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September 27, 2024

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PJM Whitepaper to Highlight Future RA Concerns

The pace of capacity being installed on PJM’s grid may not keep up with the rate of retirements and accelerating load growth over the next eight years, according to a white paper PJM plans to release Friday.

“There is a concern that we may not be replacing the exiting generation at the rate needed to maintain resource adequacy,” PJM’s Scott Benner told the Markets and Reliability Committee during a presentation on the white paper’s findings.

About 40 GW of generation in the RTO is forecast to retire by 2030, representing 21% of currently installed generation. The white paper lays out two scenarios for the development of additional capacity over the same period, with a conservative estimate at just over 15 GW installed and a more optimistic forecast seeing nearly 31 GW of development.

Brenner said while 46 GW left the market over the past eight years, the period saw sharp growth in natural gas resources that made up for lost coal generation. Natural gas installations are expected to drop off after 2023, with renewables only picking up a share of the slack. 

“We’re blessed in PJM to have an abundant natural gas supply, but there’s a concern over the next 10 years that we won’t have that backstop to cover the retirements,” Brenner said.

PJM Vice President of Market Services Stu Bresler said staff have been looking at the future supply-demand balance since October, when CEO Manu Asthana shared concerns about the pace of retirements and development at the 2022 Annual Meeting of Members. (See “PJM CEO Manu Asthana Warns of Potential Generation Shortfalls,” PJM MRC Briefs: Oct. 24, 2022.)

“We cannot take the reliability that we enjoy in our region for granted through this energy transition; we have to take concrete steps to ensure that it will continue,” Asthana said before the Markets and Reliability Committee on Oct. 24.

The development forecasts combine analysis of projects in PJM’s queue with analysis conducted by S&P Global. The conservative scenario assumes that about 5% of projects that enter the interconnection queue reach commercial operation, while the more optimistic estimate assumes more projects enter service. Of the 40 GW expected to retire, Benner said coal would account for about 60% and natural gas 30%.

State clean energy policies are expected to drive about 24 GW of the retirements, with PJM’s analysis assuming that owners will choose to retire facilities rather than make the upgrades required to comply with new regulations and laws.

The retirements are expected to accompany a growth of demand from data centers and the electrification of vehicles and buildings. Benner said those trends could collide later this decade, causing installed generation to fall below the 14% reserve margin unless the rate of new resources accelerates.

“With the expected retirements and rates of replacements, there’s a risk that we move into a higher rate of demand response usage in around 2027,” he said.

Carl Johnson, of the PJM Public Power Coalition, said the RTO must implement firm and transparent rules to avoid reliability problems and creating a scenario where reliability must-run (RMR) contracts are seen as a solution.

“We’re going to need some sort of reliability backstop that isn’t the current RMR rules,” he said.

Noting that Benner’s presentation pointed to the Resource Adequacy Senior Task Force as one of the forums to discuss market changes to continue the conversation, David “Scarp” Scarpignato of Calpine said the task force has already been mired in intractable discussions, and PJM may need to take a more active role in addressing the issues it’s highlighted.

“PJM might have to exert even more leadership than you already have to push this forward … because I’m not sure the stakeholders are going to reach consensus,” he said.

Abe Silverman, of the New Jersey Board of Public Utilities, said he was glad to see that development of new generation is being treated as an equal priority to the issue of retirements. States and companies with clean energy goals have significant demand for renewable resources and obstacles limiting their entry to the market, including the interconnection queue, should be treated as part of the solution, he said.

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DOE Announces $2.5B for Carbon Capture Projects

The Department of Energy is targeting the dirtiest and hardest-to-decarbonize electric power and industrial plants with $2.52 billion in funding for “transformative carbon capture systems and carbon transport and storage technologies,” according to an agency announcement on Thursday.

The dollars from the Infrastructure Investment and Jobs Act will go to two programs, both focused on advancing carbon capture technologies that are at or moving toward commercial scale.

The Carbon Capture Demonstration Projects Program will get the lion’s share of the money — $1.7 billion — for approximately six projects that demonstrate commercial-scale, and readily replicable, carbon-capture and sequestration (CCS) projects.

According to the funding announcement, at least two of the projects will be at new or existing coal-fired generation plants. Another two will be sited at new or existing natural gas plants, and the final two at new or existing industrial facilities, such as cement, iron or steel plants.

“Proposed projects must demonstrate as part of the application and during the award at least 90% CO2 capture efficiency over baseline emissions and a path to achieve even greater CO2 capture efficiencies for power and industrial operation,” the announcement says. The awards will come with a 50% cost-share requirement.

Letters of intent for the funding must be received by March 28, with final applications due May 23.

The Carbon-Capture Large-Scale Pilots program will offer a more modest $820 million for 10 projects that will de-risk “transformational carbon capture technologies and [catalyze] significant follow-on investments for commercial-scale demonstrations” in both the electric power and industrial sectors.

