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November 4, 2024

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Shapiro Proposes Cap-and-trade, More Renewables for Pa.

Pennsylvania Gov. Josh Shapiro (D) on March 13 announced a new state energy plan he says will ramp up renewable production and save ratepayers $252 million while generating $5.1 billion in clean energy investments. 

The Keystone State is home to the nation’s first oil well and civilian nuclear reactor, but Shapiro’s office said it’s now falling behind other states in diversifying energy sources.  

Shapiro’s legislative plan aims to change that by establishing an emissions reduction program that will create a resilient electricity grid by 2035, attract more federal dollars, and support clean nuclear and low-carbon natural gas-fired generators. 

“From the very beginning, I have made clear that any energy policy supported by my administration must meet the three-part test of protecting and creating energy jobs, taking real action to address climate change pollution and ensuring reliable, affordable power for consumers in the long term,” Shapiro said in a statement. “My energy plan is built to do all three, making sure the first dollar goes to Pennsylvania ratepayers and ensuring Pennsylvania will continue to be a leader on energy for decades to come.” 

The governor is proposing the Pennsylvania Climate Emissions Reduction Act (PACER) to set up a cap-and-invest program that would take the commonwealth out of the Regional Greenhouse Gas Initiative and allow it to set its own cap on emissions. 

Seventy percent of PACER’s benefits would be returned to end-use customers as rebates on their electric bill — a higher percentage than any cap-and-trade program in the country. PACER also would support projects that cut air pollution, further reduce customer energy bills and invest in new job-creating clean energy projects, including carbon capture and storage, geothermal, and clean hydrogen. 

Shapiro also proposed a new renewable portfolio standard under legislation called the Pennsylvania Reliable Energy Sustainability Standard (PRESS), which builds on the state’s existing Alternative Energy Portfolio Standards (AEPS). It adds nuclear power and next-generation technologies like fusion and clean-burning forms of natural gas. 

PRESS would require Pennsylvania to get 50% of its electricity from a diverse range of resources by 2035, including 35% from clean resources such as solar, wind, small modular reactors and fusion; 10% from sustainable sources like hydropower and battery storage; and 5% from “ultra-low emission” forms of natural gas and other traditional fuels. 

PACER and PRESS are meant to work together to deliver the governor’s goals of protecting and creating energy jobs, cutting costs, and ensuring energy independence. Shapiro also wants legislators to create legal and regulatory frameworks around carbon capture and storage. 

Democratic Support, Republican Opposition

Shapiro’s office released a supporting statement from leaders in the state’s Democrat-controlled House of Representatives. 

“House Democrats are committed to reducing harmful greenhouse gas emissions while strengthening our economy and energy infrastructure, investing in our communities, and cutting costs for families,” their statement said. “Governor Shapiro has brought together many different sectors to explore how Pennsylvania can be a clean energy leader, and today’s announcement represents a step forward toward that goal.” 

While Democratic leaders in the Republican-run Senate also voiced support for the legislation, the body’s majority leader, Sen. Joe Pittman (R), came out against a cap-and-trade program. The senator has opposed the state’s membership in RGGI, the subject of a state court case. 

“It now appears the governor agrees with the Commonwealth Court’s ruling asserting a cap-and-trade program for electric generation is a tax on electricity and would require legislative approval,” Pittman said. “The governor correctly points out it is time we stop losing to Ohio, however, any cap-and-trade program applying solely to electric generation in Pennsylvania and not our competitors, does not fit the bill.” 

He added that any energy policy changes in Pennsylvania must prioritize generation, grid reliability and consumer affordability. 

Pennsylvania Public Utility Commission Chair Stephen DeFrank expressed support for the plan. 

“The PUC stands ready to work with Gov. Shapiro’s administration and the General Assembly to implement a comprehensive energy policy,” DeFrank said in a statement. “We are at a very critical point in energy transition for our state, our nation and globally and it’s incumbent upon all parties to work together to develop new solutions. The commission has implemented provisions of the AEPS Act for two decades, and we understand it is time to take the next positive and important step for this commonwealth, while giving our consumers a voice in the process.” 

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First Large US Offshore Wind Farm Complete

For the first time, a utility-scale wind farm is fully operational in U.S. waters. 

All of South Fork Wind’s turbines are sending electricity to the New York power grid. The announcement March 14 is a milestone for the struggling industry which advocates hope will help pave the way for many more. 

New York Gov. Kathy Hochul (D) and U.S. Interior Secretary Deb Haaland threw a supersized ceremonial light switch to mark the occasion. 

“Today is further proof that America’s clean energy transition is not a dream for a distant future — it’s happening right here and now,” Haaland said. 

Hochul said: “With more projects in the pipeline, this is just the beginning of New York’s offshore wind future and I look forward to continued partnership with the Biden administration and local leaders to build a clean and resilient energy grid.” 

N.Y. Gov. Kathy Hochul (D), left, and U.S. Interior Secretary Deb Haaland throw the symbolic switch on South Fork Wind, which announced March 14 that it is fully operational. | New York Governor’s Office

South Fork’s value is symbolic as much as electrical. 

It consists of a dozen turbines and a single offshore substation with a nameplate capacity of only 130 MW and a capacity factor of just 47%. 

