs, she added. (See FERC Updates Interconnection Process with Order 2023.) While utilities will look at AARs under Order 881, Selker argued it makes sense for them to start considering the more efficient DLRs at the same time. Under Order 2023, utilities have full discretion on how to evaluate and implement the transmission technologies.

“It really looks like it’s down to the state oversight to make sure that the RTOs and the transmission owners are doing that meaningful evaluation of these technologies and fully incorporating them in the processes,” Selker said.

Posted on

NERC Confident in Ability to Deliver ITCS On Time

At NERC’s quarterly technical session last week in Ottawa, the ERO’s staff said they’re confident they can finish the congressionally mandated Interregional Transfer Capability Study (ITCS) despite the relatively tight time frame given by lawmakers.

NERC added the technical sessions to the schedule of events for its Board of Trustees and Member Representatives Committee meetings to host more in-depth discussions on topics of interest to the ERO. Last week’s session featured an extended discussion of the ITCS, which has caused considerable discussion among NERC and other stakeholders because of its effect on the ERO’s work plan and budget for 2023 and 2024. (See FERC Approves NERC Transfer Study Funding Request.)

Speakers at the technical session emphasized the importance of the study, which Congress mandated when it passed the Fiscal Responsibility Act in June and which must be submitted to FERC by December 2024. Mark Lauby, NERC’s senior vice president and chief engineer, called the work necessary preparation for the rapidly changing electric grid.

“It’s really a critical time to be looking at transfer capability, because as our system is now [evolving] to one that is much more energy-constrained and not capacity-driven, it’s very important for us to understand where the energy is and where it isn’t, and make sure we have an ability to get from where it is to areas that are [in] deficit,” Lauby said.

John Moura, NERC’s director of reliability assessment and performance analysis, said that while “another study … might not answer every single question that we have,” the ERO sees the ITCS “as an essential component to the energy transformation story arc” that the grid is undergoing. Moura said he saw “no better set of organizations suited to do this” than NERC and the regional entities, which represent an “independent and objective voice.”

A visualization of NERC’s conception of the study. | NERC

Study Comprises Three Tasks

Moura illustrated NERC staff’s approach to the study, and its three components mandated by Congress, with a simplified visualization presenting two systems: one with 200 MW of load and 120 MW of generation — representing a deficiency of 80 MW — and the other with 200 MW of load and 260 MW of generation, a 60-MW surplus.

Task 1, Moura explained, is to calculate the transfer capability between the two systems — in this theoretical case, one system can transfer 40 MW to the other over existing lines and the other can transfer 50 MW, which “isn’t sufficient in meeting what the [system] on the left’s load requirement is.” Therefore, the second task is to determine where deficiencies exist, and how much additional transfer capability would resolve the issues. Under the example presented, adding 30 MW of capability should address the deficiency.

The third task, which Moura called the most important, is to “evaluate what is needed to meet and maintain these transfer limits.” This means, for example, addressing the ability of the system on the right to deliver the 80 MW needed by the system on the left, when it only has a surplus of 60 MW.

“Generation is just as important to transfer capability as transmission,” Moura said. “It’s not all about stringing the wires; we’re going to need generation to support the transfer capability, so we’ll need to identify those needs as well.”

Industry Help Needed

While Congress’ mandate puts NERC “at the helm,” Moura said engagement across industry also will be required. So, the ERO will form the ITCS Advisory Group “in the coming weeks” to provide advice and input on the study scope, approach, results and recommendations. Moura called this group “the tip of the spear for stakeholder coordination,” and said it will review the final report and the recommendations, though the ERO Executive Leadership Group will be in overall control of the study.

Until recently the project was in what NERC staff called “Phase 0” — focused on defining the scope and assumptions, stakeholder engagement and preparing data requests — while awaiting FERC’s approval for its payment strategy, which required redirecting funds budgeted for 2023 and drawing from NERC’s financial reserves. The commission gave its assent on Aug. 10, and the study entered Phase 1, which consists of identifying generation deficient and surplus areas, performing transfer capability analysis and identifying thermal, voltage and stability limits.

NERC expects to prepare a draft of the final report by August 2024, with comments to be solicited from stakeholders over the following three months. While the final report will be submitted at the end of the year, the ERO expects to remain active providing support to FERC as it reviews the study, and in conducting further research and support as needed.

“This is not just to submit to FERC and do nothing. We’d like this to really mean something and for it to be a launchpad for policy and other developments that will occur,” Moura said. “There are benefits beyond the ITCS — substantial benefits — in gaining the expertise and capability to perform these studies.”

