Entergy has asked FERC to exclude some of its power plants from rules contained in MISO’s new availability-based accreditation method, warning that without exemptions, it risks a potential capacity shortfall in Mississippi.
The utility filed a waiver request last week on behalf of its Mississippi and Arkansas subsidiaries, which claim that if a 24-hour startup exclusion is applied to certain generators under the RTO’s new accreditation method, it could set off capacity deficits in the state across multiple seasons (ER23-1140).
Entergy (NYSE: ETR) said its Mississippi and Arkansas arms “are facing dramatic decreases in the capacity accreditation of the resources due to the application of MISO’s new accreditation methodology.”
It requested three-year exemptions from historical startup times being used in accreditation for the 738-MW gas-fired Gerald Andrus Power Plant in Mississippi; its partial ownership interests in Units 1 and 2 of the 1,678-MW coal-fired Independence Steam Electric Station in Arkansas; and its majority interest in Units 1 and 2 of the 1,800 MW coal-fired White Bluff Steam Electric Generating Station in Arkansas.
FERC last year gave MISO permission to conduct four seasonal capacity auctions and apply a seasonal accreditation based primarily on a thermal generating unit’s performance during tight system conditions. The expected and historical tight conditions are dubbed “resource adequacy hours” and represent periods when resource availability is less than 25% of operating margin.
The grid operator’s 2023-24 capacity auctions in April will be the first to get seasonal treatment and use the availability-based accreditation. Its previous method deducted forced outages from installed capacity values.
With the commission’s approval, MISO will treat offline resources that historically take longer than 24 hours to start up as unavailable during resource adequacy hours. In those cases, the RTO will reduce accreditation accordingly.
The 24-hour cutoff has Entergy concerned. It said if the rule is applied as written to its three plants, it will have a “material effect” on capacity values through mid-2026. The utility said the accreditation rule could cut capacity values by 25% at Gerald Andrus and by 27% at White Bluff’s Unit 2.
Entergy said it has conducted field verification at the plants and adjusted startup times to less than 24 hours. It said if it secures the waivers, accreditation values for the plants will be a “more reasonable estimate of the [resources’] expected availability.” It also said startup times at Gerald Andrus, Independence and White Bluff “were already only slightly above 24 hours” and that it fine-tuned the startup times in good faith to protect customers from expensive capacity prices.
The utility asked FERC for expedited treatment by March 7 before the seasonal auctions take place “to limit the potential for irreparable harm.”
MISO has taken no position on Entergy’s filing.
Entergy made the filing a day after FERC rejected its request to annul the new accreditation. It had argued that an accreditation hinging on generator availability during a small set of hours will produce volatile and difficult-to-predict results year-over-year. (See FERC Affirms MISO’s Seasonal Auctions, Accreditation.)
Though FERC upheld MISO’s accreditation design, Commissioner Allison Clements logged dissent, criticizing the 24-hour threshold as too generous to be effective. She said the grid operator’s decision to credit resources that take up to a full day to start up will see MISO extending credits to resources that can’t respond in time and are unlikely to be helpful during reliability issues.
The race to clean up the nation’s transportation sector by ending its reliance on the internal combustion engine includes a dark horse that could be a contender as the best technology for heavy long-distance trucking: a hybrid diesel engine (H2ICE).
Modified to burn hydrogen, the H2ICE has become the focus of active research and development by engine builders globally. It has also garnered the interest of governments because such an engine could sharply and cheaply reduce carbon emissions within a decade.
In such an engine, the hydrogen replacing a large percentage of diesel fuel would produce more water vapor than carbon dioxide.
The U.S. Department of Energy’s Vehicle Technologies Office (VTO) has been focusing on the creation of diesel-hydrogen hybrids, and several federal laboratories are involved in research to develop the technology.
The current industrial research and development efforts to convert diesel engines from an oil-based fuel to hydrogen is unprecedented. | DOE
“Hydrogen-fueled engines have several favorable attributes, including the use of existing engine platforms, which means we can use existing manufacturing infrastructure,” Gurpreet Singh, manager of the VTO’s Advanced Combustion Systems and Fuels Program, said in remarks opening a DOE webinar Wednesday focusing on H2ICE development.
