FERC last week granted one of three claims against Public Service Company of Colorado (PSCo) in response to cooperatives’ complaints that they were charged $17.5 million in excessive gas costs during Winter Storm Uri in 2021 (EL23-21).
The commission said four PSCo customers (CORE Electric Cooperative, Grand Valley Rural Power Lines, Holy Cross Electric Association and Yampa Valley Electric Association) were able to prove they are entitled to review a baseload contract under the utility’s fuel protocols. It directed PSCo to make the contract available to the complainants, subject to a protective order.
The cooperatives said they were charged $17.5 million for extra fuel costs during the storm.
The utility’s fuel protocols provide that PSCo will make available to any wholesale fuel adjustment clause customer “books and records” related to the clause’s provisions and protocols. The Xcel Energy subsidiary argued the term “books and records” does not include the baseload contracts because the contracts are not the actual inputs for the fuel costs that are calculated and charged to the cooperatives under the fuel adjustment clause.
PSCo contended that the invoiced amounts charged under the baseload contracts, which it had already turned over to the cooperatives, were relevant because the information is necessary to understand how the charges were calculated. FERC found the argument to be unpersuasive, saying the utility did not cite any fuel protocol language indicating that “books and records” is limited only to “fuel cost inputs.”
The commission denied two other complaints by the cooperatives: that PSCo “imprudently” planned for its natural gas reserves and passed on excess costs from spot market purchases in February 2021 and that it acted imprudently and in a preferential manner by selling excess gas to an affiliate during the storm. FERC said the complainants had not presented sufficient evidence to meet their initial burden for those claims.
The commission also denied without prejudice the complainants’ request for relief from a Dec. 31, 2022, tariff deadline to raise questions concerning the fuel adjustment clause charges. They alleged PSCo violated its filed rate by withholding information, negating a further challenge to the charges, but FERC found the request to be “premature at this time.”
Projects in Louisiana and Texas have been chosen as the first two direct air capture (DAC) hubs to receive up to $1.2 billion in funding from the Infrastructure Investment and Jobs Act, the Department of Energy announced Friday.
The South Texas DAC hub and the Project Cypress DAC hub in Louisiana “are going to build regional direct air capture hubs, and that means they’re going to link everything from capture to processing to deep underground storage, all in one seamless process,” Energy Secretary Jennifer Granholm said during a Thursday press call.
Granholm described the technology as “essentially giant vacuums that can suck decades of old carbon pollution straight out of the sky, and once you harness that pollution, we can trap it permanently underground, or we can turn it into building materials … agricultural products or even clean fuels.”
Combined, the Texas and Louisiana projects are expected to take more than 2 million metric tons of carbon dioxide out of the atmosphere per year, “like taking nearly half a billion gas-powered cars off the road,” she said. “These hubs are going to help us prove out the potential of this game-changing technology so that others can follow in their footsteps.”
Mitch Landrieu, White House senior advisor and infrastructure coordinator, said the projects are “the first direct air capture projects at this scale in the United States and will be the largest in the world.”
Occidental Petroleum and its carbon-capture subsidiary 1PointFive are developing the South Texas DAC hub on 106,000 acres at King Ranch, an agribusiness ranch and farm that is larger than the state of Rhode Island, according to its website.
The project will use technology developed by Carbon Engineering Ltd. of British Columbia that “draws air into a facility using a series of large fans” and separates out the carbon via a chain of chemical interactions, as described on the 1PointFive website. The carbon, in liquid form, can be compressed and stored underground or processed to be used as feedstock for other products.
Battelle, a technology developer that manages seven of DOE’s national labs, is leading the Project Cypress DAC hub to be located on the Gulf Coast in southwest Louisiana. The company is partnering with two carbon capture companies — Climeworks Corp. and Heirloom Carbon Technologies — with the intention of combining their different technologies. Climeworks uses fans, filters and heat to capture carbon, while Heirloom has developed a process to absorb CO2 using limestone.
The two projects are the first of four DAC hubs to get a slice of the $3.5 billion the IIJA provided to develop the technology at commercial scale. Noah Deich, deputy assistant secretary of DOE’s Office of Carbon Management, said the two projects were chosen based on a rigorous review of their technical readiness, financial viability, and community benefits plans.
DOE has provided early funding of $3 million to $12 million to 19 DAC projects still in development, with the goal of getting ready to compete for the other two hub awards, he said.
“It will be a bit before we open up the funding,” Deich said in an interview with NetZero Insider. “It’s intentional so that we can let this direct air capture field catch up, and we don’t want to lock in any one technology that happened to get a head start. We really wanted diversity of technology approaches, a diversity of business models [and] geographies.”