Posted on

BOEM Approves Revolution Wind off New England Coast

Revolution Wind on Tuesday became the fourth utility-scale U.S. offshore wind project to gain federal approval.

At full capacity, the facility south of the Rhode Island and Massachusetts coast will send 704 MW of power to Connecticut and Rhode Island.

Fabrication of components began this year. Developer Ørsted said in a news release Tuesday that the project remains on track for onshore construction activities to begin in coming weeks and for offshore construction to begin in earnest in 2024. It is targeting a 2025 operational date.

The record of decision issued Tuesday by the Bureau of Ocean Energy Management signals BOEM’s approval of the construction and operations plan.

The decision is being presented by the Department of Interior and the Biden administration as the green light for the project, but BOEM still must issue final approval of the plan. Additional state and federal authorizations are needed as well.

Ørsted said it anticipates receiving BOEM’s approval in November.

Tuesday’s announcement came just shy of 10 years after BOEM executed wind energy lease OCS-A 0486 with an entity called Deepwater Wind New England LLC.

It was later divided into two areas: South Fork Wind and Revolution Wind.

Among the cluster of wind energy areas being developed off the eastern tip of Long Island and the southeastern corner of New England, Revolution Wind will be one of the closest projects to land.

The plan approved by BOEM is a modified version that reduces the number of turbines erected in an attempt to reduce its visual profile and limit the impact on people and industries that use the ocean, such as fishers.

Revolution Wind has committed to compensate recreational and commercial fisheries for losses directly arising from the project.

Details

Revolution Wind is a joint venture of industry leader Ørsted and New England utility Eversource, which is looking to exit the partnership and exit offshore wind development all together.

In a news release Tuesday, the pair touted the economic impact Revolution Wind already has had, even before gaining approval, including: investment of $100 million to help redevelop the State Pier in New London, Conn.; creation of a regional offshore wind component fabrication facility in ProvPort, R.I.; commissioning five vessels at local shipyards; and contributions to multiple career-development programs.

BOEM’s parent agency, the Department of the Interior, said construction of Revolution Wind is expected to create about 1,200 local jobs.

Some of the new shoreline infrastructure already is in use as Ørsted and Eversource build the 132 MW South Fork Wind, which is expected to begin commercial operations before the end of this year.

South Fork gained a critical advantage by being in the forefront of U.S. offshore wind development.

Other projects that are not as far along in the yearslong planning-review-permitting process have been clobbered by soaring material costs and interest rates in the past two years.

Ørsted and Eversource have told New York state they need more money to proceed with Sunrise Wind 1, for example.

New York, in turn, invited them to rebid Sunrise 2 into the most recent solicitation at a lower cost, before the state makes final contract decisions.

The two partners also saw their 884 MW Revolution Wind 2 proposal rejected as too expensive in Rhode Island.

And Ørsted sought and received more money from New Jersey for Ocean Wind 1, a project it is pursuing solo. It became the third offshore wind plan greenlighted by BOEM, last month.

Other developers are citing the same problems with their projects along the Northeast coast, suggesting the first major buildout of offshore wind in the Americas will be slower and/or more expensive for ratepayers than initially projected.

Commentary

Tuesday’s decision was hailed as a milestone and landmark.

Offshore wind has been a priority for President Biden, who has set a goal of 30 GW by 2030. BOEM said in a news release that Tuesday’s approval of Revolution Wind puts the agency on track to complete review of 16 projects with more than 27 GW of nameplate capacity by 2025.

“Today’s approval is not the end of our work on this project. We will continue to maintain open communication and frequent collaboration with federal partners, tribal nations, states, industry and ocean users to address potential challenges to and identify opportunities for the continued success of the U.S. offshore wind industry,” said U.S. Interior Secretary Deb Haaland.

“As the first offshore wind project solicited by Connecticut, we are particularly pleased to see Revolution Wind receive final approval from BOEM, clearing the way for the project to fulfill its promise of delivering clean energy, providing good jobs and enhancing local economies,” said Charles Rothenberger of New England for Offshore Wind.

“The U.S. offshore wind industry is on the move,” said Liz Burdock, CEO of the Business Network for Offshore Wind. “The steady stream of offshore wind project environmental reviews is critical to the success of supply chain investments, and today’s announcement bolsters investments in component production at ProvPort in Rhode Island, cable manufacturing in South Carolina, steel fabrication in western New York, and shipbuilding in Texas and Louisiana.”

“The Revolution Wind project will play a significant role in advancing the state’s Act on Climate law, growing our clean energy economy and achieving our 100% renewable energy standard objectives,” said Rhode Island Gov. Dan McKee.