H2ICE systems are also under development to replace conventional diesels in freight locomotives because existing fuel cells are inadequate for locomotive use and battery systems would be too expensive. Two federal labs are involved with locomotive products manufacturer Wabtec. (See Hydrogen-burning Locomotive Focus of New Federal Research.)
A massive deployment of H2ICE-powered Class 8 tractor-trailer trucks would also accelerate the development of a national hydrogen fueling system at existing truck stations throughout the interstate highway system.
Gurpreet Singh, DOE | DOE
That hydrogen network would then be in place for fuel cell electric heavy trucks as they are developed, Singh said.
H2ICE offers something fuel cell electric systems or battery-electric systems currently cannot: engines that do not contain any imported or exotic rare-earth metals and are capable of producing a lot of power by combusting hydrogen that does not need to be pure, as it must be for use in a fuel cell.
H2ICE technology also inherits well developed industrial supply chains and a century of manufacturing expertise backed by already trained mechanics.
In contrast, fuel cells large enough to replace the 15-liter diesel engines in Class 8, over-the-road rigs have not been fully developed, and battery-electric heavy trucks, though being manufactured in small numbers, have two problems: battery weight that reduces total freight capacity, and the need for massive electric charging stations, reducing their current range.
“Why bring another technology to the carbon-neutral portfolio? The reason is that the mixed scenario is likely the lowest-risk, fastest and most cost-effective pathway to carbon neutrality,” Ales Srna, an engineer at Sandia National Laboratories, said in opening the webinar.
He added that H2ICE technology could benefit early adopters because the engines could initially use blends of natural gas and hydrogen. And he argued that the technology could be retrofitted to some existing diesels as the hydrogen fuel injection systems continue to be developed.
Noting that fuel cell technology is more developed currently than hydrogen-diesel hybrid technology, Srna said H2ICE systems could arguably become more efficient and less costly to operate than fuel cell vehicles in severe service applications, such as excavating equipment in which the engine is under a constant heavy load.
Several current studies have concluded that fuel cells would be a better technology than H2ICE in “smaller, lower-power applications or where noise and emissions are key factors; for example, in urban environments,” he said. But in heavy-duty applications such as long-haul trucking, the H2ICE would be less costly than a fuel cell initially and a contender as less costly in total cost of ownership compared to a truck powered with a fuel cell.
Srna said federal legislation enacted to decarbonize the nation’s transportation system excluded more funding for H2ICE systems, unlike European programs, which allow for hydrogen combustion as a zero-emission technology. That appears already to have led to the development of extremely efficient, and clean-burning, H2ICE engines for heavy trucking in Europe, he said.
“Current emissions legislation [standards] is not a challenge for some prototypes and some demonstrators on the road,” he said of the early European hydrogen-diesel hybrids already being road tested. “And they may be compliant without any after [combustion] treatment, which significantly reduces the cost of ownership.”
The Hydrogen Shot
Cost is another issue that could give new hybrid diesels an advantage over fuel cell or battery trucks.
Ram Vijayagopal, the manager of vehicle technology assessment at the Argonne National Laboratory, said DOE’s 2030 target for affordable fuel cell and battery technologies for vehicles is, by design, very aggressive and a reminder that current costs are too high. But the low-cost targets may not be achievable in the envisioned time frame.
“There are uncertainties associated with those targets,” he said, reminding the audience that DOE’s parallel “Earthshot” mission to develop the technology to produce hydrogen at $1/kg by the end of the decade is crucial if fuel cell vehicles are going to be economically viable. (See Granholm Announces R&D into Green Hydrogen as 1st ‘Energy Earthshot.’)
Ram Vijayagopal, Argonne National Laboratory | DOE
Achieving that price for hydrogen will also require continued development of electrolyzers to produce hydrogen more efficiently than it is produced today from natural gas. (See Competitive Green Hydrogen Could be Available by 2025.)
“We saw that the diesel engine can be adapted to burn hydrogen, and this gives us a way to quickly migrate to a hydrogen fuel-based transportation system. Hydrogen ICEs can be a bridge or backup,” Vijayagopal said.
The Argonne team, in consultation with industry, modeled several future truck engine systems, including the H2ICE and a fuel cell-battery hybrid power system, in which a smaller fuel cell is used but backed up by a battery to enable the truck to handle grades without having to run a larger fuel cell all the time.