But it is built, operating and wrapping up its commissioning process. 

Developers of the rest of New York’s offshore wind portfolio have canceled their offtake contracts in the past year, and developers canceled multiple projects or contracts north and south of New York, as well. 

Soaring construction costs in 2022 and 2023 made previously negotiated contracts with fixed power revenue untenable. First movers South Fork and Vineyard Wind 1 were far enough along in procurement when costs started rising that they could proceed to construction. 

The sector is attempting a rebound, albeit at a much higher cost to ratepayers. 

In the past few months, New York has tentatively awarded new contracts to two canceled projects and three new projects — the total capacity of all five would be 5,766 MW. (See Sunrise Wind, Empire Wind Tapped for New OSW Contracts.) 

New Jersey awarded two contracts totaling 3,742 MW in January. (See NJ Awards Contracts for 3.7 GW of OSW Projects.) 

A 6,000-MW joint solicitation by Connecticut, Massachusetts and Rhode Island will close March 27. (See Mass., RI, Conn. Sign Coordination Agreement for OSW Procurement.) 

Other bright spots include Revolution Wind, which will be five times larger than South Fork and starts offshore construction later this year; Vineyard Wind 1, which will be six times larger and is under construction; and Coastal Virginia Offshore Wind, which is on schedule for 2026 completion and would be 20 times larger than South Fork. 

Each of the states pressing offshore wind development hopes not only to decarbonize its grid but to create a new sector of its economy centered on offshore wind. 

The critical mass created by construction and operation of so many gigawatts of wind generation would help make that possible. 

Hundreds of Northeastern workers supported South Fork’s construction and hundreds in other regions were involved in assembling the first U.S.-built offshore wind substation. 

The turbines were assembled and staged at the State Pier in New London, Conn.; foundation components were completed at Rhode Island’s Provport; helicopters and surface vessels were based in Quonset Point, R.I.; Long Island firms fabricated the concrete mattresses to shield the underwater cables and install the underground cables; and a western New York firm fabricated specialized steelwork. 

Trade organizations played up the larger significance of South Fork Wind. 

Oceantic Network CEO Liz Burdock said: “The U.S. offshore wind industry now enters a new phase with its first operational commercial-scale wind farm. Now the question is no longer if we can, but how fast we can. A robust collection of U.S. supply chain companies and unions supported development of this project, and the entire U.S. industry should take huge pride in this milestone. The U.S.’s first completed commercial-scale project is providing clean, renewable offshore wind energy to communities and homes.” 

New York Offshore Wind Alliance Director Fred Zalcman said: “As we commemorate the completion of the South Fork Wind Farm, the first of many offshore wind farms to provide New York with clean, emissions-free electric power, let us always remember and replicate the formula that got us here. It takes visionary leadership from local, county and state elected officials; strong commitment and community engagement from civic leaders across the labor, business and environmental spectrum; innovative public policy in transitioning to newer and more sustainable forms of electric generation; and the skill, experience and investment capabilities of leading developers to orchestrate the design and construction of these massive infrastructure projects.” 

Not everyone cheered the announcement. 

Green Oceans President Elizabeth Quattrocki Knight said: “Today’s announcement from Governor Hochul of New York only motivates us to redouble our efforts to protect our oceans and the life they sustain. … Adding a fully activated offshore wind project to the grid will not reduce our reliance on fossil fuels. Instead, the intermittent electricity will cause natural gas plants to operate inefficiently. If we consider the overall carbon footprint of these projects coupled with the environmental harm they will inflict, it is irresponsible to proceed with offshore wind development.” 

South Fork Wind is a joint venture between Ørsted and Eversource, which is selling its share to Global Infrastructure Partners.  

It was approved in 2017 by the Long Island Power Authority. All other proposed offshore wind projects in the state have been contracted by the New York State Energy Research and Development Authority. 

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3rd Circuit Rejects PJM’s Post-auction Change as Retroactive Ratemaking

The 3rd U.S. Circuit Court of Appeals on March 12 vacated FERC’s order allowing PJM to revise a capacity market parameter for the DPL South zone after the 2024/25 Base Residual Auction had been conducted but before the publication of its results, ruling that it constituted retroactive ratemaking, a violation of the Federal Power Act’s filed-rate doctrine. 

PJM sought the authority to revise the locational deliverability area (LDA) reliability requirement for the zone, which covers the Delmarva Peninsula, after preliminary analysis of the BRA showed a nearly fivefold increase in capacity prices. (See P3 Challenges FERC Ruling on PJM Changes to 2024/25 BRA at 3rd Circuit.) 

The RTO attributed the increase to its practice of increasing the reliability requirement for small LDAs when it’s expected that solar resources or large generators could create an elevated need for imports to cover any outages of those resources. PJM had anticipated those circumstances to be present in DPL South, but the expected resources ultimately did not enter into the market, potentially leaving consumers with a sharp jump in capacity prices. 

PJM said the DPL South clearing price would have been about $393/MW-day under the status quo rules, while under the revised reliability requirement the zone cleared at $90.64/MW-day, an increase over the $69.95/MW-day price in the 2023/24 auction. 