“With the federal record of decision, we now advance Revolution Wind to the construction phase, bringing good-paying jobs to hundreds of local union construction workers, keeping local ports busy with assembly and marshaling activities and further growing the local supply chain,” said David Hardy, CEO Americas at Ørsted.

“The extreme weather we’ve experienced this summer underscores the growing dangers and devastating effects of global warming, as well as the need for bold solutions to address the climate crisis,” said Connecticut Gov. Ned Lamont (D).

Posted on

FERC Sides with Wind Developer vs. NorthWestern

FERC on Monday granted in part, and dismissed in part, Ponderosa Power’s complaint that NorthWestern Corp.’s proposal to assign roughly $30 million in network upgrade costs to the wind farm developer violates NorthWestern’s tariff and the commission’s “but for” cost allocation policy (EL23-48).

The agency agreed with Ponderosa that NorthWestern’s assignment of the disputed upgrade costs in an optional study that applied a rounding policy is contrary to FERC’s “but for” policy and violated the utility’s tariff. FERC dismissed the remainder of Ponderosa’s complaint as moot because it found for Ponderosa on the issue. It also declined the developer’s request to investigate NorthWestern’s interconnection queue practices, saying the record doesn’t warrant such a review.

NorthWestern’s modeling software represents thermal violations in decimal numbers with values to the hundredth decimal point. As a result, loading values between 99.5% and 99.99% are rounded up to 100%, FERC said, which NorthWestern deems to be a thermal violation requiring network upgrades.

Ponderosa is developing a 70-MW wind-powered generation facility that would be interconnected to NorthWestern’s transmission system in Montana. It filed a Section 206 complaint under the Federal Power Act in March after studies determined Ponderosa would have to pay the upgrade costs.

The commission found that the optional study results did not demonstrate that the disputed upgrades are required for Ponderosa’s project. It said the project’s loading value of 99.65% on one line segment did not trigger a thermal overload under the “but for” policy.

FERC said NorthWestern treats the rounding policy “as a practice that is part of its study process” but said it should be more “correctly viewed” as an after-the-fact change that materially modifies and “effectively departs from” the underlying study results.

“The rounding policy’s clear effect here is to deem the disputed upgrades to be ‘required’ for Ponderosa’s interconnection, notwithstanding that the optional study results otherwise establish that they are not,” the commissioners wrote.

FERC directed NorthWestern to issue Ponderosa within 30 days a revised optional study that removes the disputed upgrades and associated requirements and provides an updated estimate of its network upgrade costs, as the developer requested.

Posted on

DOE Wants US to Produce 50 Million MT of Clean Hydrogen by 2050

The White House and Department of Energy on Friday unveiled a new interagency task force aimed at reaching the administration’s ambitious goals for the deployment of clean hydrogen to decarbonize a range of hard-to-abate industrial and transportation sectors, from steel production to heavy-duty trucking and aviation.

The Hydrogen Interagency Task Force (HIT) “will be designed to … fully leverage the strengths and capabilities of the U.S. government to develop technologies, implement policy and overcome barriers to building a clean hydrogen economy,” said Mary Frances Repko, White House deputy national climate advisor, during a Friday webinar.

The task force will include representatives from 11 federal agencies, including EPA and the departments of Transportation, Labor, Interior, Agriculture and Commerce. Repko will co-chair the group with DOE Deputy Secretary David Turk, who laid out the administration’s timetable for clean hydrogen deployment.

The U.S. currently produces about 10 million metric tons (MT) of hydrogen a year, most of which “comes from fossil fuel sources without carbon capture,” Turk said. “By 2030, we want to produce the same amount of hydrogen, but we want to do it with clean hydrogen. … By 2040, we want to double that … from 10 million MT to 20 million MT, and by 2050, we want to go to 50 million.”

Deployments of clean hydrogen to decarbonize industry, transportation, and the power grid can enable 10 MMT/year of demand by 2030, ~20 MMT/year of demand by 2040, and ~50 MMT in 2050. | DOE

Reaching that goal would produce enough hydrogen to power all the buses, trains, planes and ships in the U.S., and could help the U.S. cut its greenhouse gas emissions by 20% by 2050, he said.

“So, this is not a nice-to-have,” Turk said. “This is not just a sideshow. This is part of the main event going forward.”

One of the core pillars of the agency’s strategy is building out a network of regional clean hydrogen hubs, with the first six to 10 funded with $7 billion from the Infrastructure Investment and Jobs Act (IIJA). Applications for the funding were due in April, and Todd Shrader, director of project management for DOE’s Office of Clean Energy Demonstrations, said the awards would be announced “in the fall.”