The models also varied the cost of hydrogen as well as diesel fuel over time. And the modeling included comparisons of load-carrying abilities and distances traveled.
Overall, the modeling predicts that by 2030, the H2ICE performs better than conventional diesels in medium-duty applications, a use that researchers had not initially investigated.
Overall, the multiple scenarios produced by the modeling point to the H2ICE as a key technology, Vijayagopal said.
“We know that if all these [DOE] technology targets are met, fuel cells will be viable by 2030, and hydrogen ICE has the ability to provide that backup or to be a bridge technology until fuel cells become economically attractive,” he said.
“This can de-risk the hydrogen infrastructure investments, and it can provide more users in a nearer term due to the possibility to retrofit or rebuild [existing] engines to be compatible with hydrogen.”
American Electric Power (NASDAQ:AEP) reiterated its strategy to de-risk the company and prioritize investments during the company’s quarterly earnings call Thursday with financial analysts.
The call came a day after AEP announced it has entered into an agreement to sell its 1,365-MW unregulated, contracted renewables portfolio in a transaction that will net the company $1.2 billion in cash. The portfolio includes 14 projects representing 1,200 MW of wind and 165 MW of solar in 11 states.
The transaction’s proceeds will be funneled into supporting the company’s regulated businesses. AEP plans to invest about $40 billion over the next five years in its regulated wires and generation business. It hopes to add 17 GW of new generation resources, with 15 GW of new renewable resources added over the next decade.
“We’re strengthening our focus on these regulated investments and de-risking the business through active management of our portfolio,” AEP CEO Julie Sloat said. “This transition allows us to add fuel-free generation. … At the same time, the $26 billion we plan to invest in our transmission and distribution systems over the next five years will help ensure the continued delivery of safe, reliable and affordable power to serve our communities.”
The transaction with IRG Acquisition Holdings, a partnership between Invenergy, Quebec state pension fund CDPQ and funds managed by Blackstone, is expected to close in the second quarter, pending regulatory approvals. AEP announced its intentions a year ago. (See AEP to Sell Unregulated Renewables Portfolio.)
The Columbus, Ohio-based company projects the transaction to result in a loss of between $100 million and $150 million for the quarter.
AEP reported fourth-quarter earnings of $384 million ($0.75/share), down from earnings of $539 million ($1.07/share) for the previous year’s quarter.
For the year, earnings were $2.3 billion ($4.51/share). A year ago, they were $2.5 billion ($4.97/share).
Sloat told analysts AEP is continuing to work “diligently” on completing the sale of its Kentucky operations to Algonquin Power & Utilities by an April 26 contractual deadline. The companies recently made fresh filings at FERC to add more customer protections. (See AEP, Liberty Utilities Try Again on Kentucky Territory Deal.)
“Our near-term focus remains closing on our two pending sale transactions,” Sloat said. “Once both transactions are complete, we plan to revisit the equity needs in our current multiyear financing plan.”
AEP reaffirmed its 2023 operating earnings guidance range of $5.19 to $5.39/share. Its share price closed Thursday at $90.71, an 11-cent loss from the previous close after a late rally.
OGE Energy (NYSE:OGE) saw earnings per diluted share drop slightly from 2021 as it did not benefit as much from the sale of its midstream natural gas business, the company said during its fourth-quarter earnings call Thursday.
The firm brought in $3.32/diluted share in 2022 compared to $3.68/diluted share in 2021, but its regulated electric company, Oklahoma Gas & Electric, brought in more money, contributing $2.19/diluted share, up from $1.80 in 2021.
OGE still had some earnings from its natural gas business in 2022 despite its sale closing in December 2021, but going forward it is going to be a pure-play electric company, CEO Sean Trauschke said.
“My message to you is this, we’ve certainly got this, and our sustainable business model provides numerous opportunities from driving load growth, to grid investments and generation for many years to come,” Trauschke said on his firm’s earnings call. “We are mindful of ensuring a smooth customer impact and delivering consistent growth.”
The winter storm at the end of last year led to a lot of “discussion” in the utility industry, but OG&E made it through “Elliott” without issue because of the firm’s weather hardening, he said.