The court ruled that PJM’s tariff mandates that auction parameters, including LDA reliability requirements, be posted prior to the auction being conducted. Pointing to precedent set in Oklahoma Gas & Electric Company v. FERC, the court wrote that a change is retroactive when it affects a past action that resulted in a legal outcome.

“The relevant inquiry is simply whether the tariff amendment alters the legal consequences attached to past actions,” the court said. “The tariff is clear that PJM’s calculation and posting of the LDA reliability requirement carried a legal consequence. … That simple instruction means what it says: The calculated and posted LDA reliability requirement cannot be altered outside of the limited circumstances enumerated in the tariff. Adjusting for certain resources’ lack of participation was not one of them.”

To change the DPL figure, FERC had approved PJM revising its tariff to exclude planned generation capacity resources from the calculation of an LDA’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 court limited its ruling to vacating FERC’s order as to the 2024/25 BRA, leaving the changes in place for future auctions. 

FERC argued in its order and before the court that because no capacity obligations had been assigned nor clearing prices determined, revising the parameter would not change any standing rates. Commissioner James Danly dissented from the 3-1 order, arguing the order was a retroactive rate change that would cause market dysfunction by undermining investor confidence in the predictability of the rules by which PJM runs its markets and how the commission regulates them. He predicted the order would be challenged and ultimately vacated by the courts (ER23-729). 

The commission also argued PJM tariff language allowing it to conduct the auction while “minimizing the costs of satisfying the reliability requirements” justified the change. But the court said that would hold the broad goal of minimizing costs over the specific requirements detailed in the tariff’s ordering of the steps in administering the auction. 

While there are circumstances under which the tariff permits PJM to revise the reliability requirement after the auction has closed, the court ruled those are limited and specifically enumerated exceptions. Applying tariff provisions allowing for correcting errors in the auction results would render specific provisions moot in favor of broad language, it said. 

The Electric Power Supply Association (EPSA) applauded the court’s decision, saying it preserves certainty in PJM’s markets. 

“EPSA is pleased that the court so quickly and definitively resolved the questions raised here: that the filed-rate doctrine bars FERC from changing auction rules after the fact. The importance of certainty cannot be overcome based on an arbitrary decision to change the outcome of an auction,” EPSA CEO Todd Snitchler said. “Looking ahead, market operators would be well served to operate consistent with the tariff. If changes are needed, market operators should apply them prospectively as has been the practice for decades and as the filed-rate doctrine requires. Doing so will only help to ensure participants’ confidence in the market’s operation.” 

A PJM spokesperson said the RTO is reviewing the decision and would not comment. 

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DOE Announces $750M in Clean Hydrogen Funding

The U.S. Department of Energy wants to reduce the cost of producing clean hydrogen and hydrogen fuel cells with $750 million in funding for 52 projects across 24 states, all aimed at advancing electrolysis technologies and manufacturing and recycling capabilities for clean hydrogen, according to a March 13 announcement. 

The goal for the projects receiving the awards from the Infrastructure Investment and Jobs Act (IIJA) is to ramp up manufacturing of electrolyzers to produce up to 1.3 million tons of clean hydrogen yearly and boost the production of fuel cells, which run on the clean hydrogen, by 14 GW yearly. 

The increased production of fuel cells alone could power 15% of the medium- and heavy-duty trucks sold in the U.S. each year, according to the announcement. 

Electrolyzers produce hydrogen by splitting water molecules into their components of hydrogen and water. For hydrogen so produced to be clean, or green, as it is commonly called, the electrolyzers have to be powered by zero-emissions renewable or nuclear energy.  

Medium- and heavy-duty trucks powered by hydrogen fuel cells are being rolled out as an alternative to electric trucks due to their comparative ease of fueling and potentially longer range. For example, the Nikola Corp. has a battery-electric heavy-duty vehicle with a range of 330 miles and a charging time of 90 minutes.  

The company’s fuel-cell model offers 500 miles of range and takes 20 minutes to refuel, according to Nikola’s website. 

The awards range from a low of $2.4 million for Georgia Tech Research Corp. to develop materials that will lower costs and boost efficiency of electrolyzers, to $50 million for Nel Hydrogen US, which is working toward fully automating electrolyzer manufacturing that, in turn, could improve electrolyzer design.  

As quoted in the announcement, Energy Secretary Jennifer Granholm said the new funding will propel “an American-led clean hydrogen economy that is delivering good paying, high quality jobs and accelerating a manufacturing renaissance in communities across America.” 

The IIJA allocates $1.5 billion for clean hydrogen and fuel cells, so this announcement represents half of that funding, with $500 million going to electrolyzers and $250 million to fuel cells.   

DOE sought funding proposals across six highly technical categories, such as “low-cost, high-throughput electrolyzer manufacturing” (eight projects, $316 million) in which selected projects “will conduct [research, development and demonstration] to enable greater economies of scale through manufacturing innovations.” 