The term “large-scale” here means projects that are not yet commercialized but are large enough to validate the technology and “demonstrate the interaction between major components so that control philosophies for a new process can be developed and enable the technology to advance from large-scale pilot project application to commercial-scale demonstration or application.”

Again, the focus will be on coal and natural gas power plants and industrial facilities, and the award can be used for up to 70% of project costs. The Office of Clean Energy Demonstrations will oversee both programs.

Concept papers for the funding will be due April 5, with full applications due June 21.

“Drastically cutting emissions across our economy through next-generation carbon management technologies is a critical component of President Biden’s strategy to combat the climate crisis and achieve our ambitious clean energy goals,” Energy Secretary Jennifer Granholm said in the DOE announcement. “By focusing on some of the most challenging, carbon-intensive sectors and heavy industrial processes, today’s investment will ensure America is on a path to reach net-zero emissions by 2050.” 

Other Carbon Capture Funding 

The White House and DOE continue to roll out IIJA funding, signaling the administration’s focus on implementing its clean energy and greenhouse gas emission reduction initiatives at speed and scale. The CCS announcement comes hard on the heels of Wednesday’s announcements of new initiatives aimed at expanding offshore wind. (See Interior Proposes 1st Lease for Offshore Wind in Gulf of Mexico and DOE Launches West Coast OSW Transmission Study.)

The carbon capture industry has already been buoyed by earlier funding announcements from the IIJA, focused mostly on demonstration projects, and the Inflation Reduction Act, which contains generous tax credits for such projects.

The IIJA funding includes $3.5 billion for four regional direct air capture hubs, each of which will have to capture, store or utilize one million metric tons of CO2 per year. The IRA contained significant increases in the 45Q tax credits, which specifically benefit CCS. For example, the credit for carbon captured from power or industrial plants and stored in underground salt caverns rose from $50/metric ton to $85/metric ton, and the credit for direct air capture jumped from $50 to $130/metric ton.

Coming on top of this support, Thursday’s announcement “is significant not just for the size of the investment, but for the impact it will have on further advancing the development and deployment of carbon management technologies in both heavy industry and power sectors,” Jessie Stolark, executive director of the Carbon Capture Coalition, said in a statement to NetZero Insider. “Testing, demonstrating and safely deploying new emissions reduction technologies in heavy industry sectors, such as steel, cement and concrete as well as the power sector are not optional if we are to meet climate targets.”

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Dragos: Cyber Landscape Remained Volatile in 2022

The cyber threat landscape in 2022 included new malware targeting the electric industry with “breakthrough escalation in capabilities,” in addition to an increase in energy sector-targeting threat activity in general, possibly linked to tensions between Russia and the EU, cybersecurity firm Dragos said in its annual Year in Review report released last week.

However, while attacks against targets in Europe — particularly Ukraine — escalated following Russia’s invasion of that country in February, cyber incidents involving U.S. energy utilities were “primarily focused on reconnaissance,” Dragos said. This ran counter to fears that the Russo-Ukrainian War could become the prelude to a broader cyber offensive against Western countries that support Ukraine. (See Experts Warn Cyberwar Still Possible.)

The biggest news for Dragos on the malware front last year was the introduction of Pipedream, a framework for attacks on industrial control systems (ICS) disclosed by Dragos in April. (See Dragos Warns Malware Developers Building Skills Fast.) Pipedream’s developers, a newly identified threat group dubbed “Chernovite” by Dragos, intended the tool to “attack industrial infrastructure,” the firm said.

Dragos added that it has “high confidence” that Chernovite represented a state-backed actor with “disruptive or destructive” goals, though in keeping with its usual practice, it has not connected the group with a specific nation.

Ransomware incidents (Dragos) Content.jpgRansomware incidents by sector | Dragos

 

Although it was discovered before being deployed in the wild, Pipedream sparked concern across the cybersecurity community because of the unprecedented level of sophistication it displayed. Pipedream’s modular nature meant it could be easily modified to attack many manufacturers and equipment types and could impact companies in a wide range of industrial sectors.

Dragos’ report compared the new tool to Havex, a malware variant discovered in 2013 that targeted victims in the U.S. and Europe. Like Pipedream, Havex could be used across multiple industries; Dragos called it “the [cybersecurity] industry’s first glimpse into the potential cross-industry impact an adversary could have by taking advantage of a standard protocol.”

“Havex’s campaign goal was espionage, and … the adversary gathered data on networks from companies in the energy, aviation and pharmaceutical sectors, to name a few,” Dragos said. “While we can never know whether Chernovite looked at Havex when designing Pipedream, we do know that Pipedream takes that cross-industry ability to the next level [with] the ability to target thousands of devices across critical industries.”

Aside from Chernovite, and another newly identified threat actor dubbed “Bentonite” that targets governments and the manufacturing and maritime oil and gas networks, Dragos identified a number of other known threat groups as still active last year. These include Kostovite, which has demonstrated “skilled lateral movement and initial access operations into ICS/OT [operational technology] environments” in U.S. energy companies, and Kamacite, which has been linked to the 2015 and 2016 attacks on Ukraine’s power grid.