“I’m very proud of our team’s work every day, particularly during the weather extremes we experience here in Oklahoma and Arkansas,” Trauschke said. “We continue our grid weather-hardening investments that deliver great results for customers.”
The firm built seven new substations, upgraded another nine and added 65 miles of transmission lines last year to better serve its customers and keep up with demand growth, he added.
“Our communities maintain strong unemployment rates and continue to attract expanding and new businesses that our low rates help secure,” Trauschke said. “Our load forecast for 2023 continues to keep pace with the outstanding growth we’ve experienced over the last two years, and our long-term load forecast remains strong as our service area continues to grow.”
The firm saw weather-normalized load growth of 3.1% in 2022, which comes on top of 2.4% growth in 2021, CFO Bryan Buckler said.
“This back-to-back expansion of load is remarkable and indicative of economic strength in Oklahoma and Arkansas,” Buckler said. “The biggest driver of load growth is coming from the business sector with a variety of companies contributing, including those in data mining, agriculture and manufacturing.”
Commercial load shot up by 12.2% in 2022 compared to a year earlier, and it is now about 15% above 2019, pre-pandemic levels, he added.
The load growth for 2023 varies depending on how much data mining for cryptocurrencies expands in OG&E’s footprint. Without any growth from that industry, load growth would be just about 2.5 to 3.5%, but with it, growth could be 4 to 5%. Focusing in on commercial load for 2022, OG&E is forecasting growth without data mining expansion of 8 to 9%, but it could hit as high as 15% with expanded data mining.
The firm is also participating in the HALO Hydrogen Hub — a joint effort between Arkansas, Louisiana and Oklahoma, in which OGE is a stakeholder — which is seeking federal funds under the Infrastructure Investment and Jobs Act to produce hydrogen.
“Additionally, OG&E is competing for two [Department of Energy] grants as part of the IIJA for grid resilience and smart grid,” Trauschke said. “After assessing our initial submission, DOE encouraged us to submit full applications.”
The difficult prospect of building a new industry rapidly and well with few past examples for guidance was front and center on Day 2 of the U.S. Department of Energy’s Floating Offshore Wind Shot Summit.
Thursday’s sessions ranged from developing technology to cutting costs to being considerate of the ocean’s ecosystems and other users. (See related story for Day 1 coverage, DOE Launches West Coast OSW Transmission Study.)
One set of panelists examined the question of whether to start building floating offshore wind (FOSW) farms now with the imperfect technology that exists today, or wait years until it can be improved, if not perfected.
The consensus was that it needs to be done now, if not to meet President Biden’s 15-GW-by-2035 goal, then because of the critical need to address global warming now, not later.
But the first generation of floating wind installed and the transmission infrastructure to support it need to be future-compatible, several panelists said.
Factoring in the priorities of the Biden administration and the numerous stakeholders represented by speakers Thursday, the scale of the challenge becomes apparent: These floating wind farms need to be built relatively soon by a well paid unionized workforce that does not exist, drawing on a supply chain that does not exist, using U.S.-built vessels that do not exist, without harming any ecosystems, while ensuring that disadvantaged communities are the first to benefit from all aspects of the process.
And the projected cost of electricity that they will produce has to drop by 70%.
Build, Research or Both?
Mike Olsen of the U.S. Department of Energy’s Advanced Research Projects Agency – Energy (ARPA-E) said an informal conversation at the agency gradually centered on one of the central considerations to FOSW planning: “Should we use existing technology to do this, or should we wait 10, 15 years to let technology advance to the point where we can get there more efficiently?”
Others have raised such questions about clean-energy goals set out by various state and federal leaders, he said.
So he threw it out again: “Do we continue to invest in new innovations to reach those goals, or do we take existing, proven technologies and scale them so that we can reach economies of scale?”
Aaron Smith, of floating wind firm Principle Power, said it must be both.
“You can’t wait to have technology that is absolutely perfect, representing a mature industry,” he said. “Also, we have technology now that is suitable for deploying commercial-scale floating wind farms that get us on the path to a full cost parity with the other costs of generation.”
Developing offshore wind is in many ways an effort to successfully marry parts of the onshore wind and offshore oil and gas industries, all of which have a decades-long record of success, he added.