The purpose of the hubs is to co-locate commercial-scale production and end uses “to demonstrate different use cases from different feedstock diversity, meaning different power supplies,” Shrader said. Once DOE helps build the first six to 10 hubs, he said, “what that really does is [it] encourages and shows the lessons learned to industry to build plants 11 through 100.”

An analysis from Resources For the Future found that the applicants competing for the DOE money largely are multistate, private-public collaborations, with many planning to use renewable energy to produce clean hydrogen.

The National Clean Hydrogen Strategy and Roadmap, released in May, lays out three pillars for scaling clean hydrogen, beginning with zeroing in on high-impact end uses, such as heavy-duty transportation. The second is cutting costs so clean hydrogen is competitive with the fossil fuels used for other critical end uses, and the hubs are the third, said Sunita Satyapal, director of DOE’s Hydrogen and Fuel Cell Technologies Office,

DOE’s main initiative for cost cutting is the Hydrogen Shot, one of the agency’s Energy Earthshots, which all are aimed at reducing costs for new technologies needed to reduce U.S. greenhouse gas emissions. The goal for the Hydrogen Shot is to decrease the cost of clean hydrogen from about $5/kg to $1/kg within a decade.

Clean hydrogen is produced by using electrolyzers, powered by electricity, to split water into hydrogen and oxygen. The equipment is expensive and not yet produced at the scale needed for significant market growth.

But the lower the cost of clean hydrogen, the more sectors will open up to its use, Satyapal said. For example, getting the cost to $4/kg would make hydrogen competitive for heavy-duty trucking, she said.

“If we can get 10 to 15% of all the trucks using hydrogen fuel cells, that will enable 5 to 8 million MT of hydrogen in terms of demand,” she said.

Clean hydrogen at $2/kg could compete with biofuels, and at $1/kg, demand for clean hydrogen could grow in steel production, ammonia and energy storage, she said.

Production vs. End Use

Friday’s webinar and the announcement of the interagency task force seemed designed to fill the gap in concrete results on clean hydrogen as President Biden celebrated the first year of the Inflation Reduction Act (IRA). The law provides a production tax credit of up to $3/kg for clean hydrogen, which has been a draw for new investment.

While promoting administrative initiatives like the new taskforce, speakers at the webinar also acknowledged the challenges ahead, calling for an “all-of-industry” commitment to match Biden’s all-of-government strategy.

While passage of the IRA led to a doubling of announcements for new clean hydrogen projects in the U.S. by the beginning of 2023, more than half were for production versus about a third for end use, according to DOE. Projects in planning or under construction almost entirely are in hydrogen production, leaving the market decidedly lopsided.

“It doesn’t really do any good to have lots of production capacity if there’s not end-use capacity or an end user for the product itself,” Shrader said.

DOE recently announced $1 billion in IIJA funds to be dedicated to building demand for clean hydrogen, with the government possibly acting as a “market maker,” buying hydrogen from the hubs and selling it to others. (See DOE to Invest $1 Billion to Build Demand for Clean Hydrogen.)

Other obstacles cited in DOE’s recent Pathways to Commercial Liftoff: Clean Hydrogen report include a lack of “midstream infrastructure” — pipelines or other means of transport — for situations where hydrogen production and end use are not collocated, and the need for increased scaling of renewable energy.

Without adequate renewables — wind, solar and nuclear — the report predicts that fossil fuels with carbon capture and storage (CCS) could be used to produce up to 80% of clean hydrogen by 2050, as opposed to fossil fuels with CCS and renewables producing 50% each.

With utilities and other industries looking at mixing natural gas and hydrogen, pipeline safety also could be an ongoing concern. Mary McDaniel, of the Department of Transportation’s Pipeline and Hazardous Materials Safe Administration (PHMSA), said her agency has been tightening regulations on pipeline leak and rupture detection and mitigation.

“We have 1,500 miles [of pipelines] that are pure hydrogen at this point,” McDaniel said. “We’re going to be looking at hydrogen blending for pipelines as it gets more use in the pipeline line system; so, making sure that we have the infrastructure in place for that. Then we’ll be able to make any leak detection and response for those leaks.”

Posted on

NYISO: Software Upgrades for DER Participation to be Ready Next Month

NYISO told FERC on Thursday the software development and testing necessary to implement its distributed energy resource participation model will be ready by Sept. 1 (ER23-2040).

The ISO had requested an effective date of Dec. 15 for the revisions it had submitted in June, later than it thought necessary but proposed “out of an abundance of caution.”