The other categories are: 

    • Electrolyzer component and supply chain development (10 projects, $81 million) to support U.S. manufacturing and development needs for core electrolyzer components. 
    • Advanced technology and component development (18 projects, $72 million) to demonstrate new materials, components and designs for electrolyzers that can “enable cost reductions and mitigate supply chain risks.” 
    • Advanced manufacturing of fuel cell assemblies and stacks (five projects, $150 million) to support “RD&D that will enable diverse fuel cell manufacturers to flexibly address their greatest scale-up challenges and achieve economies of scale.” 
    • Fuel cell supply chain development (10 projects, $82 million) to “address critical deficiencies in the domestic supply chain for fuel cell materials and components.” 
    • Recovery and recycling consortium (one project, $50 million) to establish a consortium of industry, academia and national labs to develop new approaches to recovering and recycling of clean hydrogen materials and components. The consortium is being led by the American Institute of Chemical Engineers, with 15 other members.  

A map of the projects chosen to begin contract negotiations with DOE shows a heavy concentration of projects in New York and New England, but North Dakota, Kansas and Oklahoma each scored one project.  

Full-court Press

The Biden administration has bet big on clean hydrogen, which “is set to play a vital role in reducing emissions from our most energy-intensive and polluting sectors … such as heavy-duty transportation and industrial and chemical processes like steelmaking and fertilizer production,” according to the DOE announcement. 

Clean hydrogen, produced with excess wind, solar or nuclear and stored or put to other uses, is also being promoted as a potential long-duration storage technology. 

However, figures in a recent DOE report show that about 95% of the hydrogen produced in the U.S. today uses natural gas as a feedstock. The cost to produce clean hydrogen via electrolysis remains high ― between $5 and $6/kg versus $1 to just over $2/kg for hydrogen produced from natural gas or other fossil fuels. 

The latest funding announcement is part of the administration’s full-court press on clean hydrogen, which is widely seen as an emerging technology offering the U.S. an opportunity to show off its innovation chops and lead the global market. The IIJA also provided $7 billion for seven regional hydrogen hubs, announced in October, although two of the hubs plan to use natural gas with carbon capture and a third will use a mix of natural gas, nuclear and renewable energy. (See DOE Designates Seven Regional Hydrogen Hubs.) 

Another $1 billion from the IIJA will be used to build up market demand for clean hydrogen, while the Inflation Reduction Act provides a generous tax credit of up to $3/kg for clean hydrogen. (See DOE to Invest $1 Billion to Build Demand for Clean Hydrogen.) 

Environmental groups continue to express skepticism about hydrogen. After the hydrogen hubs’ announcement, some advocates called for a refocus on renewables like wind and solar, while others said using natural gas with carbon capture should be called “fossil hydrogen with carbon capture.” (See Hydrogen Hub Announcement Draws Praise and Scorn.) 

The 52 projects announced March 13 target some of the underlying manufacturing challenges in the clean hydrogen supply chain. For example, common electrolyzer components, called proton exchange membranes (PEMs), use both platinum and iridium, a byproduct of platinum mined mostly in southern Africa.  

The Mott Corp. in Farmington, Conn., is up for a $10 million award to develop nonplatinum group metals for electrolyzers. 

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NERC RSTC Briefs: March 12-13, 2024

Kelly Praises Committee as ‘Kitchen’ of ERO

SAN DIEGO — In her first address to NERC’s Reliability and Security Technical Committee since being named the committee’s board liaison last month, NERC Trustee Sue Kelly asked attendees at the committee’s first meeting of 2024 in San Diego to “bear with me” as she adjusts to her new role. 

Kelly, who previously served as the Board of Trustees’ liaison to the Standards Committee, likened the RSTC to the “kitchen” and the SC to the “front of the standards development house,” meaning the work of both committees is vital to maintaining the ERO’s reputation for “technical excellence.” 

From left: RSTC vice-chair John Stephens; Mark Lauby, NERC; NERC Trustee Sue Kelly | © RTO Insider LLC

“In many respects, you are NERC’s brain trust,” Kelly said. “You do the complicated but vital work that underpins NERC’s standards, guidance, white papers [and] assessments. The reliability issues we are dealing with now are incredibly complex, and we need all the gray matter we can get to apply to these challenges. So, we on the board very much appreciate the efforts that all of you dedicate to this work.” 

The RSTC’s next meeting will take place June 11-12 at Amazon’s headquarters in Seattle, and will be a joint gathering with the SC. Committee members will participate in person, while all others attend online. Its Sept. 11-12 meeting at the headquarters of Hydro-Québec in Montreal will be hybrid as well, and the final meeting of the year, Dec. 11-12, will be fully virtual. 

IBR, DER SARs to Receive Comments

RSTC members endorsed or accepted multiple draft standard authorization requests, reliability guidelines and white papers during their two-day meeting. 

The first SAR was brought to the committee by NERC’s Inverter-based Resource Performance Subcommittee (IRPS). NERC Senior Engineer Alex Shattuck told attendees the IRPS developed the SAR in response to FERC’s Order 901, issued in October, which directed NERC to develop rules addressing IBR data-sharing, model validation, planning and operational studies, and performance standards. (See FERC Orders Reliability Rules for Inverter-Based Resources.) 

The SAR would authorize NERC to update reliability standards FAC-001-4 (Facility interconnection requirements) and FAC-002-4 (Facility interconnection studies) to ensure that transmission operators, balancing authorities and reliability coordinators that identify IBR performance issues can work on corrective actions with generator owners. Members voted to accept the draft SAR and post it for a 30-day public comment period, to begin March 18. 