Leif Delp of Equinor said the continuing drive to make bigger and more powerful turbines is important. “The scale of the turbine is really the main mover for reducing the cost, so we need bigger turbines for sure.”
That said, there is likely a size beyond which turbines will be too expensive to install, operate and maintain, Delp added, because of the cost of maintenance.
Adrienne Downey, of floating wind developer Hexicon, said there just isn’t time to wait for new and better technology.
“I don’t think we have the luxury of waiting for a cost decline,” she said, “first and foremost because of the existential crisis of climate change; and second, the cost decline is not going to happen unless we do the hard work of deployments, working through the technology advancements, doing both simultaneously.”
Downey has previously compared floating wind to the Ford Model T, which became the first affordable automobile through efficient mass production, and she repeated the analogy Thursday.
Supply chain and infrastructure growth are critical, along with cutting costs and boosting yield, she said. “We need to look at this as an ecosystem; it’s the scale that matters.”
Downey said the solar and onshore wind industries overcame their growing pains by focusing on workhorse models that could be scaled and serialized.
About two thirds of potential wind power development areas off the U.S. coast are in water too deep to use fixed-bottom turbines. | NREL
Habib Dagher, executive director of the University of Maine’s Advanced Structures & Composite Center, is managing a team of 45 engineers working toward his state’s goal of building out offshore wind — which, due to the depth of the Gulf of Maine, will need to rely on floating technology.
The technology is coming into place and the state is seeking permission to place a small-scale research array to test it. “We have a climate crisis that we’re in, and therefore we need to move forward now with the technologies that we have,” Dagher said. “At the same time, nobody can put technology in a box; we’re going to continue to innovate.”
Maine’s goal is to not only decarbonize its electric grid but to create a center of innovation for the nascent floating wind industry, and to build some of the components locally. This attempt to vector benefits to local communities is central to the idea of equity in the energy transition, Dagher said.
The concrete hull technology Maine has developed for floating offshore turbines is an adaptation of technologies used to build bridges for the last 40 years, Dagher said, and it can be fabricated locally.
“Essentially, we’re turning bridge builders into hull builders,” he said, “and what that does is allows communities across the country and the world to actually reap the benefits of producing these technologies locally.”
Ralph Torr of Offshore Renewable Energy Catapult said the technical and economic analysis his firm has done for a group of floating wind projects showed that technology development would be important in the long term.
“Innovation is important,” he said, but “in the short- and medium-term, it’s actually the scale of deployment and ramping up strong, steady growth that will really allow cost reduction.”
Learning rates are important, Torr said, and it is an unsafe assumption that the industry will learn as much and as quickly as possible just through a flurry of construction.
“The early projects are going to play a key role in forming learning within the sector as well,” he said.
“So I guess here from the U.K., looking across the U.S., I just think it’s really important that you guys create these mechanisms that allow the technology to develop as the project develops to share learning and make sure the industry can grow in a strong but sustainable way.”
Also Noted
Other points made by speakers Thursday:
Joel Cline of the National Ocean and Atmospheric Administration said improvements in forecasting — focused in windows of space and time as close as 3 km and 15 minutes — will boost the efficiency of offshore wind operations. But knowledge about the atmosphere over the ocean still is not as broad as over land.
Georges Sassine of the New York State Energy Research and Development Authority said New York has begun work to create over the next two years a new offshore master plan that will include floating wind turbines. New York currently has more gigawatts of offshore energy in its development portfolio than any other state, but all of it is fixed-bottom turbines.
Mario Garcia-Sanz of ARPA-E said the floating wind industry will have to abandon sequential planning; the many factors involved in the operation of a floating turbine need to be co-designed.
Sassine and Garcia-Sanz said public funding is indispensable at this point. Such investments are too risky for the private sector, Garcia-Sanz said. The private sector is good at adopting and scaling proven technology, Sassine said, but government can play a key role in bringing the technology to market-ready status.
The California Public Utilities Commission on Thursday ordered load-serving entities under its jurisdiction to procure an additional 4 GW of clean energy resources by 2027, adding to the record-setting 11.5 GW of procurements it ordered less than two years ago to bolster reliability and meet environmental goals.