“Prompt commission action will enable DER and aggregations to begin enrolling in the NYISO’s markets by the end of 2023,” the ISO said in response to FERC staff’s deficiency letter, which sought more information on the proposal. (See FERC Seeks More Info on NYISO DER Aggregation Proposal.)

FERC had approved NYISO’s participation model in 2020, but the ISO proposed modifications this year to better align the model with its new software and ease the burden on staff. Among those changes was a controversial 10-kW minimum for DERs in an aggregation to participate. The commission directed the ISO to explain how it had come to the 10-kW figure.

NYISO said it had become apparent that the new manual processes developed to enroll and track DER and aggregations “would be unmanageable with a high volume of DER penetration.” It said it analyzed enrollments in its existing Emergency Demand Response Program and Special Case Resource program as comparable proxies to the DER participation model. Of the 9,814 resources in the two programs as of July 1, 6,475 are less than 10 kW, it said. At a combined 7.3 MW, they represent just 0.58% of the programs’ total capability.

“NYISO does not currently have sufficient resources to timely and efficiently administer the monthly enrollment processes required for the DER and aggregation participation model if several thousand end-use customers seek to enroll in the markets at once,” the ISO wrote. “The costs associated with building the infrastructure to enable such participation include more staff, more software and the development of new market rules that will result in less oversight of small DER.”

FERC also asked NYISO to explain what it considers a DER “material modification,” address its proposed DER metering and telemetry requirements, justify why it will use the lowest cost DER as an aggregation’s reference level and explain why it would eliminate locational-based marginal pricing and bid-based reference levels for aggregations.

NYISO said a material modification constitutes “any change to the physical and operating characteristics of the DER” and included nearly 40 examples that would trigger a review, including a change of address, ownership or capability.

The ISO also responded that its metering rules ensure consistency among similar resources and do not give one participation model, whether aggregation or standalone, an undue advantage.

Additionally, NYISO justified its reference levels revisions by claiming the proposals will help the ISO better understand aggregation market and bidding behaviors, as the lowest-cost DER level incentivizes aggregations to be available more often, while switching to cost-based references will allow the ISO to better study relevant financial data.

Posted on

NCUC Approves Duke’s Performance-based Rates

The North Carolina Utilities Commission (NCUC) on Friday approved Duke Energy Progress’ latest rate case, which includes “performance-based regulation” meant to help achieve the state’s environmental policies.

Gov. Roy Cooper (D) signed HB 951 into law in October 2021, which required the utility to implement performance-based regulation. The law defined that as “an alternative rate-making approach that includes decoupling, one or more performance incentive mechanisms and a multiyear rate plan, including an earnings-sharing mechanism (ESM), or such other alternative regulatory mechanisms.”

The law recognizes that traditional ratemaking no longer works well because utilities are shifting from making larger and more infrequent investments (such as large-scale power plants) to smaller, more frequent investments such as grid improvements and distributed energy resources, the utility said in its initial application.

Duke Energy Progress told the NCUC that it took a conservative approach on its first application for performance-based regulation (PBR) so it could gain experience from its implementation. DEP serves 1.7 million customers in the Carolinas. The firm’s other utility in the state, the larger Duke Energy Carolinas, has a pending application to implement PBR.

The new rate mechanism represents a “fairly significant departure” from how the state has regulated its utilities for decades, Friday’s order said. Specifically, the new law approved four new concepts in retail rate regulation.

First, the multiyear rate plan means DEP has its rates set for several years, with periodic changes in base rates that do not require an additional rate application. Second, utilities including DEP can use a decoupling mechanism for its residential customers. Third, the ESM allows utilities to decide to file a new rate case when their weather-normalized earnings fall below the authorized rate of return and requires them to refund customers on excess weather-normalized revenue, plus 50 basis points.

The fourth major change is the performance incentive mechanism that links rates with performance in targeted areas consistent with public policies. DEP can earn extra money for doing well under the PIMs, or it could face penalties that go back to customers if it does poorly.

The PIMs are designed to increase the number of customers on time-differentiated rates, raise the number of net-metered interconnections, encourage the interconnection of utility scale generation above DEP’s targets and help large commercial and industrial customers achieve decarbonization goals.

The order drew partial dissents from four of the seven NCUC commissioners. Chair Charlotte Mitchell dissented in part and was joined by Commissioner Kimberly Duffley in full and Commissioner Karen Kemerait on its findings on DEP’s rate of return and recovery of COVID-19 costs. Commissioner Daniel Clodfelter wrote a separate dissent.

The commission approved a rate of return of 9.8%, while Mitchell and her colleagues would have approved 10%, reasoning that the costs of borrowing money have risen significantly and DEP risks a potential ratings downgrade at the lower level, which would cost customers. It could force the utility to cut costs to maintain its rating.