Getting to Scale
Direct air capture, like carbon capture, has raised concerns and skepticism among some environmental groups, which have pointed to its expense, high power requirements and its potential use for enhanced oil recovery. At the same time, it has garnered strong support from lawmakers from states with a long history of fossil fuel production, including Sen. Joe Manchin (D-W.Va.).
Kelly Cummins, deputy director of DOE’s Office of Clean Energy Demonstrations, said that neither of the DAC hubs will use captured carbon for enhanced oil recovery, a process in which carbon dioxide is injected into low-producing wells to increase their output.
Asked about the power source for the Louisiana project, Lewis Von Thaer, CEO of Battelle, said the company would be buying clean energy from the local power provider to start, but intended to build renewable energy for the project later.
Both Occidental and Battelle have to match the IIJA funds dollar for dollar, but they stand to benefit from the $180 per ton tax credits for DAC in the Inflation Reduction Act. Still, for first-of-a-kind projects, DOE is encouraging the hubs to develop additional revenue streams, if necessary, to ensure they are financially viable, Deich said.
He pointed to the “voluntary market” for carbon removal offtake agreements, such as 10-year agreement Climeworks signed with Microsoft in July 2022, to take 10,000 tons of CO2 out of the atmosphere on the software giant’s behalf.
“There’s greater demand than supply, and these projects will be really critical for helping to fill that gap once they do start to come online,” Deich said. Such agreements also will be vital to help the early demonstration hubs get to commercial scale, he said.
Echoing Deich, Madelyn Morrison, government affairs manager for the Carbon Capture Coalition, hailed the announcement of the two hubs as an important step “to help realize economies of scale and support the decarbonization of the American economy. As such, today’s announcement provides major headway to kickstart the deployment of large-scale DAC projects as well as to foster the development of promising earlier-stage efforts.”
ATLANTA — In his opening remarks at Thursday’s joint FERC–NERC technical conference on physical security, FERC Chair Willie Phillips reminded attendees that “it is not a matter of if, but when there is another attack” on North America’s electric infrastructure.
Phillips’ attendance at the conference, held in NERC’s headquarters in Atlanta, was intended to demonstrate the seriousness with which the commission takes the growing threat of violence against the grid. FERC and the ERO organized the technical conference following NERC’s April report on its physical security reliability standards and recent physical security incidents, including the Dec. 3 gunfire attack on two substations in North Carolina that left 45,000 customers without power for days. (See NERC Says Changes Coming to Physical Security Standards.)
“I thought that it was important that I be here to help kick things off, because I want to underscore a couple of things,” Phillips said to the audience. “One, how important this dialogue is; and [second], we can’t do this alone. NERC can’t do this alone. No one entity can do what we need to do to protect the integrity of the [grid] from physical security attacks. … That’s why we’re here today.”
The goal of the conference was to discuss potential improvements to NERC’s reliability standards — particularly CIP-014-3 (Physical security) — in addition to other actions that registered entities can take to improve grid security.
NERC CEO Jim Robb noted that more than 1,200 people were watching the meeting online, in addition to those in the room. He said the size of the audience showed “the breadth of interest, both in the topic and the importance of getting this right.” He emphasized that any grid security solution must take the reality of utilities’ limited resources into account.
“Nobody wants to have an entity have to construct Fort Knox around a bag of pennies,” Robb said. “At the same time, we also have to be cognizant about the difference between the money that we spend to protect versus the money we spend to be able to recover, and recover quickly. And I think, given the sprawling above-ground physical nature of the electric system, that’s a really important balance to keep in mind when we think about physical security of our infrastructure.”
In the first panel, speakers focused on CIP-014-3, which aims to “identify and protect transmission stations and transmission substations, and their associated primary control centers, that if rendered inoperable or damaged [by] a physical attack could result in instability, uncontrolled separation or cascading within an interconnection.”
Jamie Calderon, a manager of standards development at NERC and contributor to the ERO’s April report on grid security, briefly described its conclusions. The report found that the standard’s applicability criteria are effective to “focus limited industry resources” on the most critical facilities and did not need to be expanded; however, the ERO also found that utilities’ approaches to some studies required by the standard are inconsistent because its wording is unclear.
Lawrence Fitzgerald, director of security and emergency management at engineering consultancy TRC, said that CIP-014-3 has “done a good job” identifying sites critical to grid security. However, he said the standard could be improved, asserting that some of its requirements seem to require utilities to certify the compliance of facilities that haven’t even been built yet.
“We get put in an awkward position for facilities, substations and control centers that are only on the drawing board. They don’t exist yet. It can’t cause a cascading outage,” Fitzgerald said. “But we’re being asked to … certify that everything’s copacetic and working well. I can’t do that if I don’t know what the connectivity between the substation and the monitoring center is, [or] if I can’t see a camera view or know how a facility is actually going to look on the ground.”