“This additional procurement is necessary as electric demand is projected to further increase in the coming years and the accelerating impacts of climate change are creating new demands on our electric resource mix,” CPUC President Alice Reynolds said.
The additional procurement is part of the state’s massive buildup in renewable and zero-emitting resources as it tries to meet its 100% clean energy mandate by 2045 while avoiding repeats of the energy emergencies it experienced during the past three summers, including the rolling blackouts of August 2020. (See Calif. Must Triple Capacity to Reach 100% Clean Energy.)
The proposed decision adopted Thursday includes electricity resource portfolios for CAISO to use in its 2023/24 transmission planning process. The ISO updates its 10-year transmission plan annually.
The CPUC’s base-case portfolio anticipates the state will need 69 GW of new resources by 2033 and another 16 GW of new resources by 2035 to meet its environmental goals while maintaining reliability.
The additional 85 GW would be “on top of the existing resource mix on the electric grid of approximately 75 GW. This is more than a doubling of nameplate capacity on the system within 12 years,” the decision by Administrative Law Judge Julie Fitch says.
The base-case scenario includes 39 GW of solar and 28 GW of battery storage by 2035. It projects adding 3,900 MW of in-state wind, 4,800 MW of out-of-state wind and 4,700 MW of offshore wind in Northern and Central California.
The decision also recommends that CAISO study a 75 GW sensitivity portfolio that would add 13.4 GW of offshore wind. The portfolio “is designed to refine and update transmission capability and upgrade assumptions relevant to offshore wind resources,” it says.
In June 2021, the CPUC ordered load-serving entities — including Pacific Gas and Electric, Southern California Edison and San Diego Gas & Electric — to procure 11.5 GW of new clean-energy resources by 2026. It was the largest single procurement order in state history and followed a series of smaller procurement orders that began in 2019 and increased after the 2020 blackouts. (See CPUC Orders Additional 11.5 GW but No Gas.)
“This additional procurement for 2026 and 2027 is required for several reasons … [including] updated load forecasting from the California Energy Commission that suggests that electricity demand is increasing and will continue to increase compared to when [the 11.5 GW was ordered],” Fitch wrote in Thursday’s order.
She also cited the “increasing and accelerating impacts of climate change,” the “likelihood of some additional fossil-fueled generation resource retirements that were not anticipated at the time” and the “likelihood that some delays beyond 2026 in the procurement of long lead-time resources required by [the June 2021 decision] will be necessary.”
The latest decision postponed the procurement of long lead-time resources such as geothermal and long-duration storage from 2026 to 2028.
A number of parties to the most-recent proceeding expressed concerns that ordering another 4 GW could undermine the CPUC’s efforts to develop a “programmatic” approach to resource planning and keep the CPUC “stuck in a cycle of ad hoc, interim procurement orders,” the decision noted.
“A programmatic approach means moving beyond the CPUC’s current energy resource procurement order-by-order approach and setting rolling, ongoing requirements for LSEs [load serving entities] to meet,” the CPUC said in a fact sheet on the effort, called the Reliable and Clean Power Procurement Program.
The CPUC said it had to address reliability concerns before that program is ready.
“As much as we would like to agree … that we should focus on development of a programmatic approach to procurement, we also are convinced that we cannot wait for that larger process to be complete before ordering additional procurement,” the proposed decision said. “In 2022, the electric system came very close to running out of resources, and it actually did run out in 2020. The system is much closer to a supply and demand balance than is comfortable for reliability purposes.”
Tight supply and high prices in summer, “coupled with the lengthy lead time needed for the development of new resources, persuade us that we need to order new procurement now so that the LSEs can have sufficient time to contract for and develop the resources in a timely and cost-effective fashion.”
Staff Proposing Bridging Solutions to ERCOT’s Long-term Market Redesign
ERCOT staff have prepared a draft of its early thoughts on a bridge solution to Texas regulators’ preferred market design, which is not expected to be implemented for at least three years.
Kenan Ögelman, ERCOT vice president of commercial operations, told the Technical Advisory Committee during its Monday meeting that staff will bring some proposed recommendations to the Board of Directors’ Reliability and Markets Committee meeting Feb. 27.
ERCOT plans to hold at least two workshops with stakeholders in March to solicit feedback and other alternatives. The board, responding to a directive from the Public Utility Commission, is expected to approve a final bridge recommendation during its April meeting.