“Given the dynamics of the electric system, including changes in the generating mix, as well as the increasingly extreme summer and winter weather in North Carolina, now is not the time to put DEP in a position to cut to the extent that could impair the reliable operation of the system,” Mitchell said in the dissent.

COVID expenses include costs from having a moratorium on disconnections during the pandemic, which led to bad debt and other costs, as well as costs incurred by DEP and its employees to maintain the grid during the pandemic. Mitchell would have allowed DEP to collect additional funds, and, in her dissent, argued the majority decision is not good for the firm’s financial ratings.

Clodfelter’s dissent focused in part on the PIMs, arguing the commission should have adopted ones that encourage DEP to cut costs in order to offset upward pressures on rates, and to encourage the utility to finish projects early or under budget. He noted the law gave the NCUC and stakeholders little time to implement the first rates and argued they should prepare well for the next rate case in a few years.

Duke said it was reviewing the order and that the multiyear rate plan approved by the NCUC would strengthen the electricity grid while facilitating a cleaner energy future.

“We believe this is a constructive outcome that enables Duke Energy to maintain strong progress toward building a cleaner, more reliable energy future for our North Carolina customers,” the firm said in a statement.

Posted on

PJM Stakeholders Finalize CIFP Proposals Ahead of Vote

PJM and stakeholders have finalized their critical issue fast path (CIFP) proposals and posted executive summaries detailing how their packages would redesign the capacity market if approved by the Board of Managers.

The proposals will be presented to the board during the CIFP Stage 4 meeting on Wednesday, followed by a special Members Committee meeting in which stakeholders will vote on recommending packages to the board. The board letter initiating the CIFP process stated its intention to direct PJM to make a FERC filing in October with a slate of capacity market changes to be informed by stakeholders’ recommended proposals.

The 20 proposals on the table largely fall into three camps: PJM’s two proposals and variants building off it from Constellation, Buckeye, Vistra, LS Power and the Consumer Advocates of the PJM States (CAPS); the Independent Market Monitor’s Sustainable Capacity Market (SCM) design and variants from Daymark/East Kentucky Power Cooperative (EKPC) and American Municipal Power (AMP)/J-Power; and an annual market with two capacity products designed by Leeward Energy and American Electric Power (AEP).

PJM Adds Annual Auction Design Proposal

Following stakeholder feedback that its seasonal capacity market design may need additional development, PJM added a second proposal retaining the annual Base Residual Auction (BRA) structure, while including all other changes in its original proposal. Both options will be voted on Wednesday. (See PJM Updates Proposal as CIFP Nears End.)

The seasonal design would allow generators to submit a “menu” of offers, with summer, winter and annual components. Seasonal offers would include the incremental costs to deliver capacity for that period, while the annual offer would be based on costs that could be avoided if the resource were to be committed for the full year. Resources would have separate accreditations for each season. Variable resource rate (VRR) demand curves would be created for each season and calibrated to allow the reference resource to recover its full annual costs in one season if the other season clears at zero.

Both the annual and seasonal proposals would include correlated outages, ambient de-rates and other availability risks in resource accreditation and all resources, except for energy efficiency, would be accredited under a marginal effective load carrying capability (ELCC) approach.

PJM’s proposals would shift to expected unserved energy (EUE), which aims to measure the breadth of an outage both in duration and number of megawatts shed, as the reliability metric instead of loss of load expectation (LOLE), which tallies the number of outages experienced. Marginal effective load carrying capability (ELCC) would be used for the accreditation of all capacity resources, except for energy efficiency.

The option for retroactive replacement of capacity obligations after a performance assessment interval (PAI) would be eliminated and the proposals would create a market where resources can trade hourly obligations prior to the day-ahead market.

Generators would have the option of using a default capacity performance quantified risk (CPQR) calculation to represent the risk they take on as a capacity resource.

Several Stakeholders Propose Variants of PJM Proposals

Three proposals — from the Monitor, Daymark/EKPC and AMP/J-Power — focus on the capacity performance (CP) non-performance penalty charge rate and the annual stop-loss limit. The three would redefine both parameters to be based on the annual BRA clearing price, rather than the net cost of new entry (CONE). Since their effect is the same, they will be combined in Wednesday’s voting.

The penalty rate and stop-loss were two of the three changes to the CP structure the MC recommended changing in a May vote. However, the Board of Managers directed PJM to file changes to the triggers initiating a PAI, which defines when a generator can be penalized for not meeting its capacity obligations. (See FERC Approves PJM Change to Emergency Triggers.)