Mark Rice, senior power engineer at Pacific Northwest National Lab, observed that there is a longstanding divide between operational staff, who “care about the next 24 hours,” and those involved in planning who think “five, 10, or 15 years out.” He said “there probably needs to be a better conversation” between those who are responsible for evaluating risk at these different scales.
“I know [from] talking to some utilities at the transmission level, they have no clue what the load is, and they don’t know that it’s identified as critical to someone downstream,” Rice said. “And so we have to get that information into our systems or into our evaluations before I can do the next step of evaluating risk.”
Cool on Mandatory Minimums
Participants in the second panel discussed whether NERC should mandate minimum resiliency or security protections against physical attacks at critical facilities.
Jackie Flowers, director of Tacoma Public Utilities — which suffered a coordinated attack last December as two men damaged several substations as part of a robbery plot — expressed skepticism about establishing mandatory minimum protections. (See Wash. Sabotage Suspect Pleads Guilty.) She said resiliency would be better served by allowing utilities the flexibility to address the myriad different challenges that could apply at each site.
“We believe that a uniform, bright-line set of physical security measures is unlikely to offer as effective of an approach, because of the very site-specific conditions and varied risks that we have from infrastructure to infrastructure,” Flowers said. “So it’s very important that utilities are at the table and part of identifying what those risks are.”
Flowers’ fellow panelists agreed. Mike Melvin, director of corporate security and corporate and information security services at Exelon, emphasized that “you’re never going to get that risk [of physical attack] down to zero.”
Melvin pointed to the arrests earlier this year of neo-Nazi leader Brandon Russell and one of his followers for plotting to attack substations operated by Baltimore Gas and Electric (an Exelon subsidiary) in hopes of starting a race war. (See Feds Charge Two in Alleged Conspiracy to Attack BGE Grid.) He suggested that Russell’s plot, which was based on publicly available information on the utility’s facilities, showed that “where there’s readily [available] information out there, you can never pull it back in.”
Rather than mandatory minimum standards, the panelists suggested that robust information sharing networks, both among utilities and with law enforcement, are key to foiling physical attacks and sabotage before they escalate into disaster. Flowers endorsed the Electricity Information Sharing and Analysis Center as a way for utilities to update their peers on the latest physical and cyber security threats.
Panelists in the afternoon session — the theme of which was “Solutions Beyond CIP-014-3” — agreed the standard should be considered a baseline for physical security rather than an end goal in itself.
Scott Aaronson, a senior vice president at Edison Electric Institute, warned against a one-size-fits-all approach to physical security, noting that threat actors are increasingly sophisticated.
“I’ve said it before — you protect diamonds like diamonds and pencils like pencils, and what [are] the crown jewels [is] going to continue to change,” Aaronson said. “So I think open dialogue about understanding where those truly critical nodes reside, and how best to protect them and/or ensure redundance and resiliency and opportunity to recover is going to be key.”
Aaronson echoed earlier panelists’ calls for information sharing, while warning against letting that crucial data spread outside the industry. He raised the chilling prospect of a map of critical substations appearing “on the front page of The Wall Street Journal.”
Vinit Gupta, vice president at ITC Holdings, recommended holding regular penetration tests in which a third party attempts to break into a facility and cause simulated damage. He said that in one case, testers found several vulnerabilities at his company using techniques found in videos on YouTube, or cheap devices purchased on Amazon.
“You’d be surprised to see that you can buy a $10 device and do some of those [threatening] activities,” Gupta said. “So when we looked at some of the recommendations … that actually prompted us to reevaluate our approach, with physical access control systems and video monitoring systems. And we’re right now in the middle of replacing that and looking at where we go from here, because the threat landscape continues to change.”
The Department of Energy on Thursday proposed a set of rules to streamline the federal permitting of certain onshore electric transmission projects.
CITAP, the Coordinated Interagency Transmission Authorization and Permits program, would establish a two-year timeline for federal review of transmission proposals. It would set deadlines for permits and authorizations but also seek to ensure local communities, tribes and other stakeholders have an opportunity for engagement, DOE said in a news release.
DOE’s Grid Deployment Office would administer CITAP and is seeking public comment on the Notice of Proposed Rulemaking issued Thursday.
CITAP would be one response to a pressing issue — the lengthy process for adding the infrastructure that is critical to greater electrification of the U.S.
Many clean energy projects proposed nationwide are slowed, stalled or even canceled because of the time and cost of securing interconnection. A 2022 DOE report found more than 930 GW of generation and more than 420 GW of storage in transmission queues nationwide.
That will increase as fossil fuels are replaced with electrons. DOE said independent estimates find that transmission capacity will need to increase 60% by 2030 and perhaps triple by 2050.
