New York state officials on Tuesday issued a straw proposal for integrating community distributed generation (CDG) into community choice aggregation (CCA) on an opt-out basis (14-M-0224).
The Public Service Commission initiated the CDG program to give utility customers a chance to participate in distributed solar regardless of whether they own a residence or business suitable for installing panels.
“Opt-out CDG encourages municipal governments — and their constituents — to take control of their energy future through locally driven CDG participation,” Department of Public Service said in the proposal. “Staff is confident that a robust opt-out CDG program will encourage a multitude of new administrators to join the CCA market, including public and nonprofit organizations, leading to an increase in market competition which could spur innovation by means of the CCA model.”
CCA “is a municipal model for procuring energy that replaces the utility as the default supplier of electricity and/or natural gas for virtually all homes and small businesses within a jurisdiction.” All utility customers financially support clean generation facilities through surcharges added to their bills.
The commission decided to focus the program on residential and other small customers because they otherwise would not be able to benefit from clean distributed energy resources. The opt-out model of implementation is designed to pull more customers into the program, given people’s tendency to take the path of least resistance: Customers in the municipality would be automatically enrolled, unless they opt out.
Structure and Rules
The commission’s November procedural order directed that the proposal detail the program’s operation, oversight and enforcement. The DPS held two public webinars in February and incorporated some of the comments into its recommendations.
Staff recommended that two unique products be offered to municipalities: standalone CDG, or CDG in addition to becoming a CCA. Much of the proposal is concerned with rules to minimize confusion for those customers in a CCA; the timelines for the CDG opt-out and CCA supply will not necessarily line up. It also accounts for customers already enrolled in a CDG program.
“We understand that a combined offering for [municipalities] who choose to offer both supply and CDG will allow for greater energy options and consumer choices,” Michael O’Donnell, DPS utility analyst, said during the first webinar. “We need to guarantee that customers who already have a supply product are not confused by another product offering or misguided by the timing of the offerings.”
The straw proposal also recommends that the following customers, who are ineligible to be opt-out enrolled in CCA supply, be eligible for opt-out enrollment in CDG:
time-of-use or time varying rate customers;
Assistance Program Participant (APP) customers;
customers with energy service company (ESCO) blocks on their utility accounts; and
customers who are being served by an ESCO.
The proposal recommends that low-income APP customers be the first members to be subscribed in the municipalities’ programs, and that they should continue to receive their CDG credits and not be dropped or unsubscribed because of any change in their APP status.
Crediting Methods
The proposal recommends that programs use the state’s current net-crediting model — for now.
“Under net-crediting, the utility keeps 1% of credits generated each month for billing administrative purposes, a minimum of 5% of credits go to the customers, and the remaining value is paid to CDG owners by the utility, according to the proposal. “This model guarantees savings for customers participating in CDG.”
However, under the proposal, the state could adopt a credit pooling mechanism, proposed by New York State Energy Research and Development Authority (NYSERDA) and National Grid and approved by the PSC in January for the Expanded Solar for All (E-SFA) program (19-E-0735).
Credit pooling was adapted from commercial and industrial practices to allow residential customers to share the energy produced from an eligible renewable resource and receive bill credits based on the production of the facility. It potentially offers considerable efficiencies for CCA administrators, customers and utilities, Max Joel, assistant director of the NY-Sun program at NYSERDA, said at the first webinar.
Admin Details
The state also recommends that CCA administrator fees for opt-out CDG be paid exclusively by the owner of the project serving the aggregation. In addition, fees can be calculated based on percentage, per kilowatt-hour or per customer. CCA administrators must clearly present their proposed fee structure in proposals to municipalities, made through a competitive municipal bid process with NYSERDA’s assistance, including the method by which fees will be calculated.
The state is requesting further stakeholder feedback on CDG capacity to decide whether a cap, block, carve-out or some other mechanism needs to be put in place to ensure all New Yorkers have access to CDG, either through an opt-in or opt-out model.