Electrum, another group involved in the 2016 Ukraine attacks, was back last year as well. In a fresh attack on Ukraine, the group deployed a malware that Dragos has labeled Industroyer2, a variant of the tool used in 2016. However, unlike the earlier attack, last year’s hack was apparently foiled before any outages were caused. (See E-ISAC Warns of Escalating Russian Cyber Threats.)

Ransomware on the Rise

While North America was relatively free of ICS attacks during 2022, ransomware was another story. Dragos said it “tracked 605 ransomware attacks against industrial organizations [worldwide in] 2022, an increase of 87%” over the prior year. Of these, 247, or about 41%, affected organizations in North America.

The vast majority of global ransomware incidents occurred in the manufacturing sector, with 437 attacks. Energy accounted for 29 incidents, with seven attributed to engineering and utilities.

Attacks in the energy sector included a compromise of unspecified companies reported in October by the Electricity Information Sharing and Analysis Center, resulting in the exfiltration of data that could “allow a capable adversary to dynamically model electricity systems.” According to Dragos, however, no outages are known to have occurred because of this data extraction.

The ransomware sector was marked last year by the apparent collapse of the Conti cybercrime gang in May, after its attack on the government of Costa Rica led the U.S. State Department to announce a reward for any information about the group’s leadership and affiliates. (See Dragos: Ransomware ‘More Impactful’ in Q2.)

However, the disappearance of Conti was accompanied by the rise of other groups such as Black Batista, which attacked U.S. agricultural equipment manufacturer AGCO in May; Dragos said it is possible that personnel from Conti may have joined Black Batista or other groups.

Dragos attributed about 28% of ransomware incidents last year to the Lockbit group, which released an updated version of its eponymous ransomware-as-a-service software that included features such as anti-detection mechanisms and the ability to disable Microsoft Defender Antivirus. The firm said it had “moderate confidence” that Lockbit “will pose a threat to industrial operations into 2023.”

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Lordstown Motors Recalls Endurance Electric Truck

Lordstown Motors (NASDAQ:RIDE) on Thursday announced it had stopped production of its battery-electric pickup truck, the Endurance, and would voluntarily recall those already sold to address an electrical connection issue that could result in a loss of propulsion while driving.

The recall affects 19 vehicles that are being driven either by customers or by company employees, Lordstown said in a statement and simultaneous filing with the U.S. Securities and Exchange Commission.

Judging from the company’s explanation that it is working with its entire supplier network to address the problem, the potential malfunction may not be as simple as one malfunctioning part.

“While our experienced team has made significant progress in addressing the underlying component and vehicle subsystem issues affecting the Endurance build schedule, we remain committed to doing the right thing by our customers and to resolve potential issues before resuming production and customer shipments,” CEO Edward Hightower said in the statement.

“The team is diligently working with suppliers on the root-cause analysis of each issue and potential solutions, which in some cases may include part design modifications, retrofits, and software updates,” the company said.

“In this regard, LMC has filed paperwork with the National Highway Traffic Safety Administration to voluntarily recall the Endurance to address a specific electrical connection issue that could result in a loss of propulsion while driving. Lordstown is working with its supplier network to implement a corrective action that the company believes will address this issue.”

The company expects to provide a detailed update on the problem during its 2022 earnings call with analysts on March 6, it said.

The company did not begin production of its truck until last fall after a yearlong delay because of supply chain problems. (See Startup EV Makers Inching Toward Profitable Production.)

The company’s share price fell 11.38% on Thursday, closing at $1.09. During the last 52 weeks, the share price has been no higher than $1.47. It was as high as $29.01 on Sept. 14, 2020.

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Avangrid Pushes Forward on NECEC, Offshore Wind, PNM Merger

Avangrid (NYSE:AGR) announced Wednesday that its net income increased 16% in 2022 over 2021 but projected flat financials in 2023.

In a conference call with industry analysts, CEO Pedro Azagra said the company’s priorities this year are closing its merger with PNM Resources (NYSE:PNM), negotiating settlements in its utility rate cases and ensuring the economic viability of its New England Clean Energy Connect (NECEC) transmission project.

He said Avangrid remains committed to the Commonwealth Wind project off the Massachusetts coast and is still working on it, even after moving to terminate the power purchase agreements it agreed to.

Avangrid plans to submit an economically viable bid on that project in the state’s next offshore wind solicitation, Azagra added, and is working through the legal and economic challenges that face some of its other projects.

NECEC, first proposed in 2017, would bring Quebec hydropower to New England. After multiple challenges, the project won key court victories in 2022. (See NECEC Scores Another Victory in Maine’s Highest Court.)

But legal issues remain unresolved, Azagra said.

“Also, we have to review the economics just to be sure we get recovery of the costs we have incurred,” he said.

“With the delay caused by the unprecedented action by our opponents, we continue to look at restarting construction as soon as possible,” said Catherine Stempien, CEO of Avangrid Networks. “And with that restart of construction, we’re negotiating with all of our vendors to make sure we can optimize the construction schedule as well as the pricing. We’re doing that in the background as we’re proceeding with the legal matters.”