The CITAP proposal grows from a May 2023 memorandum of understanding signed by DOE and eight other federal agencies. DOE draws its authority to lead the process from Section 216(h) of the Energy Policy Act of 2005.
CITAP would not replace state or local permitting, nor would it circumvent any federal laws. Instead, it seeks to streamline the regulatory portion of a process that can extend more than a decade from start to finish.
Under the proposed rulemaking:
DOE would identify all entities with a role in a given transmission project, lead an iterative process to ensure the developer’s applications for federal authorization are ready by the binding timelines to be established and work with relevant agencies to prepare a single environmental review document for use by all of the federal entities with oversight on the project.
Developers would have to participate in an integrated interagency preapplication process that would provide a uniform mechanism for them to identify constraints and opportunities, gather information, engage with local stakeholders and prepare a plan for public engagement throughout the life of the project.
And there would be a standard schedule for all of this to unfold — DOE produced a draft version as part of the proposal. The schedule would be a template, however, not a rigid timeline. Each proposal would receive a project-specific schedule factoring in location, scope and potential impacts.
Reaction
Clean energy industry and advocacy organizations welcomed the proposal, as far as it goes.
“ACEG strongly supports DOE’s action to improve coordination and transparency in the federal permitting process,” said Christina Hayes, executive director of Americans for a Clean Energy Grid. “Implementing a one-stop-shop for agency reviews and setting strict deadlines for this process will represent a fundamental leap forward from the current system, which requires applicants to juggle each agency’s timeline separately and can sometimes delay a project by years. The nation needs more transmission, and we need it as soon as possible to improve electric reliability and lower costs for American households. This rule will get us closer to the finish line.”
“ACP appreciates DOE’s efforts to streamline the process for permitting transmission lines, and we look forward to reviewing and commenting on the proposed rule,” said American Clean Power Association Vice President of Markets & Transmission Carrie Zalewski. “While this is a positive step, it’s critical that Congress build upon these actions and tackle comprehensive, meaningful permitting reform that, among other things, improves the permitting process for high-impact transmission lines.”
“Transmission developers are facing inefficient and lengthy review processes to getting projects permitted and approved, leading to increased costs and delayed timelines,” said Caitlin Marquis, managing director at Advanced Energy United. “Electric transmission lines are the essential backbones of our power grid, and building more transmission leads to lower energy costs and improved grid reliability. A more efficient permitting program that maintains essential review processes will provide more certainty for developers and support a stronger, more resilient power grid.”
The Treasury Department on Thursday issued final guidance on IRA tax credit adders of 10 to 20 percentage points for clean energy investments in underserved communities.
A total of 1.8 GW of qualified wind and solar projects rated at less than 5 MW will be allowed to participate in 2023 in the Low-Income Communities Bonus Credit Program.
This breaks down to 700 MW to facilities in low-income communities, 700 MW to facilities that provide at least 50% of their financial benefits to lower-income households, 200 MW to facilities on Indian land and 200 MW to facilities that are part of federally subsidized residential buildings.
Eligible wind and solar facilities built in low-income communities or on Indian land can receive a 10 percentage-point increase. Those that are installed on a qualified low-income residential building or that provide at least half their output to low-income households can receive a 20 percentage-point increase.
The Internal Revenue Service may reallocate capacity between these categories if any become oversubscribed.
Any unclaimed allocations will roll over into 2024, when applications will be accepted for another 1.8 GW of capacity.
The application process will open in early autumn and is expected to continue through early 2024, depending on the level of response.
The bonus credits seek to direct some benefit to disadvantaged communities as the Inflation Reduction Act prompts spending of hundreds of billions of dollars on the clean energy transition.
Specifically, the credits are intended to reduce energy costs, support small-business growth, improve air quality and create good-paying clean energy jobs in low-income communities, Treasury said in a news release.
These same communities often have suffered negative health or environmental effects from fossil-fuel combustion combined with a general shortage of economic opportunities, Treasury said.
The Section 48(e) bonus credits announced Thursday are in addition to the investment tax credits available to energy projects of less than 5 MW under Section 48 of the Internal Revenue Code.
The Department of Energy’s Office of Economic Impact and Diversity is helping administer the program with Treasury and the IRS.
DOE has created a landing page for the program on its website and soon will create an application portal and user guide.
The Department of Housing and Urban Development has posted median family income data that will be used to calculate eligibility for some of the credits.
The North Carolina Utilities Commission on Tuesday approved a new tariff that will allow Duke Energy to rent charging infrastructure to customers.
Under the Electric Vehicle Supply Equipment (EVSE) tariff, Duke will install Level 2 EV chargers and charging infrastructure for residential and non-residential customers, and fast-charging systems for non-residential customers on its system. The utility will offer five options for both Level 2 chargers and fast chargers.