Customers living in utility territories with limited potential for CDG development, or with insufficient project pipeline capacity, “should not be jeopardized by opt-out CDG programs operating within their utility service territory,” the proposal said.
Nevada Gov. Steve Sisolak said Thursday that he has signed on to a multistate agreement to work toward a goal of 100% sales of zero-emission medium- and heavy-duty trucks by 2050.
Sixteen other states, the District of Columbia and the Canadian province of Quebec previously signed the memorandum of understanding, which was announced in July 2020.
The aim of the agreement is to accelerate the market for electric trucks, ranging from large pickups and vans to delivery trucks, school and transit buses, and long-haul vehicles. The group’s interim target is at least 30% zero-emission truck sales by 2030.
In addition to Nevada, signatories of the agreement include the states of California, Colorado, Connecticut, Hawaii, Maine, Maryland, Massachusetts, New Jersey, New York, North Carolina, Oregon, Pennsylvania, Rhode Island, Vermont, Virginia and Washington.
The jurisdictions represent 40% of the U.S. population and 35% of registered medium- and heavy-duty vehicles, according to Sisolak’s office.
Sisolak made the announcement via a pre-recorded video during a Las Vegas event hosted by the nonprofit Electrification Coalition.
“By working across states and with many partners, we can accomplish much more together than we could do individually,” Sisolak said.
Sisolak said the agreement will help Nevada meet its goal of net-zero greenhouse gas emissions by 2050 and position the state to respond to federal regulatory changes.
Reducing Risks
The Electrification Coalition welcomed the announcement.
“States are playing a key role in the vital work to transform our transportation system, and Nevada’s participation in this commitment represents a substantial boost to our momentum,” Katherine Stainken, the coalition’s vice president of policy, said in a statement.
In a June letter to Sisolak, the coalition urged Nevada to join the agreement to address the public health, economic and national security risks arising from the transportation sector’s oil dependence. The letter was signed by representatives of 41 businesses, including Amply, EVgo, Mack Trucks, Proterra, Rivian, Siemens, Volvo Group North America and Nestle USA.
Western Resource Advocates also commended Sisolak for bringing Nevada into the agreement.
“We applaud Gov. Sisolak for this important step that recognizes the need to reduce the harmful fossil-fuel emissions from medium- and heavy-duty trucks in Nevada that contribute to climate change,” Cameron Dyer, Western Resource Advocates’ managing senior staff attorney in Nevada, said in a statement.
But WRA called on the state to do more, including following California’s lead in adopting an Advanced Clean Trucks regulation. The regulation requires vehicle manufacturers to sell zero-emission trucks as an increasing percentage of their annual California sales from 2024 to 2035.
Draft Plan Released
Signatories to the agreement are working together through a ZEV task force being facilitated by the Northeast States for Coordinated Air Use Management (NESCAUM).
Last month, the group released a draft action plan that includes more than 60 recommendations for state policymakers to promote widespread deployment of zero-emission trucks.
The recommendations cover areas such as sales and fleet purchase requirements; purchase incentives for ZEVs and related infrastructure; electric utility and utility regulator actions; financing for fleet conversions; and outreach and education.
One of the plan’s recommendations is that states work together to support development of a standardized and reliable fast-charging network for trucks. States should also advocate for changes to federal law that would allow user-pay charging at interstate rest areas, the plan recommended.
And states should consider increasing weight limits for electric trucks, a step the federal government has already taken for trucks on interstate highways, the plan said.
“Current weight limitations can impact the payload capacity of battery-powered trucks, particularly long-haul freight trucks, because the additional weight of the battery system can result in reduced payload capacity,” the draft plan noted.
Comments on the draft plan will be accepted through April 25 and may be submitted through NESCAUM’s public input portal.
The need for energy security in the wake of the war in Ukraine dominated the Atlantic Council’s 6th annual Global Energy Forum this week in Abu Dhabi as much as the threat of climate change.