An analyst asked whether the financial review centers on the cost of construction of the line or on the revenue that will be derived from it.

“We are working on both sides,” Azagra said.

Turning to utility revenues, Avangrid reported that it had settled its rate case for Berkshire Gas in Massachusetts in 2022; expects its settlement negotiations for New York State Electric and Gas and Rochester Gas and Electric in New York to yield new rates in May; expects new rates for Central Maine Power in Maine by July; and expects rates for United Illuminating in Connecticut to be settled by September.

Avangrid also said its proposed acquisition of the largest energy utility in New Mexico is still in play, despite being shot down by that state’s Public Regulation Commission in December. (See NM Regulators Reject Avangrid-PNM Merger.)

Since that vote, Avangrid and PNM have extended their merger agreement and the elected commissioners have been replaced by appointees. Azagra expects that to make a difference.

“The new commissioners are each highly experienced individuals with deep knowledge of the challenges and opportunities the energy transition will bring, as well as the central role of utilities in enabling that transition,” he said.

During the call, Azagra spoke repeatedly about the economic pressures of the past year. He said Avangrid renegotiated PPAs for 780 MW of onshore wind in 2022 and, when it could not renegotiate the PPAs for the 1,232-MW Commonwealth offshore project, moved to dismiss them. (See Avangrid Seeks to Terminate Commonwealth Wind PPAs.) 

“Let me be clear: While we are terminating our PPAs for Commonwealth Wind, we remain fully committed to our offshore business. We are on track to bring the first large-scale project to successful completion,” he said, referring to the 806-MW Vineyard Wind I, now under construction and expected to start generating electricity later this year. “This is not a question of commitment or capabilities, but rather of a unique economic situation.

“Unfortunately, the impact of historic inflation, sharp interest rate increases, supply chain bottlenecks and existence of a price cap prevent us from moving Commonwealth Wind forward under viable economic conditions,” Azagra said. So Avangrid will submit a new bid to the state of Massachusetts in May, he added.

Asked by an analyst if Avangrid had confidence in the viability of such a bid amid continued economic pressures, Azagra said he did.

“Because of the work we have already done in the last more than three years, we’re probably as best positioned as we can to have [certainty] to make a new bid for this project because we continue working in the project, and we are committed to delivering this project.”

He noted that offshore projects in other states have included price indexing and said that given the multiyear time frame, an ability to make price adjustments needs to be considered for Commonwealth.

Unaudited financials show Avangrid ended 2022 with $901 million in adjusted net income on $7.92 billion in operating revenue, up from $780 million and $6.97 billion in 2021. That works out to $2.33/share in 2022 and $2.18 in 2021.

For 2023, it is projecting $850 million to $915 million in adjusted net income, or $2.20 to $2.35/share.

Additional discussion by the company about its projects and its finances is contained within its 10-K annual report, also published Wednesday.

Avangrid stock closed at $41.01/share in heavier-than-average trading, a 1.6% increase from Tuesday’s close.

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NYISO CEO Delivers ‘State of the Grid’ to Management Committee

NYISO CEO Rich Dewey used Wednesday’s Management Committee meeting to brief stakeholders on “the state of the grid” and the ISO’s priorities going forward.

“NYISO is excited about 2023 but is cognizant of the unprecedented challenges” arising from the Climate Leadership and Community Protection Act (CLCPA), which moves New York through “an unprecedented energy transition,” Dewey said.

Dewey said the ISO is focused on effectively transitioning the state’s grid from high-polluting and high-emitting resources to new renewables without compromising reliability. He also listed as priorities: ensuring projects such as the Long Island offshore wind solicitation remain on schedule; improving the interconnection process with more transparency and expediency; and fine-tuning market mechanisms to be more responsive during the transition.

Another priority is to “continue to recruit talented, engaged and motivated people” to NYISO and create a “learning environment focused on inclusion for every team member,” Dewey told the committee.

Scott Leuthauser of Hydro-Quebec Energy Services asked for Dewey’s opinion on the Public Service Commission’s recent approval of 62 renewable projects (See NY PSC Approves 62 Tx Upgrades Totaling 3.5 GW.)

Dewey responded that much of New York’s infrastructure and transmission needs were already identified by NYISO, and so the PSC’s recently approved projects are “compatible with what we see as needed and what we’ve been calling for.”

Chris Wentlent, of the Municipal Electric Utilities Association of New York State, asked Dewey what NYISO’s role would be in implementing the cap-and-invest program proposed by Gov. Kathy Hochul. Mark Younger, president of Hudson Energy Economics, asked whether it would be difficult to implement. (See Hochul Highlights Cap and Invest in State of the State Address.)

Dewey said NYISO has already spoken with heads of state agencies about the proposal, and they have “tapped into our expertise” and expressed “a spirit of cooperation and collaboration.” Dewey said he believes “it wouldn’t be a hard lift” to incorporate carbon pricing into NYISO markets but that “the proof will be in the pudding.”