Customers at both levels will be charged only for Duke’s investments on their side of the meter with contracts ranging from three to seven years.
NCUC’s Public Staff and third-party firms who offer EV charging infrastructure on a competitive basis questioned whether Duke’s tariff overstepped its monopoly franchise and might chill investments from other parties in its territory.
ChargePoint noted that the private sector already offers similar programs where customers can get EV chargers installed without buying the equipment.
“The private sector offers many different business models and products to provide turnkey solutions for site hosts, coordinating all aspects of the charging experience from installation to operation and maintenance, including solutions for site hosts that are not seeking to own or operate their own charging equipment,” ChargePoint told the regulator.
Duke noted that its EVSE tariff will be completely paid for by participants in the program, not all ratepayers. The charging hardware and networks will come from existing and future market participants, removing barriers to EV adoption and allowing customers to choose from multiple vendors.
Issues around competition for charging infrastructure came up when earlier pilot-scale programs were before the NCUC, and it did not close the door on Duke participating in the mature market. For example, last year it approved a “make ready credit” where Duke pays customers a credit based on increased revenues from the next three to five years of EV ownership so they can defray the cost of wiring and other improvements needed to install chargers.
“The commission concludes that there is a proper role in serving the public convenience and necessity for Duke’s involvement in offering a voluntary tariff for ratepayers who want the option of leasing EV equipment and leaving the maintenance of such equipment to Duke,” the order said.
Limited involvement from Duke’s utilities will be beneficial in gauging public interest in more charging options, as well as obtaining data on charging practices and alternative rate structures.
“The commission’s challenge is to allow the availability of such options for ratepayers while balancing the need to avoid dampening the competitive market,” the order said.
The previous programs authorized for Duke were temporary and the NCUC said it will review the EVSE in three years to determine if it should be continued, amended or discontinued.
While the question of whether Duke will continue offering actual charging equipment will be revisited, the utility is planning for an increase in load as more customers buy plug-in cars, its Managing Director of Grid Systems Integration Jay Oliver told the state’s Energy Policy Council’s Energy Innovation Committee at a meeting Thursday. The council is run out of the Department of Environmental Quality and advises the legislature and governor on energy policies.
The firm’s next integrated resource plan will include load growth from EV adoption, which can be handled easily by Duke’s generation and transmission system. The key to avoiding any issues is load management, which Duke has plenty of experience with.
“What we’ve learned is that simple load management programs for vehicle charging work very well,” said Oliver.
Without any price signals to the contrary, customers tend to charge their vehicles in the late afternoon and early evening, which works in the winter, but coincides with the peak demand hours during the summer, said Oliver. Simple load management programs can shift that charging to 9 p.m. and later.
Load management also can help address charging demand at public sites like offices where customers would plug in during the morning, which presents issues in the winter when demand is high earlier in the day, said Oliver.
The new demand from EVs is going to require some upgrades to the distribution system, where a typical transformer serves five to eight customers.
“When you add a Level 2 charger to your home, essentially, you have just doubled the demand that that home could draw,” Oliver said.
Level 2 chargers operate at 240 volts and typically take about two hours a day to charge a vehicle’s battery, which means Duke can shift the charging times around to avoid overburdening its distribution circuits and minimizing the amount of upgrades it will need to make to accommodate new demand from vehicles.
Public chargers are going to have less flexible demand as they will be used whenever consumers show up and plug in their vehicles, said Oliver. North Carolina alone should have 140 to 200 sites planned by its Department of Transportation, said Oliver. Those are going to require more transformers to support, and it can take utilities 12 to 18 months to procure those now.
Fast-charging sites do not take up much physical space, but their effects on the power system are much greater.
“But from an electrical load perspective, think about a Harris Teeter, or maybe even a Walmart,” Oliver said. “That’s what the load of these things are.”
Electrification makes sense for many fleets of vehicles such as those operated by shipping firms or Amazon, but one issue is that fleets often park close to each other. So, when firms start to adopt EVs for the fleets, that could require even bigger upgrades such as new substations, Oliver said.
“We’re having to get, we believe, three to five years in advance to serve these locations appropriately,” he added. “And we’re working on all of that now — putting capacity projects into place so we can actually go and do those upgrades ahead of time so we’re there when the demand comes.”
Vistra CEO Jim Burke said Wednesday that Luminant’s generating fleet has performed well amid Texas’ ongoing heat wave, which has led to multiple demand records this summer.
“The units are running hard. There’s no end in sight for this heat that we’re in,” Burke told analysts during the company’s quarterly conference call. “The team is doing a terrific job keeping these units online, and I would say overall, the ERCOT grid and the operators have done a nice job keeping the grid supplied. It’s a daily focus for us.”