Kenan Ögelman, ERCOT |
ERCOT
“We would very much like to hear from interested stakeholders on what we have,” Ögelman said. “I might have to pivot on what I just said, depending on the feedback that I get, so I just want to put that caveat out there.”
ERCOT on Wednesday filed several bridging solutions in the R&M’s background materials. They include a manually settled performance credit mechanism (PCM), mirroring the market mechanism the PUC has recommended to state lawmakers for their consideration. (See Texas PUC Submits Reliability Plan to Legislature.)
The PCM rewards generators in ERCOT’s energy-only market with credits based on their performance during a determined number of scarcity hours. Those credits must either be bought by load-serving entities or exchanged between them and generators in a voluntary forward market.
Staff say the manual PCM could be brought online late this year or early next year and that it has mechanisms that preserve both existing generation and new resources. They suggest the markets would gain experience with the “proposed future state.” However, the solution doesn’t create an obligation for LSEs to contract, and there would be no forward market; the performance credits’ value would be determined by ERCOT.
ERCOT is also proposing procuring more ancillary services and making payments to more market resources; modifying the operating reserve demand curve to achieve a one-in-10 loss-of-load expectation in 2026; deploy a backstop reserve service that secures a preset capacity amount based on bids; and capacity contracts to bring retired generators back to life.
The various options fall within three categories: solutions that address new investment and maintaining existing resources; those that address existing resources; and those that address new investment.
System Admin Fee up for Increase
Staff told stakeholders to expect an increase in the system administration fee next year, a message that was first relayed during last August’s board meeting. However, Controller Richard Scheel declined to provide an idea of how large the increase will be from the current 55.5 cents/MWh rate that has been in place since 2016.
“I hesitate to comment on the magnitude publicly before I discuss it with the board,” he said.
Scheel plans to take the same message to the Finance and Audit Committee’s Feb. 27 meeting. He’ll return to the committee and the board in April with proposed numbers.
Stakeholders had asked staff to provide them with more advance notice of admin fee increases during the 2016-2017 budget cycle. Lower Colorado River Authority’s Emily Jolly reminded Scheel that TAC’s ask included an idea of the magnitude of any increase.
“Telling our folks back at our shops that there’s going to be an increase and not being able to give them more detail is a little bit challenging,” she said.
Scheel said the final number is still under development. “We’re happy to talk about that more at the April meeting.”
Staff also said they have a path to restart the real-time co-optimization project, which has been on hold since mid-2021. They are evaluating the program’s scope and any gaps and overlaps in RTC-related protocols during the past two years.
Staff plan to complete a prospective budget and schedule for consideration by the June board meeting. The project still has a $51.6 million budget line item and a three-and-a-half-year timeline, but a new impact analysis will be conducted.
Members Approve 2023 Goals
The committee approved its goals for 2023 and those of the Retail Market Subcommittee as part of the combination ballot. TAC’s 19 goals include two late additions to review market design changes and improvements made since the February 2021 winter storm, and to support ERCOT staff in identifying, developing and implementing bridging solutions.
Members approved the ballot 28-0. It included two nodal protocol revision requests (NPRRs) and a single change to the Retail Market Guide that, if approved by the board, would:
NPRR1158: eliminate the weatherization-inspection fee’s sunset date and changes its invoicing period from a quarterly to a semiannual basis.
NPRR1159: provide needed references to the Retail Market Guide accounting for Texas standard electronic transaction processing options for municipally owned utility or electric cooperative service areas. The change is aligned with RMGRR171, which would add language establishing the mechanism that opt-in MOUs or cooperatives without an affiliated provider of last resort (POLR) that have not delegated authority to designate POLRs to the PUC would follow to provide their initial POLR allocation methodology; and updates and confirms such allocation methodology.
Interest is growing in bidirectional charging from vehicle batteries, but utilities and homeowners have different perspectives on the technology, speakers said during a webinar exploring the challenges of the systems.
Utilities are interested in vehicle-to-grid (V2G) charging, in which energy stored in the battery of an EV such as a school bus is harnessed to enhance grid reliability.