Chris Casey, a senior attorney with the Natural Resources Defense Council, asked if Dewey believed that a cap-and-invest program might dissuade investors from New York.

Dewey responded that incentive programs that accelerate the transition to renewables can drive economic opportunities, but NYISO wants a balanced approach that “doesn’t create counter incentives that prematurely retire resources.”

Casey also inquired about NYISO’s staffing concerns. Dewey noted that vacancy rates in some parts of the organization were once above 10% of staff levels but have since dropped back to the historic norm of 5% because of the ISO attracting top talent in key areas.

DER Revisions

The MC approved NYISO’s proposed revisions to its participation model for DER aggregation, recommending that the Board of Directors approve them as well.

The revisions process had been contentious, but a NYISO statement promising to revisit its unpopular 10-kW minimum for individual resource participation assuaged stakeholders. The ISO’s Michael DeSocio read the statement before staffer Harris Eisenhardt outlined the revisions, which passed without discussion, objections or abstentions.

With FERC approval, the revisions are expected to go into effect in summer, which is also when DER aggregation open enrollment should begin. (See NYISO Promises to Lower DER Minimum Capability in Future.)

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EV Road Usage Charge Bill Floated in Wash. House

Washington Rep. Jake Fey (D) talked Tuesday about his bill to create a road usage fee for electric and hybrid vehicles.

Talking was his main goal — with fellow legislators, interest groups and other stakeholders.

Fey’s House Bill 1832 was more of a conversation starter than a nailed-down piece of legislation. 

“I’m not wedded to any specific detail. This is the start of a discussion,” he said at a hearing on the bill before the House Transportation Committee, which he chairs. “We can’t sit back and pray we’ll have a solution.”

Last year, Gov. Jay Inslee issued a mandate banning the sale of new gasoline-powered cars in the state by 2035, which led to Fey’s proposal of a road usage fee. The measure is designed to replace shrinking state gasoline tax revenue that pays to maintain Washington’s highways. (See Road to Mass EV Adoption Still Unclear in Wash.)

“Gasoline revenues are headed downward and consistently so from year to year,” Fey said. The legislature needs to discuss and hammer out a road usage fee system to counteract those shrinking gas revenues, he said.

HB 1832 proposes to establish a voluntary road usage charge program in 2025 that would levy a 2.5-cent fee for every mile that an electric or hybrid vehicle drives on public roads and highways. The fee would likely be calculated by an instrument connected to an electric vehicle’s odometer, a Transportation Committee memo said. A mandatory mileage fee would be targeted for 2030 under the bill.

Owners of electric and hybrid vehicles in Washington currently pay two annual fees that total $150. Under HB 1832, an owner would have the choice of either paying the $150 or the fees calculated by the odometer readings, which would be capped at the amount of the combined annual fees.

Before Fey suspended the hearing Tuesday, the Washington State Transportation Commission, Seattle Electric Vehicle Association (SEVA) and Seattle-based think tank Climate Solutions testified in favor of the bill, without getting into specifics.

“This is a more equitable system for EVs to pay their fair share of road costs,” SEVA’s Grace Reamer said.

Fey said he plans to reopen the hearing on HB 1832, but no date was set.

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DOE Launches West Coast OSW Transmission Study

Energy Secretary Jennifer Granholm opened the Department of Energy’s two-day Floating Offshore Wind (FOSW) Shot Summit with the first of the event’s long list of offshore wind metaphors and puns — and announcements of DOE’s latest initiatives to advance FOSW technology, supply chains and infrastructure.

Pointing to the ongoing impacts of Russia’s year-old invasion of Ukraine, Granholm said Wednesday, “When the winds of change blow, some build walls, others build wind turbines.”

Announced in September, the Floating Offshore Wind Shot is aimed at cutting the cost of FOSW by more than 70% to a target price of $45/MWh, which Granholm said “would make floating offshore wind competitive across the nation, across the globe.”

Two-thirds of U.S. offshore wind potential is located in waters deeper than the 60-meter maximum for fixed-bottom turbines, she said, which is why floating turbines, mounted on floating platforms, are now a major focus of White House and DOE initiatives. In addition to the 30 GW of offshore wind development President Joe Biden has targeted for 2030, the Bureau of Ocean Energy Management has added an additional 15 GW of FOSW by 2035.

BOEM’s first West Coast auction in December brought in $757.1 million for five sites, but other potential areas for floating offshore wind development include Hawaii, the Gulf of Maine, and parts of the Gulf of Mexico. (See First West Coast Offshore Wind Auction Fetches $757M.)

Still, California figured heavily in the day’s announcements. Granholm started with the launch of a new West Coast Offshore Wind Transmission Study, supported by funds from the Inflation Reduction Act. “That study is going to examine how the West Coast can expand transmission to support offshore wind development,” Granholm said.