Co-sponsored by the United Arab Emirates, the two-day conference drew more than 100 speakers, including energy analysts and venture capitalists from around the world, executives with gas turbine manufacturers, pipeline companies, oil and gas producers, hydrogen startups and government representatives.
European dependence on Russian hydrocarbons and the U.S. pledge to have more LNG shipped to Europe added urgency to the discussions about how to begin moving away from conventional oil and gas to renewables. Hydrogen was discussed as a fuel to augment rather than quickly replace fossil fuels.
Amos Hochstein, the U.S. State Department’s presidential coordinator, said Europe had begun this winter with low natural gas inventories because Russian state-owned Gazprom had reduced the amount of gas it exported for months before Russia invaded Ukraine. The Biden administration has announced at least 15 Bcf of additional LNG will be shipped to Europe this year, he said.
“We were able to work with market participants — U.S. companies, traders and buyers around the world — [to] redirect cargos … to Europe,” he said.
“You can’t magically bring on LNG infrastructure; you need to work with the system that you have,” he said. “There are some LNG export plants around the world that are not operating at full capacity. We are working to bring them into full capacity by increasing production on a temporary basis in those countries.”
Without saying so explicitly, Hochstein made it clear that more U.S. gas production will be needed, a development certain to infuriate environmentalists but encourage the industry, which has been reluctant to increase production because of past debt created by overproduction that drove down prices.
The price of gas contracts traded on the New York Mercantile Exchange for April closed Tuesday at $5.34/MMBTU. That was up from the March wholesale contract price of $4.57. Future monthly gas contracts through November trading on the New York Mercantile Exchange closed Wednesday in a range from $5.57 in May to $5.73 for November — an early warning for gas turbine plants and next winter’s heating bills.
“Europe is making some commitments that they will work with member states to ensure that there are long-term and contractual arrangements with U.S. infrastructure to allow for those facilities to be financed so that additional LNG can come on the market sooner,” Hochstein explained. “We are living in this strange world of energy transition, where we have to make sure that we have enough supplies of oil and gas today and over the next several years as we accelerate and double down on the energy transition itself, whether it’s through expansion of nuclear and including small modular reactors [SMRs] as well as other renewables and … clean energy technology that will reduce demand.”
Reducing demand for natural gas is a second leg of the strategy, Hochstein said. Even before the Ukrainian war, Europe had begun to diversify its energy sources, he said.
“There’s no doubt that is going to take time though. It’s not going to happen this year. And even by the end of the decade, we’re not going to see the biggest declines in demand. We have to plan for the short term, the medium term and the long term.
“We are looking to get away from the reliance on fossil fuels,” he added. “In the short term, we need to make sure that our system and our economy is well supplied to be able to sustain growth and to avoid the kind of inflationary actions that we’re seeing today in the market.
“But one thing is for sure, this war has totally and completely changed the narrative and how we view Russian supplies into Europe and the critical need to diversify away from Russian supplies into the future.
“That is a tall order, but it has to be done, and I don’t think there is more than one or maybe two countries in Europe that don’t fully understand this issue and commit themselves to this.”
Trillions of Dollars to Decarbonize
Kara Mangone, director of climate strategy at Goldman Sachs said the firm estimates that funding the transition to renewables envisioned by the 2015 Paris Agreement will require $3 trillion to $5 trillion a year or $100 trillion to $150 trillion total.
“We’re nowhere near that today. About half of that capital will need to go into renewables and technologies that are at commercial scale today; but the other half, very importantly, will need to go into carbon capture; into hydrogen; into direct air capture; into sustainable aviation fuel and e-fuels.
“These are the fuels technologies that are not yet being adopted on a commercial scale because they have not hit the price point where that can happen for a lot of companies.”