NERC’s System Planning Impacts from Distributed Energy Resources Working Group (SPIDERWG) brought forward the other SAR, intended to clarify the definitions of operational planning analysis (OPA) and real-time assessment (RTA) in the ERO’s glossary of terms to “explicitly include aggregate DERs as a component of both” definitions.  

SPIDERWG Chair Shayan Rizvi explained the goal of the SAR was to bring “enhanced clarity to situational awareness and [reduce] operational risk,” noting that “DERs have contributed to grid disturbance events” and that clarifying the definition would help grid operators identify and react more efficiently in emergency situations. Members voted to approve this SAR for a public comment period, also to start March 18. 

SPIDERWG, Other Groups Submit Papers

RSTC Chair Rich Hydzik | © RTO Insider LLC

The SPIDERWG also brought forward a white paper on coordination strategies between transmission and distribution entities and a reliability guideline to assist grid planners with needed studies of DERs’ impact on reliability. RSTC members accepted the white paper and approved posting the guideline for a 45-day comment period. 

NERC’s Probabilistic Assessment Working Group also brought a paper intended to help grid planners understand the reliability risks posed by extreme weather events, while the System Protection and Control Working Group submitted its paper on transmission relay loadability. The RSTC accepted both papers and agreed to solicit reviewers for two more papers from the SPCWG: one on evaluating IBRs’ compliance with existing standards, the other on transmission system phase backup protection.

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Drop in Wash. Carbon Price Spells Uncertainty for Budget, Gas Costs

Washington’s first quarterly carbon allowance auction of 2024 has thrown two new wrinkles into the economics of the state’s fledgling — and controversial — cap-and-invest program.  

First: The auction cleared at $25.76 per allowance. That’s sharply lower than clearing prices in 2023’s four quarterly auctions, which took a lot of blame for Washington’s high gasoline prices last summer.  

Second: The March 6 auction, results for which were announced by the state’s Department of Ecology on March 13, raised $135.5 million, setting a dramatically slower pace than is needed to reach the $941 million the state predicted it would collect in the first half of 2024.  

Last year the auctions cleared at $48.50 in the first quarter of 2023, $56.01 in the second, $63.03 in the third and $51.89 in the fourth. Those prices were significantly higher than predicted, and cap-and-invest critics blamed them for adding 21 to 50 cents per gallon to Washington’s traditionally high gas prices. 

Washington has always had some of the nation’s highest gas prices due to geographical and economic factors outside the cap-and-invest program. Average gas prices in the state are currently $4.22 per gallon compared with a national average of $3.40, according to AAA. 

High gasoline prices have led conservatives to back a November referendum seeking to repeal the cap-and-invest program. (See Wash. Cap-and-trade Opponents Advance Repeal Petition to Sec. of State.) 

Ecology Department spokesperson Caroline Halter said demand for allowances “remained strong” despite the sharp decline in settlement prices compared with the December 2023 auction. 

“As in past auctions, all available allowances were sold, and there were more bids than available allowances,” Halter told NetZero Insider in an email. An external auction monitor for the sales did not find any evidence of market manipulation and determined that the auction was conducted fairly, she added. 

Washington’s Office of Financial Management said the auction’s $135.5 million in revenue is $108-$110 million less than predicted. The state has raised $1.96 billion in cap-and-invest revenue since last year. 

The OFM noted five quarterly auctions remain in the budget biennium running from May 1, 2023, through June 30, 2025. These include two in June and September that run prior to the November referendum. Three more are scheduled for December, March 2025 and June 2025.  

With the November referendum being a factor in assembling a supplemental budget for July 2024 through June 2025, the state Legislature put language in its budget bills to keep $816 million in cap-and-invest revenue from being appropriated until Jan. 1, 2025, OFM spokesperson Hayden Mackley told NetZero Insider. Consequently, if cap-and-invest is repealed, that $816 million in appropriations would be rendered moot. 

“Regarding gas prices, OFM can’t speak to the effect of the auction on those — we don’t have any insight into or control over businesses’ pricing strategies,” Mackley wrote.  

Gov. Jay Inslee (D) spokesperson Jaime Smith added: “Even as allowance prices were relatively high throughout the fall and winter, gas prices fell to a two-year low, showing how difficult it is to infer direct impacts.” 

Washington is exploring joining the joint California-Quebec carbon market to help bring down auction prices. California-Quebec bid prices increased from $19 in 2021 to $41.76 last month, according to the California Air Resources Board. The results from last week’s auction mean that Washington’s allowance prices have now dropped below California’s for the first time. 

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Solar Growth has ERCOT Looking at Ride-through Rules

An expected tsunami of solar resources setting up shop in Texas has led to an immediate need for ERCOT to understand and set ride-through requirements for inverter-based resources (IBRs), according to a Texas energy expert. 

The Texas grid operator had more than 22 GW of solar capacity operational when 2024 began and expects that to exceed 30 GW by year-end, with more to follow. ERCOT has set numerous records for solar production this year, the most recent coming Feb. 19 at 17.2 GW. 