“The study will use its findings to develop practical plans through 2050 to address transmission constraints that currently limit offshore wind development along the nation’s West Coast,” a DOE press release said. “It is also expected to evaluate multiple pathways to reaching offshore wind goals while supporting grid reliability, resilience and ocean co-use.”

Other announcements focused on new research partnerships and initiatives:

  • California has become the first West Coast state to join the DOE-funded National Offshore Wind Research and Development Consortium. “The consortium works across the public and private sectors to invest in research and development projects that slash the cost of offshore wind for ratepayers across the country,” Granholm said. “The California addition is going to bring a whole new focus on floating offshore wind technology.”
  • Both California and Louisiana also joined the White House Federal-State Offshore Wind Implementation Partnership, launched last year to “maximize the benefits” of offshore wind development for workers and communities, according to a White House fact sheet.
  • DOE, along with the Sandia National Laboratory and the National Renewable Energy Laboratory, also announced “the development of an industry-informed roadmap for new operations and maintenance technologies and processes to enhance cost-effectiveness, efficiency and reliability at offshore sites,” according to the DOE press release.
  • With Hawaii still another potential site for floating offshore wind, DOE’s Pacific Northwest National Laboratory and the Bureau of Ocean Energy Management have deployed a floating scientific research buoy about 15 miles east of the island of Oahu “to collect offshore wind resource, meteorological and oceanographic data,” DOE said.

Not Business-as-usual

Granholm and other speakers at the summit were also eager to frame FOSW as a job generator and a vital technology for unleashing U.S. clean energy independence and energy security.

The Floating Offshore Wind Shot “is about bringing supply chains home; it’s about creating jobs from sea to shining sea, from welders and deckhands assembling platforms at our ports … to steelworkers hundreds of miles inland who are making towers or other components, to electricians and construction workers to connect those communities to the energy,” Granholm said.

It will also show “the world that we’ve got to build a global energy system that can never be manipulated again by one leader, by one autocrat or even one country,” she said.

But behind the sweeping, turbine-charged rhetoric of the summit lie real challenges. In its 2023 Offshore Wind Market Report, the Business Network for Offshore Wind sees both major growth drivers and potential headwinds, including ongoing debates over streamlining and accelerating permitting processes and rising concerns over the impact of expensive OSW construction on consumer electric bills. The report also notes the ongoing drag of inflation, which has some offtakers seeking to renegotiate contracts for East Coast projects,

“Building out the floating industry will require a substantially different supply chain than the one being developed for fixed-bottom turbines, necessitating more and new government research and support,” the report says.

Jocelyn Brown-Saracino, DOE’s offshore wind energy lead, agreed, saying the 70% cost reduction goal of the Floating Offshore Wind Shot “is not meant to represent a business-as-usual case. It will require [an] expanded, concerted R&D push from all of us, and more, it will require future leasing actions, transmission infrastructure, supply chain maturation, and the readiness of U.S. infrastructure, including ports.”

While the shot’s primary goal is to drive down costs and increase deployment, Brown-Saracino said, “R&D alone is not going to be enough to reach the cost targets.” Other priorities are being incorporated, such as ensuring just and sustainable deployment of FOSW, supporting the development of a “robust domestic supply chain,” transmission development, and advancing co-generation opportunities between FOSW and, for example, clean hydrogen.

As reeled off by Brown-Saracino, the supply chain challenges will be daunting. “We’re going to need to expand port capabilities. We’re going to need to ensure that we have a fleet of vessels for construction and operations, and we’re going to need to build manufacturing facilities,” she said. “We’re going to need to ensure that we have a set of trained domestic workers ready to step into jobs as the industry grows. And we’re going to need foresight into the timing and the geography of that growing demand. And we’re going to need to look for opportunities to ensure that that workforce is diverse, equitable and inclusive.”

Resolving transmission challenges will also be critical to “ensure that electrons can come to shore at a cost-effective manner,” she said. “We’re going to need solutions that help grid operators and system planners meet our goals to decarbonize the electric system, while not just protecting but enhancing the resilience and reliability of the grid.”

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More Cold Weather Standards Headed to Ballot

NERC’s Standards Committee kept up momentum on the organization’s efforts to harden the electric grid against extreme cold during its monthly conference call on Wednesday, despite some last-minute changes to a propose standard in response to a FERC directive issued last week.

The cold weather project — Project 2021-07 — is in its second phase of development, after completion of two new reliability standards in response to the February 2021 winter storm, also known as Winter Storm Uri, that nearly collapsed the ERCOT interconnection. NERC’s Board of Trustees voted last October to approve the new standards, EOP-012-1 (Extreme cold weather preparedness and operations) and EOP-011-3 (Emergency operations), which implement many of the recommendations found in the commission’s joint inquiry with NERC into the performance of the Texas grid during Uri.

At its open meeting last Thursday, FERC approved the standards, but criticized EOP-012-1 for including “in its current form … undefined terms, broad limitations, exceptions and exemptions, and prolonged compliance periods.” (See FERC Orders New Reliability Standards in Response to Uri.)