Estimating that global business and industry is currently investing about a third of what Goldman thinks must be spent, Mangone said the new technologies should not be financed by pulling funding from traditional technologies. To remain commercially viable, industry “cannot pull out financing from the exact sectors: the oil and gas sector, metals and mining, real estate [and] agriculture,” she said.
Andre Pienaar, founder and CEO of C5, a venture capitalist company, said legacy nuclear is one of those older technologies that must be supported and that firms such as his should be investing in companies building SMRs.
Calling SMRs a “complete sea change,” Pienaar said advanced nuclear “has a very important contribution to make, to provide a secure and always-on source of fossil-free energy for the future to enable us to reach these goals.”
In an earlier event initiating the forum, Sultan Al Jaber, CEO of Abu Dhabi National Oil Co. and special envoy for climate change, also stressed that the transition to renewables and carbon-free synthetic fuels cannot happen overnight with little regard to existing technologies.
“Ladies and gentlemen, the theme for this year’s forum, the geopolitics of the energy transition, could not be more timely. We are all witnessing firsthand how sensitive energy markets are to geopolitical shocks,” Jaber said in opening remarks.
“The current volatility in oil prices is the result of a deeper underlying structural issue. Long-term underinvestment in oil and gas has left markets more exposed to risks of any kind, and wherever they take place.
“According to the [International Energy Agency], investment in oil and gas is $200 billion below where it needs to be. And that is just to keep up with demand through 2030. Near term, we’re also seeing markets tighten with demand up almost 3 million barrels over last year and expected to reach pre-pandemic levels by fourth quarter of this year.
“In short, the push to divest from hydrocarbons has met a stark reality, and we must accept and acknowledge that when we fully embrace the energy transition, we need to recognize that policies should be tailored to real-world scenarios.
“And they should follow the basic rule of progress: that if we fail to plan, our plan will definitely fail. Put simply, we cannot and must not unplug the current energy system before we have built the new one,” Jabar argued.
The Role of Hydrogen
Whether produced from natural gas or with renewable energy, or converted to a liquid such as ammonia or methanol, or shipped globally or moved through pipelines, hydrogen’s future role repeatedly emerged as a way to deal with climate concerns and at the same time address national energy security. (See Global Hydrogen Conference Reveals Plans to Ship Sunshine.)
Roger Martella, GE | Atlantic Council
Hydrogen made from natural gas was also seen as a crucial and immediately available decarbonization tool, initially as a fuel for gas turbine power plants. The Biden administration has allocated $8 billion to help industry create at least four “hydrogen hubs,” two of which would be in regions rich in natural gas.
Roger Martella, chief sustainability officer for General Electric, said using hydrogen as a generation fuel for gas turbines just makes sense.
“We think of hydrogen as a breakthrough technology. And it is because it’s not really commercially feasible today. It’s something we’re investing in around the corner. But it’s also a unique breakthrough technology because it is, I’d say, technologically proven. We can run our turbines today on hydrogen. One hundred turbines have run for more than 8 million hours on hydrogen. Whether it’s blue hydrogen or green hydrogen, the technology exists to create it. We need to focus on the commercial feasibility of it,” he said.
“Our attitude is that all hydrogen is good hydrogen at this point. And what we’re hearing about infrastructure is key. Power generation seems to be the obvious [first] go-to place because it makes sense. We can run our turbines on hydrogen today; we can create power, and that’s an immediate decarbonization benefit,” he added.
Snam CEO Marco Alverà | Atlantic Council
Marco Alverà, CEO of Snam, Europe’s largest pipeline company, said 99% of the company’s pipeline system can move hydrogen today, but the company will start with blends until the demand for hydrogen develops. Snam plans to move hydrogen produced by renewable energy in northern Africa throughout Europe.
“The blending of methane and hydrogen is a good way to create the market, to create immediate demand, like we did for biofuels in Europe,” Alverà said.
Though he did not mention regulators, moving pure hydrogen in pipelines is not currently permitted in Europe but regulators will have to address the issue because pipelines are the least-cost way of moving gas.