Two IBR-related voltage disturbances in West Texas in 2021 and 2022, dubbed the Odessa Disturbances I and II, have led to ERCOT working with stakeholders on a nodal operating guide revision request (NOGRR245) to improve the clarity and specificity of IBRs’ voltage ride-through requirements. The change would align the ISO’s rules with NERC reliability guidelines and the most relevant parts of the Institute of Electrical and Electronics Engineers standard for IBRs interconnecting with the grid. 

“One of the things that really added a sense of urgency to this issue was the fact that the projection for growth of solar in ERCOT was very significant,” Jewell and Associates principal Michael Jewell said during a Talk with Texas RE event March 12. “We’ve seen that kind of growth already happening since the Odessa events, and that growth is continuing. The need to address this issue has remained very high.” 

The guide change is tabled at the stakeholder-led Technical Advisory Committee meeting to allow for additional negotiations between ERCOT staff and clean energy developers. The NOGRR is expected to be taken up again during TAC’s March 27 meeting. (See “Stakeholders Continue Discussion of IBR Reliability Requirements,” Technical Advisory Committee Briefs: Jan. 24, 2024.) 

Under the rule’s initial requirements, all IBRs with a standard generation interconnection agreement executed on or after Jan. 1, 2023, would have to comply. All other IBRs would have to comply within 12 months of the NOGRR’s approval, with an extension of up to 12 months. 

“SCADA [supervisory control and data acquisition] data was not necessarily detailed enough to be able to catch what was going on,” Jewell said. “High-resolution data really became a focal point … and a real strong need for accurate inverter settings.” 

Stakeholders have pushed back against the timeline. They also have been concerned with issues regarding existing exemptions for ride-through requirements already in place and whether they will be repealed. 

“Stakeholders continued to point out that there have been multiple examples of grandfathering existing resources from new requirements that this was something that really should be considered,” Jewell said. 

Original equipment manufacturers (OEMs) of IBRs have said a limited pool of resources to retrofit existing IBRs could delay the time it will take to make the upgrades. Staff and stakeholders also are looking at alternative solutions for mandating testing requirements that have not yet been developed. 

“To say that there have been a lot of comments that have been filed with regard to 245 would be an understatement,” Jewell said, referring to the nearly five dozen comments submitted. “It’s a significant amount of data that’s been provided, and ERCOT has been wrestling with those and making some making some changes.” 

Jewell told his audience progress has been made to address issues at the facilities affected by the Odessa disturbances with software and firmware changes. ERCOT is expected to file another set of comments, after which the clean energy stakeholders will file their responses before the TAC meeting.

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WRI Webinar Examines How to Expand Grid-enhancing Technologies

With a major grid expansion on planning boards around the country, grid-enhancing technologies (GETs) will be key to getting the most out of current and future systems, experts said on a World Resources Institute webinar March 12. 

“We are increasingly relying on the grid to enable power-sharing between neighboring regions, to ensure good reliability, generally, but also during extreme winter events and as well as extreme heat events,” said WRI Senior Manager for Clean Energy Jennifer Chen. “We need to deliver low-cost clean energy to customers and support growing electricity demand from electrification, manufacturing, data centers, artificial intelligence, crypto-mining, indoor agriculture and the list really goes on.” 

GETs can get more power through existing transmission lines with operational tweaks or reconductor existing lines to greatly expand the number of electrons that flow through them. 

FERC must consider more than decarbonization in grid expansion; as an economic regulator, it needs to ensure the bulk power system can support the wave of demand, Commissioner Allison Clements said. 

“We need to figure out how to make easy, quick investments that can help us in the near term to modernize the grid, as well as working on medium-term and longer-term, more difficult investments, like the investment in new regional and interregional transmission,” Clements said. “I don’t think that any of the things you described are actually replacements for new transmission investment. But certainly, we have a toolbox of technologies and transmission options, cost options, market design options, and we should be trying to take advantage of all of them.” 

GETs have been shown to produce major benefits, but they face economic, operational and regulatory barriers. The utility industry does not have good incentives to make smaller investments that avoid capital spending. 

“Everyone knows that you should eat your broccoli, you don’t necessarily do it if there’s cake sitting there for you to enjoy,” Clements said. 

Many grid operators are not familiar with GETs and thus are hesitant to risk reliability on less-proven technologies, she said, adding that economic incentives and regulations need to be aligned so GETs are used more broadly than just as the subject of pilot programs. 

Another major barrier to deploying GETs is information asymmetry between regulated utilities and their regulators, said Connecticut Public Utility Regulatory Authority Chair Marissa Gillett. Like grid operators, regulators are wary of relying on new technologies. 

“State regulators, or different regions, often want to pilot something, even if it has been proven in another area of the country,” Gillett said. “And I think that can be very frustrating, particularly for proponents of new technologies.” 

Sometimes the desire to pilot makes sense, such as when a technology worked in a state with different regulations. But it also happens even when a technology has been proven to work in a state’s regulatory construct, she added. 

The Idaho National Laboratory has found that 118,000 miles of transmission lines nationwide could benefit from reconductoring, said Gilbert Bindewald of DOE’s Office of Electricity. 