In addition to changing the penalty and stop-loss to the capacity clearing price, Buckeye Power recommended that all capacity resources be required to offer into the energy market, provide hourly operating parameters and real-time telemetry, and have a fuel cost policy if their capacity offer is above zero. The company offered two variants of its proposals, including PJM’s seasonal and annual designs and the bulk of their other components.

Buckeye stated that PJM’s report on the December 2022 winter storm showed that the RTO lacks insight into the amount of curtailment it will receive from demand response (DR) resources and additional provisions are needed to ensure it can deliver on its capacity obligations. Either firm-service level (FSL) or guaranteed load-drop (GLD) would be required for DR to participate in the capacity market. Intermittent and DR resources would retain their exception from the requirement that generators offer into the capacity market.

Constellation’s two proposals mirror the bulk of PJM’s annual and seasonal capacity options, but change the risk modeling to use 50 years of historical weather data, rather than 30 years and would use a “prompt auction” timeline with six to 12 months between the auction and delivery year. The proposals also include a commitment to open a stakeholder process to consider additional changes to the energy and ancillary services (E&AS) markets.

PJM had proposed to use 50 years of weather data in previous iterations of its proposal, but arrived at the conclusion that an adjustment for warming temperatures would be needed past 30 years. After presenting multiple versions of how such an adjustment could be done, PJM decided to start its weather lookback with data from 1993 with no adjustment. The Constellation proposal would not include a climate change adjustment.

While it’s supportive of a more granular capacity market design in the future, Vistra’s executive summary argued that additional work is needed on a seasonal design before the company can support filing changes with FERC. Its proposal is based on PJM’s annual auction proposal, but with several modifications including retaining the ability for generation owners to retroactively substitute capacity obligations after a PAI, changing the default CPQR calculation and holding off on expanding the ELCC construct to all resources to the 2026/27 BRA to allow for more refining.

Vistra’s proposal would retain the penalty rate and stop-loss based on net CONE, arguing that using auction clearing prices to determine the penalties would reduce the incentive for resources to perform during an emergency. Eligibility for bonus payments to generators that overperform during a PAI would include all resources that are eligible to participate in capacity auctions, including those that do not clear. PJM’s proposal would tighten eligibility to only cleared capacity resources, which Vistra argued would reduce the incentive to perform.

The proposal includes PJM’s testing requirements, but states PJM should account for market and operating conditions when scheduling tests to avoid creating “testing traps” where a generator that would meet its obligations under real-world conditions nonetheless fails the test. It recommends testing take into account the gas pipeline nomination cycle, arguing that many resources would not procure fuel when system conditions do not indicate they will be dispatched.

The company’s proposal also calls for a stakeholder process to be initiated looking at improving accreditation for thermal resources, including marginal ELCC or alternatives, and a second CIFP process with the goal of “developing a framework that protects both consumers and market participants alike from market power, but allows resources to employ their best commercial judgement in submitting offers into the market.”

The consumer advocates’ proposal supports PJM’s seasonal model, but opposes calibrating the demand curves to allow full annual cost recovery in one season, arguing that could lead to a doubling of capacity payments. It also opposes removing the capacity benefit of ties (CBOT) from the balancing ratio, a proposition it calls “overly conservative” and not in line with the probabilistic manner in which the value of generation resources is viewed.

Removing CPQR from the calculation of resources’ avoidable cost rate (ACR) also raises market power mitigation concerns and leads to uncompetitive auctions.  It recommends leaving CPQR as a component of ACR so that risks can be offset by net E&AS revenues.

“It is unlikely that any consumer advocate office could support such a significant change in PJM’s philosophies. The consumer advocates have always strongly supported competitive wholesale markets and see the competitive construct focus as a pillar by which PJM stands upon,” the CAPS executive summary states.

The proposal also includes changing the distribution of CP bonus payments to include a share going to consumers to reimburse them for the capacity that was not delivered by resources not meeting their obligations.

LS Power based its proposal off PJM’s annual capacity package, arguing the seasonal design has not been adequately vetted, modeled and back-cast. It would substitute the marginal ELCC accreditation for thermal resources with an equivalent unavailability factor-weighted approach, which reduces accreditation for any historical shortfall in performance. Capacity offers would be similar to the energy market, with generators offering market-based and cost-based offers. The marginal offer would be subject to the Monitor market power test and would be mitigated to the cost-based offer if it fails and the auction re-run until the marginal offer does not fail the market power test.

Fixed resource requirement (FRR) entities would be required to meet their own capacity needs, as well as the average percentage that the BRA has cleared above the installed reserve margin in the prior five years. The proposal also retains retroactive replacement transactions for generators and status quo eligibility for CP bonus distribution.