“The cheapest way to move any gas is via pipe,” he added, possibly in a reference to plans by Canadian, Japanese and Australian companies and at least one U.S. hydrogen startup to convert hydrogen into liquid ammonia, methanol or a similar liquid chemical and ship it in ocean-going tankers to Europe, Japan and South Korea.
This will take years and trillions of dollars of investment.
“It’s the same with natural gas, and it will be the same with hydrogen,” Alverà said of the slow transition. “There will be different uses for hydrogen, whether it goes into a synthetic fuel like diesel, whether it goes into ammonia, whether it goes into methanol.
“Where it has to replace coal and natural gas for baseload energy in industry, it will be impossible to beat the cost competitiveness of pipelines,” he said.
Regina Mayor, head of energy and natural resources at the global accounting firm KPMG, warned that investment in innovative technologies will be constrained until accounting firms can figure out how to count carbon emissions emitted by current fuels.
She said a surprising number of energy investment analysts “don’t even understand that the basic carbon reporting that we see today [is] based on algorithms, measurements, extrapolations.
“The accounting firms really have to figure out how we [can] start counting carbon emissions in the same way that we count currency down to detailed levels. And only then I think, will we have the level of transparency to reduce emissions that we need to [in order for] the investor community to be confident in what we’re doing,” she said.
Charles Hendry, former UK energy minister | Atlantic Council
That lack of detail puts corporations pressured by investor activists in a quandary, said Charles Hendry, former U.K. energy minister.
“I think investors are becoming much more critical in this area. If you look at the way that they’ve turned their backs on coal, it is very hard to find public investment into coal now. And oil and gas run the risk of moving in the same direction,” he said. “And publicly quoted [traded] companies, they have got to face shareholder activism.
“And if they are not moving in the right direction, if they are not investing heavily in low-carbon technologies in the way that BP and Shell are, if they’re not tackling their methane emissions, if they’re not looking at how they advance carbon capture, they will then be marked down and will find it much more difficult to get there,” he said.
WASHINGTON — Competitive power generators on Tuesday renewed their calls for a national price on carbon emissions while complaining of a lack of market support for the flexible gas-fired generation they say will be needed to supplement renewables for the foreseeable future.
Top officials from Calpine, LS Power, Vistra (NYSE:VST), Competitive Power Ventures and Tenaska delivered their views at the Electric Power Supply Association’s Competitive Power Summit at the National Press Club, where some of their concerns were echoed by a panel of Ph.D.s and the CEOs of NERC, PJM and ISO-NE.
“I think it’s worth saying one more time: national carbon price. It’s such a no-brainer,” said Sherman Knight, president and chief commercial officer for Competitive Power Ventures. “It’s straightforward. It is efficient, and it gets it gets the job done.”
“I don’t know why we continue to have this debate about what’s the most direct way [to accomplish decarbonization]; what’s the most … even playing field; what seems to be administratively easy to do,” agreed Curt Morgan, CEO of Vistra. “And for the life of me, I’ve met with a lot of people on Capitol Hill — many you guys probably have too — and I still can’t quite get my head around why we can’t get something like a carbon price. [It’s] baffling, I think, to all of us. There is movement though; I will say I’m not as pessimistic as I was a year ago.”
“If we don’t put that price of carbon on the system, I don’t see how anything could work,” Harvard economist William Hogan said in the last session of the daylong conference. “We’re doomed to fail. So I’m very pessimistic about it.”
“I agree with everything that Bill just said,” economist Paul Sotkiewicz, president of E-Cubed Policy Associates, joked in response. “In fact, now I’m so depressed, I’m going to bring my hair dryer into my shower.”
A More Expensive Transition
“The energy transition is going to be expensive. … And it’s going to be far more expensive if we go around choosing pet projects here, here and here,” Knight said. “We feel like we’re chasing state mandates, as opposed to focusing on reliability and reducing carbon in the industry. And that gets a little bit frustrating. … We can do it, you know, but certainly it’s less effective [than] if there was a federal, or even just a regional — within an RTO — consistent, policy.”