“One of the aspects that I’m continually hearing is not only the economics, but given that these are multidecadal investments, how will these technologies continue to perform 20 years from now, 30 years from now?” he added. 

Multiple offices at DOE are working on research, development and deployment of GETs with the hope of showing the industry the technology’s reliability and resilience benefits, Bindewald said. That work includes testing different GETs by accelerating the aging process and using other tests to get a sense of their full lifetime of benefits, he added. 

In the Energy Policy Act of 2005, FERC got the authority to offer performance-based incentives that could be applied to GETs, but so far it hasn’t been used much, Clements said. The WATT Coalition and others have asked FERC to include GETs in its regional transmission rule and advance a notice of inquiry it launched on dynamic line ratings.  

“I think all three sitting commissioners currently have expressed a desire to revisit our transmission incentives policy,” Clements said. “I’m not sure all three of us have the same outlook for where that policy should go. From my perspective, we need to incent the hard stuff to build.” 

That would include GETs and harder-to-build transmission lines such as interregional projects, she added. 

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CAISO Wins FERC Approval for Subscriber-funded Tx Plan

FERC has approved a CAISO proposal allowing transmission lines outside California to join the ISO under a new subscriber-funded model that avoids allocating project costs to the ISO’s load-serving entities (ER23-2917). 

Under CAISO’s “subscriber participating transmission owner” (PTO) program, the developer of a transmission project not chosen in CAISO’s transmission planning process can solicit generation-owning customers to subscribe to service on a line designed to deliver energy into California. The project owner then can turn operational authority of the line over to the ISO, joining the balancing authority areas as a “subscriber PTO,” a category of owner ineligible to recover costs through the ISO’s transmission access charge (TAC) — the mechanism CAISO uses to bill load-serving entities for their transmission use.  

The plan, which CAISO’s Board of Governors approved in July 2023, is designed to help California draw on clean energy resources outside the state to meet its ambitious greenhouse gas reduction goals while alleviating financial risks associated with building new merchant transmission. (See CAISO Board OKs Plan to Admit Subscriber-funded Transmission Lines.) 

“The commission has long required a merchant transmission facility’s owner and its willing customers to assume the full market risk for the cost of constructing the facility and ensure that no captive customers are required to pay for the cost of the facility,” FERC wrote in the March 12 order. “Here, subscribers of the capacity on the subscriber PTO’s transmission facilities will be responsible for paying the entire cost of constructing those transmission facilities, and no transmission revenue requirement for the subscriber PTO transmission facilities will be included in the TAC.  

“Therefore, we find CAISO’s proposal to be consistent with the commission’s policy regarding cost recovery for merchant transmission facilities.”

The subscriber PTO program will require applicants to obtain approval from CAISO’s board to join the balancing area, execute a transmission control agreement, place transmissions assets and associated entitlements under the ISO’s operational control, and satisfy the requirements applicable to other PTOs.  

In exchange for funding the project, subscribers will receive scheduling priority on the associated transmission paths. Initial subscriber-owned generation interconnecting with CAISO through the subscriber PTO’s transmission will be studied through the PTO’s transmission interconnection process, rather than the ISO’s generator interconnection process. 

The program is open to existing transmission lines and those being planned or developed. 

Nonsubscriber Charges Prompt Protest

Protests filed with FERC against the subscriber PTO model focused on how those PTOs will be compensated when nonsubscribers use their lines.  

The proposal calls for CAISO to assess the TAC rate for nonsubscriber imports using the scheduling points associated with a subscriber PTO’s transmission facilities, while assessing the ISO’s wheeling access charge (WAC) rate for nonsubscriber exports and “wheeling-through” transactions at those points.  

At the same time, each subscriber PTO can develop a nonsubscriber $/MWh usage charge that cannot exceed the application TAC rate at the time the PTO files its charge for FERC approval.  

“Thus, while nonsubscribers will pay CAISO the current TAC or WAC, the subscriber PTO would receive an amount no greater than the TAC rate via the nonsubscriber usage rate accepted by the commission,” FERC noted in the order. “CAISO explains that, if the total TAC and WAC revenue contributed by transactions on the subscriber PTO’s facilities exceeds the total calculated nonsubscriber usage payment then the excess amount will be added back to the regional access charge for allocation to the other participating TOs besides the subscriber PTO.” 

When WAC revenue is insufficient to cover nonsubscriber charges, CAISO will draw on nonsubscriber TAC revenues to cover the balance before distributing those revenues to other CAISO PTOs. 

In a jointly filed protest, Pacific Gas and Electric and Southern California Edison complained that subscriber PTOs should not be compensated for nonsubscriber use of their transmission lines because those lines will be fully paid for by the subscribers. 

“As an initial matter, and contrary to protestors’ arguments, the commission has not held that a facility’s costs can be allocated to customers only following a determination that the facility is necessary for reliability, economic, policy or other reasons through the CAISO transmission planning process,” the commission wrote. “In any case, we disagree with protestors that compensation for nonsubscriber use of a subscriber PTO’s transmission facilities conflicts with the commission’s longstanding policy that a merchant transmission facility’s owner and its willing customers must assume the full market risk for the cost of constructing the merchant transmission facility, and that no captive customers are required to pay for the cost of the facility.”  