The commission directed NERC to revise the standard to include a deadline for completing corrective action plans and a shorter grace period for generators to implement needed protection measures than the five years given in the approved version.

Modified Action on EOP-012-2

The agenda for Wednesday’s meeting originally included a motion to approve three new standards from Project 2021-07 for their initial formal comment and ballot period: EOP-011-4 and EOP-012-2, comprising updates to the standards approved by FERC last week, and TOP-002-5 (Operations planning), which adds requirements for balancing authorities to have an extreme cold weather operating process to the existing TOP-002-4. Members were also to vote on the implementation plan for all three standards.

However, during the meeting, Latrice Harkness, NERC’s manager of standards development, explained that the standards development team (SDT) wished to drop EOP-012-2 from the agenda “in the interest of using stakeholder time effectively … and work on addressing the FERC directives.” Harkness said that if EOP-12-2 had been posted for comment as originally intended, the team would have had to wait until after the 45-day comment period to respond to FERC’s directive.

Standards Committee members were generally positive about the revised motion, which included changing the implementation plan to remove references to EOP-012-2 along with the changes to NERC’s glossary proposed in the draft standard. In response to a question from Charles Yeung of SPP, Harkness confirmed that EOP-012-2 was “still on track for … board approval” by November along with the rest of the Phase 2 standards. Yeung also asked that the reason for holding separate ballot periods be “communicated to the stakeholders [voting on the standards] clearly.”

Independent member Philip Winston raised a minor point of contention, saying that, while he had “no problem with the proposal,” he was concerned “from a procedural standpoint [about] voting for something [when] we have not seen everything that we’re voting on,” referring to the motion’s absence from the agenda. However, he made clear that he would abstain from the vote rather than voting against the motion.

Other than Winston’s abstention, the proposal to post all the standards except EOP-012-2 passed unanimously. Chair Amy Casuscelli of Xcel Energy clarified that she would “make sure” the reason for the change from the agenda would be reflected in the minutes.

CIP-002 Team Gains New Mandate

The other substantive item discussed at Wednesday’s shortened meeting concerned a request for interpretation (RFI) of CIP-002-5.1a (BES cyber system categorization) from Burns & McDonnell.

The consultancy submitted the RFI last year requesting clarification of the standard’s applicability to serial communication devices in medium-impact cyber systems, with the Standards Committee approving the request at its January meeting.

NERC Senior Standards Developer Jordan Mallory explained at Wednesday’s meeting that the RFI was assigned to the SDT for Project 2021-03 (CIP-002). The team concluded that because it was already revising the standard, it would be more appropriate to create a new standard authorization request (SAR) and add the clarification to its existing mandate.

As a result, the team requested the committee formally reject the RFI and adopt a SAR drafted by NERC staff and Burns & McDonnell aimed at clarifying the original question raised by the consultancy. In addition, the committee was asked to authorize posting of the SAR for a 30-day formal comment period and assign it to the existing SDT. Members voted unanimously to accept all the requests.

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FERC OKs PJM Proposal to Revise Capacity Auction Rules

FERC late Tuesday approved PJM’s request to revise the reliability requirement for the DPL South zone to avoid an artificial fourfold increase in capacity prices for delivery year 2024/25, rejecting complaints that it was changing its rules retroactively (ER23-729).

PJM asked for authority to exclude planned generation capacity resources from the calculation of a locational deliverability area’s reliability requirement if the addition of such resources increases the requirement by more than 1% and the resources do not enter a sell offer into the auction.

The commission ruled that PJM’s proposal will ensure competitive outcomes that conform to the actual reliability needs and fundamentals of supply and demand.

“If we failed to act today, the rate impact of this error would be $24/month for the average customer,” Chairman Willie Phillips said in a statement. “This substantial burden would fall disproportionately on the Delmarva Peninsula, where the average weekly wage of workers is $1,170 — $168 below the national average — and whose ratepayers in Delaware, Virginia and Maryland are among the least able to absorb such dramatic bill increases. This is not only the just and reasonable outcome, it also happens to be the right thing to do.”

But acknowledging the controversy over PJM’s request, Phillips also announced the commission will hold a forum to consider potential changes to the RTO’s capacity market. “The continuing disputes and frequent complaints about how PJM operates its capacity markets from an array of stakeholders throughout the region merit a general review outside the constraints of a particular proceeding,” the commission said. The forum has not yet been scheduled.

PJM said in a release following the commission’s order that it will post the Base Residual Auction results on Feb. 27. The RTO sought the rule changes through separate Federal Power Act Section 205 and 206 filings Dec. 23, with the latter made to offer the commission expanded flexibility.

The order rejected challenges by generation owners who said the tariff change violates precedent against retroactively changing rates and sends inadequate price signals for additional capacity required for reliability. The protesters also said the change would upset transactions made based on the reliability requirement, which is published months ahead of the auction. (See Generators Oppose PJM Filing to Change Capacity Auction Parameters.)

Protesters also argued that PJM’s tariff required it to close the auction and post the results as soon as possible, granting no discretion to hold the auction open awaiting an order from FERC.