But homeowners are more interested in vehicle-to-home (V2H) charging, in which they can use their electric vehicles as a backup energy source for their homes in case of an outage, a Pacific Gas and Electric (NYSE:PCG) official said.
“We’ve seen vehicle-to-home be kind of a bit more of the leading reason why customers get into the V2X space,” said Chris Moris, principal for grid innovation at PG&E.
“I just don’t think the average consumer, when they buy an electric vehicle, they’re really thinking about the electric grid,” Moris said. “They’re thinking more about the reliability, how I can power my home.”
Moris was one of the speakers during a Feb. 8 webinar hosted by the California Energy Commission (CEC) and ElaadNL, an EV charging innovation center led by a coalition of Dutch grid operators. The collaboration between the CEC and ElaadNL is an outgrowth of a partnership between California and the Netherlands to work on climate goals.
Much of the focus of the webinar was grid codes: technical specifications regarding connections to the electrical grid.
“For many of you who need to connect to the electricity grid for charging infrastructure, you may think, ‘Well, how hard can it be?’” said webinar speaker Lonneke Driessen, director of standardization at ElaadNL.
But ElaadNL is increasingly getting feedback about the challenging and diverse grid codes, Driessen said, and “they may become an impediment to the rapid adoption of V2G.”
ElaadNL is working to “harmonize” grid codes as part of a three-year European project called SCALE (Smart Charging Alignment for Europe), aimed at advancing smart charging infrastructure and facilitating the mass deployment of electric vehicles.
V2G ‘Stalemate’
Another webinar speaker, Jeffrey Lu with the CEC’s vehicle-grid integration unit, discussed the potential for breaking through a “stalemate” related to grid codes and V2G charging.
In California, Rule 21 covers requirements for smart inverters used in vehicle-to-grid charging.
While Rule 21 includes a standard from the Institute of Electrical and Electronics Engineers, IEEE 2030.5, as its default, “the EV and charging industries have not adopted this communication protocol,” Lu said in his presentation. Instead, the industries have been using the Open Charge Point Protocol (OCPP) and ISO 15118 for communications between the charging equipment and the network, and the charging equipment and the vehicle, respectively.
The use of OCPP and ISO 15118 doesn’t prevent V2G in California in direct-current systems, which are typical when the inverter is part of the charging equipment. But the charger manufacturers may face additional certification burdens if using those standards, CEC’s Fuels and Transportation Division told NetZero Insider.
The situation is even more complicated for alternating current (AC) V2G systems, which are used when the inverter is on-board the vehicle. Rule 21 does not currently allow AC vehicle-to-grid charging, CEC said, and a certification pathway under discussion may require IEEE 2030.5, which the EV industry hasn’t adopted.
But Lu said during the webinar that efforts are underway to update OCPP and ISO 15118, which may help them meet Rule 21 requirements.
“These updates to OCPP and ISO 15118, paired with regulatory acceptance, can help to break through a V2G stalemate,” Lu said, describing his comment as a proposal for industry to explore.
In addition, Lu said, “the updates to globally aligned protocols may support greater V2G adoption, implementation and economies of scale.”
Cost Challenges
Moris at PG&E said vehicle-to-home charging presents additional challenges because the system can switch from on-grid operation to off-grid — or islanded — mode. He said the company is conducting pilot tests to study the island-transition issue.
“There’s this unique point in time where there’s a transition between on-grid to off-grid,” Moris said. “And that’s an area where our distribution planners need to see a little bit more on how that safely happens and how that energization works.”
In one pilot study, in partnership with General Motors and Ford, six homes were equipped with vehicle-to-home charging systems. Among five of the homes, the cost to install the systems ranged from about $10,000 to $18,000. Charging equipment accounted for 20% to 30% of the total cost; remaining costs were for wiring and panel upgrades.
For the sixth home, trench work was required, which brought the total cost to $58,000. That’s an issue that could crop up for other homes with 100-amp service, Moris said. Collaboration among utilities, car manufacturers and charging vendors is needed to bring V2H costs down, he added.
Moris also proposed that automakers and EV charging vendors collaborate to create lab space where interoperability can be tested. In addition, Moris said, pathways should be explored in which V2G capability is available by default.
“What would it mean for every car to support V2G out of the gate?” he said.
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.
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.”