The commission declined to address the protestors’ concerns about how the nonsubscriber usage rate will be formulated, saying the issue was outside the scope of the current proceeding and best addressed in future proceedings dealing with rates proposed by subscriber PTOs. FERC also dismissed a request to sever the nonsubscriber rate provisions from the proposal and reject them. 

“Regarding protestors’ concerns that the TAC could increase as a result of the nonsubscriber usage rate, we find, based on the record before us, that the subscriber PTO model is unlikely to result in an increase in the TAC, and, should an increase occur, any such increase would not be due to the subscriber PTO recovering any of the costs for constructing the subscriber PTO’s initial transmission facilities through the TAC,” the commission found. It also noted that CAISO’s response to a FERC deficiency letter in January clarified that the nonsubscriber usage rate would be required to decline in line with any future reduction of the TAC. 

TransWest Request Denied

FERC rejected a request by TransWest Express for guidance on “a potential framework to determine the nonsubscriber usage rate,” saying the subject was outside the scope of the proceeding and reiterating that the issue would be addressed in future rate filings. 

The proposed TransWest Express project, a 700-mile line designed to carry 3,000 MW of wind energy from Wyoming to a CAISO interconnection point in Nevada, likely will become the first transmission facility to join the ISO under the subscriber PTO program. 

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NEPOOL Markets Committee Briefs: March 13, 2024

ISO-NE on March 13 presented the NEPOOL Markets Committee with additional results of the impact analysis for the RTO’s resource capacity accreditation (RCA) project, which looked at how changes to the resource mix would affect the seasonal distribution of shortfall risks. 

The RCA project is being developing in conjunction with structural changes to the timescale of the Forward Capacity Auction (FCA). The RTO has proposed a three-year delay of FCA 19 to develop and implement the changes. (See related story, NEPOOL MC Backs Further Forward Capacity Auction Delay.) 

In the initial impact analysis “base case,” ISO-NE estimated that loss-of-load risk is distributed 80% in the winter and 20% in the summer. (See NEPOOL Markets Committee Briefs: Feb. 6, 2024.) 

The sensitivity analyses presented to the MC included three scenarios: 

      • the addition of wind, solar and battery resources without corresponding resource retirements; 
      • the addition of the renewable resources accompanied by the retirement of oil-only capacity; and 
      • the addition of renewables accompanied by the retirement of coal capacity. 

The addition of renewables without retirements would be more likely to reduce the number of days with loss-of-load events in the winter than in the summer but would provide greater reductions in the duration of the events in the summer than in the winter, ISO-NE found. 

When coal capacity was retired, ISO-NE found increased risk of multiday loss-of-load events in the winter, shifting the region’s risk profile towards the winter, said Dane Schiro, the RTO’s principal analyst. 

Compared to the retirement of coal, retiring oil capacity “can be thought of as retiring proportionally more summer capacity than winter capacity” because of the model’s winter fuel constraints for oil resources, Schiro said. Therefore, the retirement of oil capacity shifted the overall risk profile toward the summer relative to the coal-retirement scenario. 

“The seasonal output characteristics of retiring and new resources are important to the seasonal risk split,” Schiro said, adding that the findings were in line with expectations. 

ISO-NE will present additional sensitivity results to the MC in April. 

Regional Differences in Gas Accreditation

Ben Griffiths, vice president of wholesale market policy at LS Power, made the case for the RCA updates to incorporate regional differences in pipeline gas availability in the winter. 

ISO-NE is planning to treat access to nonfirm gas as the same across the region, despite LS Power data showing that gas access varies significantly based on where generators are located on the pipeline system, Griffiths said. 

“Observational data, economic modeling and physical analysis all indicate that gas availability is location and fact specific,” Griffiths said. “A failure to reflect locational attributes will lead to inaccurate pricing for gas generators, worse reliability [and] potential premature retirement.” 

Gas units in Connecticut run “at a higher level than we would expect across a range of temperatures, and there is no appreciable temperature-dependent output deviation,” Griffiths said. “This suggests that the gas system is not constrained in Connecticut at any observed temperature.” 

In contrast, generation for some units in Maine and Massachusetts historically has been highly temperature dependent, although this temperature correlation can vary significantly unit to unit, Griffiths added.  

The accreditation of gas resources has been a major topic of the RCA project. ISO-NE has advocated for a “market constraint approach,” in which the RTO would limit the amount of nonfirm gas capacity it procures based on the region’s gas constraints while having gas-fired resources compete for capacity obligations. 

ISO-NE initially indicated it would not be able to design and implement this approach for FCA 19, but it said March 13 that if the proposal for an additional two-year delay of the auction is approved by FERC, it will prioritize implementing a market constraint approach in time for it. (See NEPOOL Markets Committee Briefs: Jan. 11, 2024.) 

Regardless of the approach ISO-NE takes, it must account for local differences, Griffiths said. 

Under the market-constraint approach, ISO-NE could create “a nested zone for Connecticut which has higher levels of fuel availability and is, in effect, unconstrained,” Griffiths said. LS Power’s proposal would not affect the total amount of accredited gas capacity and simply would change how the overall capacity of the fleet is distributed, he added.