‘Mismatch’ in Capacity Resources

PJM announced Dec. 21 that it would delay the release of the 2024/25 BRA results because of a “mismatch” between the capacity resources included in the calculation of the reliability requirement for the DPL-S LDA and the resources that entered into the auction. In small zones like DPL-S — particularly one with a higher winter load that does not align with solar output — disproportionately large generators or intermittent resources can cause the reliability requirement to increase to account for the transfers needed when those units are not available. (See Capacity Auction ‘Mismatch’ Roils PJM Stakeholders.)

When those resources push the reliability requirement higher, but those generators are not entered into the auction, PJM argued, it results in an artificial inflation of capacity prices for the LDA.

This would have led to capacity prices in DPL-S being four times higher than in 2023/24. In its comments supporting PJM’s proposal, Old Dominion Electric Cooperative said the existing rules could lead to cost increases of up to $144 million, while the Maryland Office of People’s Counsel estimated it would constitute an increase of $24/month for the average consumer.

Order Sides with PJM

Contrary to challenges that PJM’s proposal ran afoul of the filed rate doctrine and rule against retroactive ratemaking, FERC said that where the rates in question are a set of procedures, those operations can be revised “at least up until that point at which the obligation is actually incurred.”

“Protesters point to no precedent in which a change to a rate or non-rate term has been determined to be retroactive before a transaction has been made pursuant to it,” the commission said.

FERC rejected a request to allow generators to alter their capacity offers in response to changes to the reliability requirement. The commission noted that PJM and its Independent Market Monitor argued that competitive capacity offers should not account for demand and so should not be affected by the reliability requirement.

Protesters also stated that changing the parameter would impact bilateral transactions made before the opening of the auction. In its protest, NRG Energy (NYSE:NRG) stated that it had made “irreversible commercial decisions,” including rejecting capacity purchase offers, because it expected the reliability requirement would produce higher prices.

The commission noted that it has rejected proposals — at the cost of significant financial hardship — to preserve the stability and predictability in the markets. In this case, however, the balance favored of PJM’s proposal, it said.

“Accordingly, weighing the totality of the evidence before us, we conclude that the benefits associated with accepting the tariff revisions for the 2024/25 BRA outweigh any disruption to settled expectations that may exist on this record,” the commission wrote.

Danly Dissents

In a lengthy dissent, Commissioner James Danly predicted that the order will be challenged and struck down by the courts. He said the majority has distorted the filed rate doctrine, precedent formed by the commission and courts and the functioning of FERC-jurisdictional markets. He argued that the commission’s order has the effect of defining the filed rate for a capacity auction to be set after RTOs have unilaterally decided they are happy with results.

Likening the commission’s approval to a casino that allows the rules to be changed after the cards are drawn, Danly said the order is a misguided attempt at protecting consumers, which will be outweighed by the costs of market dysfunction as participants and investors lose confidence.

“The house saves a bit of money on one hand, but no one ever plays blackjack at the Federal Energy Regulatory Casino again. That is this case. The only difference is that the capacity market is not a game but rather the mechanism by which we ensure sufficient generation resources are built and maintained to keep the lights on,” Danly wrote.

He pointed to an affidavit by former FERC Chair Joseph Kelliher in support of the PJM Power Providers’ protest.

“Instead, despite what … Kelliher warns in the record, the majority ‘not only ignore[s] the limits that the FPA places upon it but also upwards of 100 years of court precedent’ by approving a plainly retroactive rate change that will almost certainly be overturned by the appellate courts in ‘a stinging and embarrassing court defeat,’” Danly wrote.

Christie Applauds Forum

Commissioner Mark Christie concurred with the order, saying that the auction’s outcome for DPL-S cannot be considered just and reasonable based on the cost estimates from PJM, ODEC and the Maryland OPC.

While he supported PJM’s proposal to fix the issue at hand, Christie said a wider discussion about the functioning of the RTO’s capacity market needs to be had and applauded the order’s announcement that a forum would be opened on the subject.

“As I wrote in my concurrence just last week to PJM’s Quadrennial Review filing, the elephant in the room must be addressed: whether PJM’s capacity market construct can still ensure sufficient power supplies to deliver reliability at just and reasonable rates,” Christie said. (See FERC Approves PJM Quadrennial Review.)

The Electric Power Supply Association slammed the ruling.

“When properly designed and administered, there is no question the competitive electricity markets deliver better outcomes than a cost-of-service monopoly model,” EPSA CEO Todd Snitchler said. “Yet this decision is another in a growing list where FERC actions undermine the workability and value proposition of markets only to then raise concerns about whether parties would be better off returning to a cost-of-service regime where, naturally, regulators would have more say over the decisions of market participants’ investments and decisions.”

“Looks like FERC will put everything on the table regarding PJM’s capacity market,” Tom Rutigliano, senior advocate for the Sustainable FERC Project, tweeted regarding the promised forum. “And it’s hard to not see this as a proxy trial for capacity markets in general.”