ISO-NE CEO Gordon van Welie cited a study by the RTO that predicted the region could face negative LMPs within a decade that would “wreck the markets.”
“As the states grapple with that reality, I think there’s some empathy starting to develop towards having to put a carbon price into the electricity markets. It’s probably not the right place to do it; the right place to do it is in [the economy-wide Regional Greenhouse Gas Initiative] or some national scheme. But both of those are not really politically feasible at this point. So the next best [place] is to put it into the ISO markets. And we’re going to need to have the states tell us what number they want.”
“It pains me to say it, but I think there is value in some incrementalism, mostly because we have no other option,” said Arnie Quinn, vice president of FERC-jurisdictional markets for Vistra. He added that his company would also support a forward clean energy market like that under discussion in ISO-NE. (See Draft Study Weighs Tradeoffs of CO2 Pricing, FCEM for ISO-NE.)
“Incremental carbon pricing is better than none,” agreed PJM Independent Market Monitor Joe Bowring, who noted RGGI has had a “demonstrable impact” on system dispatch in PJM despite the fact that only four PJM states currently belong to RGGI.
The RGGI model allows states full control over the carbon quantity and price variables. The results of those state decisions change the marginal costs of generators in the PJM market, and the impacts flow through the normal market dynamics without the RTO having to make any policy decisions about carbon.
“There has to be more state cooperation — whether it’s in the form of a carbon price, or in recognizing the value of transmission — to help meet state renewable energy and other goals along with resource adequacy,” said John Moore, director of the Natural Resources Defense Council’s Sustainable FERC Project.
Travis Fisher, president of the Electricity Consumers Resource Council (ELCON), said state targets “that say you have to get to this place 30 years from now [is] a very expensive way to do it.”
Instead, policymakers should say, “‘We are going to minimize the cost of the entire system — generation, transmission, all parts of it — we’re going to minimize the cost of it, subject to all the other policy constraints.’ … It’s got to be reliability, at least cost.”
The Length of the Natural Gas ‘Bridge’
The role of natural gas also was a recurrent theme in the discussions, with NERC CEO Jim Robb and PJM CEO Manu Asthana joining generators in insisting that natural gas will be needed to supplement intermittent resources and ensure reliability.
“In a world where policymakers don’t want gas — gas has become the new coal in many areas — what do we think is going to provide that balancing capability?” Robb asked. “It could be hydrogen, but that’s a long, long way away. It could be batteries, but we don’t have a battery technology that can perform cost-effectively at the scale we would need it to with the durations that we would need. It could be small nuclear reactors [with] flexible characteristics. But that’s a long, long way off.”
Robb said he agreed with those who see natural gas as a “bridge” to a low-carbon future. What “terrifies me in this transition [is] a lot of people think that the bridge is about this long,” he added, spreading his hands a few inches apart. “And I think most people in this [conference] room would say this bridge extends from that wall to that wall. Your point of view on the length of that bridge dictates an awful lot as to what you do in terms of investing in infrastructure.”
The inability to invest in gas infrastructure or electric transmission, Robb said, “is really going to cripple our ability to meet any of the emission-reduction targets that we have.”
“I think it is a long bridge,” Asthana responded. “In fact, PJM is on the record as saying that we think we need access to our thermal generation until and unless there’s replacements of assets in place.”
Devin Hartman, energy and environmental policy director for R Street Institute, said NERC and others need to address a “reliability and cost education problem.”
“There are folks — a sizable population — that genuinely believe that we can just force all natural gas off the system nationwide [in] this decade, replace it with renewables, and costs will go down and reliability will be maintained,” he said. “We have a stronger role to play in educating policymakers and others in understanding these mechanisms. How do markets drive [generator] entry and exit? How do they manage risk?”
Where’s the Market Support?