The Texas grid operator set three new highs for average hourly demand this week, breaking 84 GW and 85 GW for the first time Thursday. ERCOT’s new mark of 85.44 GW broke previous records set Monday and Wednesday at 83.85 GW and 83.96 GW, respectively. The new demand peak is unofficial until settlements are made.
ERCOT staff projected demand to peak at 82.74 GW in its final summer resource adequacy assessment. Demand has met or exceeded that projection 46 times this summer, 14 times since Thursday. The ISO still is operating under a weather watch, its fourth of the year, that has been extended twice through Friday because of the higher temperatures and demand and a potential for lower reserves. Grid conditions are expected to be normal and ERCOT is not calling for conservation.
Burke said that while the Texas grid’s ’s newest ancillary service, ERCOT contingency reserve service, has helped maintain a plump cushion of reserves and avoided emergency conditions, “it does not solve the broader problem that we entered the [2023 legislative] session trying to solve.”
He said although lawmakers’ objective was to retain and incent new thermal generation, “we ended up with a menu of things.”
“Frankly, it’s a ton of work for the Public Utility Commission and ERCOT to work through this. They’re going to have their plate more than full,” Burke said. “There’s a lot still to figure out, and we’ll obviously be active and work with stakeholders involved to try to bring clarity to it.”
The Irving, Texas-based company completed a 350-MW expansion of its Moss Landing energy storage facility in California during the quarter, increasing its capacity to 750 MW and, according to Vistra, making it the largest battery storage resource in the world. It also said it’s making progress on its announced acquisition of Energy Harbor.
Vistra reported $1.01 billion in ongoing operations adjusted earnings before interest, taxes, depreciation and amortization (EBITDA), an improvement over the $756 million realized during the same period a year ago. It said the increase was driven primarily by higher energy margins through its hedging strategy, backing down generation when prices were below unit costs, and strong performance in its retail segment, partly offset by less favorable weather.
The company uses adjusted EBITDA as a performance measure because, it says, outside analysis of its business is improved by visibility into both net income prepared in accordance with GAAP and adjusted EBITDA.
Vistra’s share price closed at $30.69 Thursday, up $1.87 from Tuesday’s close.
OGE Energy Retiring, Replacing 2 Gas Units
OGE Energy also released its quarterly financial results Wednesday. Oklahoma Gas & Electric’s parent company reporting earnings of $88 million ($0.44/diluted share), up from last year’s same period of $73 million ($0.36/diluted share).
The company said it has requested approval from Oklahoma and Arkansas regulators to retire and replace two aging gas-fired steam turbines at its Horseshoe Lake power plant in eastern Oklahoma with two newer gas combustion units. The proposed $331 million project would replace the two units that also can burn fuel oil with 450 MW of more efficient generation.
The two retiring units have a combined capacity of 383 MW. They have been in service since 1958 and 1963.
“These units are a great first step in meeting the future generation capacity needs of our company,” CEO Sean Trauschke told financial analysts.
OGE said it has submitted four funding applications to the Department of Energy under the Infrastructure Investment and Jobs Act to help pay for the project.
OGE’s share price closed at $34.46 Thursday, up 18 cents from its close Tuesday.
New England wholesale market costs were significantly lower in the spring of 2023 compared to spring 2022 and 2021, the ISO-NE Internal Market Monitor (IMM) told the Markets Committee on Wednesday.
The IMM noted that wholesale costs declined by 47%, or $1.25 billion, compared to spring of 2022, attributing the decrease to lower natural gas prices, which were down 69%. The IMM also said load was lower this spring because of a relatively cold May.
The monitor added that capacity market costs were down 21%, reflecting lower clearing prices from the Forward Capacity Auction (FCA) 13 relative to FCA 12.
Looking at the resource mix, oil generation declined from 13% to 11% of the average output, while gas generation increased from 43% to 47%. Nuclear generation decreased by 354 MW compared to last spring, from 21% to 19% of average output, “due to refueling outages and unplanned outage continuation,” the IMM reported.
Electricity Generation by Fuel Type. | ISO-NE
Barriers to Entry for Retired Resources
Also at the Markets Committee summer meeting, ISO-NE proposed removing the cost requirements for retired resources looking to re-enter the Forward Capacity Market (FCM). The most recent rules for resources looking to re-enter the FCM include an investment requirement of $417 per kW.
“These requirements apply to any re-entering resource after it has retired, regardless of its retirement elections and/or a reliability retention agreement,” said Ryan McCarthy of ISO-NE.
McCarthy said the requirement is intended to discourage generators from retiring and re-entering just to access unique pricing rules for new resources. Because these unique pricing rules have been removed, the investment requirement no longer is needed, McCarthy told the committee.
“As things stand currently, the investment requirement could create a barrier to cost-effective and timely re-entry of resources,” McCarthy said. “The ISO proposal removes the investment requirement for fully retired or permanently delisted resources seeking to requalify for the FCM.”