The LS proposal would change the CP penalty charge rate to be based on the BRA clearing price but leave the annual stop-loss based on net CONE. The company offered a second proposal identical to its first but leaving the status quo charge rate in place.

Monitor Proposes Hourly Model with Annual Pricing

The Monitor’s proposal would create a forward capacity market where committed resources are paid for the capacity they’re available to provide in each hour of the year based on a single annual clearing price.

Resources would be cleared based on their expected hourly availability, which is based on historical data including outage correlations with temperatures and weather.

Resources would be tested at least twice each year, once each in the summer and winter, and if they fail to start then or when dispatched they would forfeit all capacity revenues going back to the last time they started and reached their full installed capacity (ICAP) and going forward until they successfully start and ramp up to their ICAP. The Monitor’s executive summary argued that the model would incentivize resources to mitigate their risk by ensuring they’re able to start at any time of the year and to self-schedule their generators periodically to both self-test and to limit the potential lost revenue if they fail a test.

All resources, including intermittent and storage, would be subject to the requirement that resources offer into the capacity market, which the Monitor argued is imperative to ensure access to transmission capability is not withheld, as intermittents make up an increasing share of the PJM fleet. Resources’ obligation would be based on their availability in each hour and they would be paid when they’re available according to their obligation, which the Monitor argued means that intermittents would not be penalized for not being available when they couldn’t produce energy.

Without penalties for nonperformance, the proposal would eliminate the CP construct and its bonuses and penalties, which the Monitor said fail to provide functional incentives outside of PAIs and potentially can increase the likelihood of emergency conditions. The high penalty rates also create a corresponding relationship with the CPQR component in generators’ offers, increasing clearing prices.

“This impact illustrates the circular logic of the CP model. The CP model creates arbitrarily high penalty rates which affect CPQR which increase the ACR market seller offer caps … Under the SCM approach, the arbitrary and extreme penalties would be eliminated and therefore the impact on CPQR and the impact on capacity market clearing prices would be eliminated,” the Monitor’s executive summary states.

Stakeholder Hourly Capacity Proposals

The joint EKPC and Daymark proposal also would clear capacity to meet firm load in each hour of the delivery year with locational deliverability constraints, but would bifurcate the product into base capacity (BC), which would be hourly expected load plus the reserve margin, and emergency capacity, which is aimed at meeting hourly load during emergency conditions with modeling of extreme weather and fuel delivery force majeure. Resources could take either an EC or a BC position in capacity auctions, but not both.

Emergency capacity resources would be required to demonstrate they can operate under extreme temperatures and humidity, akin to the enhanced winterization concept in PJM’s proposal, show they have the financial ability to absorb non-performance penalties and have verifiable firm fuel. It would be procured in tranches and committed for three-year intervals.

Base capacity would be considered to have met its obligation if it offers committed capacity into the day-ahead and real-time markets, while EC would be considered to have not met its obligation if it’s unavailable during a dispatch day where emergency conditions are present. A non-performing EC resource would be subject to a penalty of the daily capacity rate multiplied by 120 and its unforced capacity. If it’s unavailable three times during a three-year interval, it would be removed from the roster of EC resources for the remainder of the period.

The third joint EKPC and Daymark proposal would combine PJM’s risk modeling component, eliminate CP penalties and use the Monitor’s hourly method of measuring and compensating capacity.

Taken together, the three joint AMP and J-Power proposals would create a two-phased transition to a modified version of the Monitor’s SCM. The transitional phase would include the proposed shift to a CP penalty and stop-loss based on capacity clearing prices, as well as changes to the balancing ratio to include net exports and applying the same penalties to FRR resources that generators participating in PJM’s Reliability Pricing Model face. The option of using physical penalty commitments also would be eliminated for FRR entities.

The proposal for the second phase would revise the SCM to have a two-year procurement horizon with two Incremental Auctions and no exceptions to the requirement that capacity resources offer into the energy market.

Leeward and AES Propose Four-plus Season Market

A proposal from Leeward and AES, jointly made as the capacity coalition, would create a capacity market with at least four seasonal and four intervals for each day of the delivery year. The auction structure would follow the status quo for establishing clearing prices, but would have separate accreditation for their expected output for each seasonal and daily interval. All resources would be subject to the must-offer requirement into the capacity market once the new market structure has been established.

Rather than being designed for implementation in coming auctions, like other proposals, the coalition’s proposal recommends rollout in the 2030-31 delivery year. The proposal calls for an additional CIFP-like process to create more detailed rules for the new structure.