ISO-NE has proposed an October vote on removing the requirement, with an effective date of quarter four of 2024.
FCA 19 Uncertainty
The main focus of the Markets Committee summer meeting was discussing options for the format and timing of FCA 19. (For a more detailed breakdown of Tuesday’s discussion, see NEPOOL Debates Options for FCA 19.) Many NEPOOL members have supported delaying the auction a year to implement resource capacity accreditation (RCA) changes, and to consider moving to a prompt and seasonal capacity market.
“Getting the capacity market right is incredibly important,” Ben Griffiths of LS Power told RTO Insider. “We support a one-year delay in FCA 19 to give the ISO and stakeholders time to fully vet RCA and other possible changes in market design that will be in place for years to come.”
However, some clean energy companies have expressed worries about how a delay would impact new resources which did not receive commitments in FCA 18.
“In ISO-NE, the process for generators to have their capacity deliverability studied and secured currently resides within the FCA qualification process and not in the interconnection process as in some other regions,” said Alex Chaplin of New Leaf Energy. “Postponing FCA 19 would suspend this pathway to secure capacity deliverability, making new resource development in the region substantially riskier.”
Chaplin said this added uncertainty likely would increase the cost of capital for new resources in FCA 19, putting some projects in jeopardy.
“This would slow the pace of the clean energy transition and may introduce reliability concerns in light of ISO-NE’s rising forecast peak loads,” Chaplin said.
Cost of New Entry Changes
ISO-NE also detailed potential changes to its process of calculating Cost of New Entry (CONE) and Net CONE for FCA 19 and 20.
Using FCA 18 as a baseline, ISO-NE found that the updated formula would have increased CONE by 4.2% and Net CONE by 6.5%.
The RTO plans to vote on the proposal at the Markets Committee in September, with an effective date of March 2024.
The California Energy Commission agreed Wednesday to keep three old, environmentally damaging gas-fired plants operating along the Southern California coast for grid reliability, despite an outpouring of opposition from local residents and environmental groups.
It was the second three-year extension given to the once-through cooling plants, which had been scheduled to retire because of their harm to marine life and polluting of oceanside neighborhoods. But the state has deemed them necessary as it struggles to keep the lights on during heat waves while transitioning to 100% clean energy by 2045.
Energy Commission Chair David Hochschild called keeping the OTC plants operating a “collective failure,” even as he and his fellow commissioners voted to approve capacity agreements between the state Department of Water Resources (DWR) and the plants in Long Beach, Oxnard and Huntington Beach, Calif.
“I look forward to the day not just when these three facilities are retired, but when all fossil fuel generation is retired,” Hochschild said. “We have to build that future, and I believe we can. What’s aggravating for me is that we’re doing it, but we’re late.”
The vote followed more than two hours of impassioned testimony from those who live near the plants, saying they and their family members had been sickened by emissions and wanted the plants closed down, as planned, this year.
“What I hear here is this is a crisis of betrayal, a feeling of absolute trauma that communities feel over and over,” CEC Vice Chair Siva Gunda said in response to the residents’ pleas. Gunda said he found the decision difficult but was bound by the state’s need to avoid blackouts.
An extreme heat wave led to rolling blackouts in California in August 2020, followed by energy emergencies caused by heat waves and wildfires in the next two summers.
The commission’s decision approved DWR’s plan to spend up to $1.2 billion to maintain selected units at the Alamitos Generating Station in Long Beach, the Huntington Beach Generating Station in Orange County and the Ormond Beach Generating Station in Oxnard for three more years, until Dec. 31, 2026.
The once-through cooling plants, which had originally been set to retire in 2020, had already gotten a reprieve until 2023 for the sake of reliability.
AES Corp., based in Arlington, Va., owns the Alamitos and Huntington Beach plants, while Houston-based GenOn owns the Ormond Beach facility. Collectively, the units to be kept online can generate nearly 2,900 MW of capacity.
DWR will issue the companies fixed monthly capacity payments of $8.82/kW-month to $10.95/kW-month, for a three-year total of as much as $1.19 billion. The department runs the state’s Electricity Supply and Strategic Reliability Reserve Program, which acts as a backstop to provide incremental power during extreme events.
Legislation passed hastily in June 2022 assigned the role to DWR and approved Gov. Gavin Newsom’s proposed $5.2 billion strategic reliability reserve consisting of “existing generation capacity that was scheduled to retire, new generation, new storage projects, clean backup generation projects, [and] diesel and natural gas backup generation projects.” (See California to Pass Sweeping Energy Policy Changes.)
Critics lamented the bill in large part because the once-through cooling plants would likely be retained as part of the reliability reserve.
The plants, built in the 1950s and 1960s, use ocean water for cooling, killing billions of marine organisms. In 2010, the State Water Resources Control Board ordered the phase-out of 19 OTC plants along the coast.
Some plants retired, and others updated to air-cooling or alternative water-cooling technologies. The last three plants — Alamitos, Huntington Beach and Ormond Beach — still use their original cooling designs.
The hulking plants loom over densely populated coastal communities, wetlands and sandy beaches. Many residents and elected officials have wanted them closed for years because they are noisy, unsightly and polluting, but California’s energy shortfalls have extended their lifespans.
The State Water Resources Control Board must still sign off on the DWR to keep the OTC plants online. It has scheduled a hearing for Aug. 15 to consider the extension, which it is expected to approve.
STOWE, Vt. — ISO-NE on Tuesday solicited feedback from the NEPOOL Markets Committee on several options for the timing and overall design of Forward Capacity Auction 19.
FCA 19 will procure capacity for the 2028/29 capacity commitment period. While the RTO had hoped to implement resource capacity accreditation (RCA) changes in FCA 19 aimed at improving estimations of gas generator winter reliability limitations, a software error related to LNG availability has delayed the process. (See ISO-NE Outlines More of Plans for Capacity Accreditation, DA Ancillary Services.)
NEPOOL is also considering a move to a prompt seasonal capacity market and whether this move should be initiated for FCA 19, at a later date or not at all. (See Discussion Continues on ISO-NE Capacity Market Changes.)
ISO-NE has laid out a series of options for stakeholders to consider for FCA 19, asking for input on preferred routes:
1. conduct FCA 19 using the current market rules without implementing RCA.
2. push the auction date back a year, from 2025 to 2026, and include RCA changes.
2a. plan to implement RCA in FCA 19 with the auction held in 2026, but decide by Q3 2024 whether to instead move to a prompt and seasonal auction held in 2028.
3. transition to a prompt and seasonal auction for FCA 19, with the auction held in early 2028, providing time to implement RCA.
“In each of the options, the start of CCP 19 remains the same. The timing of the pre-auction processes and auction varies,” Tongxin Zheng of ISO-NE told the committee.
ISO-NE has not endorsed any of the options and has said that all of them remain on the table.
Several committee members expressed support for delaying the auction a year to help consider and potentially implement significant changes.
Massachusetts Assistant Attorney General Ashley Gagnon wrote in a memo prior to the meeting that a one-year delay of FCA 19 “to determine the appropriate path forward for FCA 19/CCP 19 is worth serious ISO and stakeholder consideration and discussion given the importance of the decision and the current lack of information essential to making an informed decision.”
Gagnon said that delaying the auction would allow ISO-NE to finish the RCA design process and more thoroughly contemplate the possibility of moving to a prompt and/or seasonal market. Gagnon also stressed the importance of keeping ratepayers in mind while contemplating the options.
“The AGO [Attorney General’s Office] recommends that potential costs to consumers be an explicit consideration and evaluation metric in deciding the optimal path forward for CCP 19 and beyond. While the AGO recognizes that potential costs to consumers may be difficult to analyze at this stage, consumer impacts are critical and should inform the decision-making process,” Gagnon said.
Timelines for CCP 19 Options | ISO-NE
Brett Kruse of Calpine also expressed his support of option 2a, noting that the company has been advocating for a move to a prompt capacity market for several years.
“We’re fine with a one-year delay for FCA 19 in order to allow ISO-NE to implement RCA (option 2) but marginally prefer 2a because of the addition of the prompt procurement aspect,” Kruse told RTO Insider. “We’re interested in option 3 that would also add a seasonal market design, but need to be comfortable with some details about the design, which is fairly conceptual at this point.”
Eric Wilkinson of Ørsted said that the capacity market changes must properly account for the reliability attributes of renewables.
“Ørsted supports ISO-NE’s efforts to revise their capacity market rules,” Wilkinson said. “As the fuel mix for electric generation continues to evolve, it is important that the capacity market appropriately values the contributions to system reliability that renewable resources, including offshore wind, provide.”
ISO-NE plans on choosing an option by late September and bringing forward a proposal in October.
Seasonal Auction Timing
ISO-NE also presented some pros and cons of holding seasonal auctions within a given CCP simultaneously or serially.
“Either approach could be used with a forward or prompt procurement of capacity,” said Chris Geissler of ISO-NE. “However, pros/cons associated with each depend on whether procurement is forward or prompt.”
Geissler said that the benefits of serial seasonal auctions could be more pronounced under a prompt construct, which would allow the auction to reflect the most up-to-date information.
Meanwhile, Geissler noted that holding the auction simultaneously would enable capacity sellers to specify different offer prices for each season and the entire CCP, as well as helping to ensure revenue sufficiency for sellers.