Asthana said capacity markets may be increasingly important in providing incentives to gas generators as energy markets respond to renewables with zero marginal costs. “And you know, maybe there’s an answer in the form of other ancillary services that we procure for ramping or some other form of flexibility.”
Generators said that while they continue to support competitive markets, they are not providing price signals for new gas units.
Vistra’s Morgan said the industry is “at a crossroads,” with reliability at stake.
“I may be the boy that cried wolf, but that’s OK. I’m telling you … there is a big disconnect in places like PJM and in places like ISO New England if we don’t do something about this,” he said. “We’ve got to have an analysis done that figures out that marginal resource that is necessary, under the most extreme circumstance, with the intermittent resources out, that will ensure reliability. And the ISOs have to be the ones to step up and do this because they’re the objective person. [If] we come to the table, people say, ‘Oh, they’re those greedy generators, or ‘they’re just talking their book again.’
“I don’t know how to build a gas plant today, in a competitive market, with not knowing how long it’s going to be around,” he continued. “I don’t know how you can say that $50/MW-day, or $2 or less a kilowatt-month on a capacity clear supports new build of a gas plant. … Look, competitive markets have brought better reliability, lower costs. … But we’ve got a lot of hands in these markets, and a lot of forces are [attempting] to drive lower and lower capacity” prices.
CPV’s Knight agreed that “price signals do not currently support investment in new dispatchable generation in most of the country.”
“I think that what we have to be careful about is saying competitive markets aren’t incentivizing investment. And I think that is absolutely not true. I think what we’re talking about here is tweaking the competitive markets … as the infrastructure transition occurs … so that it can unleash the power of private capital to come in and make investments — or not have private companies preserve capital by retiring perfectly good assets that are needed for the transition.”
Generators said the move to effective load-carrying capability should help the most flexible gas units.
“If it takes you 24 hours to start up, that’s not that useful to the grid with intermittent resources,” Morgan said. “So combined cycle plants that have much more flexibility ought to have a higher effectiveness rating than … a gas steamer that takes 24 hours to start up. … We can’t just come in always pushing our own [generation]. We have to admit that some of our dispatchable resources are less effective.”
The Bonneville Power Administration is on track to enter the Western Energy Imbalance Market on May 3, despite lingering issues with market integration software, agency officials said Thursday.
“It is still very much full speed ahead as we continue to work through the outstanding milestones and progressing towards our May go-live date,” Nita Zimmerman, BPA’s chief business transformation officer, said during a stakeholder meeting.
The federal power marketing agency was originally scheduled to begin transacting in the WEIM on March 2, along with Avista and Tacoma Power. But after beginning parallel operations Dec. 1, BPA delayed entry by two months because of technical problems and customer training issues. The parallel production environment allows new participants to submit bids and base schedules, collect e-tags and learn how to adapt operations to real-time developments. (See BPA Postpones Western EIM Entry by 2 Months.)
“We managed through the slight delay, and we’ve made progress to meet the milestones necessary for participation, including resuming parallel operations [with the WEIM] on March 8,” Zimmerman said.
She said BPA on Wednesday submitted its WEIM “readiness attestation” to CAISO, the market’s operator, which will in turn submit the document to FERC.
“With this success achieved, there is still more work to be done,” Zimmerman said. “BPA will continue to test and implement the systems necessary to participate in the EIM.”
The outcome of that testing will be the subject of an April 19 meeting of BPA executives responsible for issuing a “go/no-go” decision on the May 3 entry date, said Mark Symonds, the agency’s director of commercial operations.
“That’s where we bring our executives together and make sure, from a functional readiness standpoint, we are in all-systems-go from a systems, process and people standpoint, to make sure that we have the level of confidence that we need to run our EIM operations on May 3,” Symonds said.
Elsa Chang, BPA’s EIM program manager, said the most “critical” problems to be addressed have to do with integration of the “sub-allocation” and outage management systems related to WEIM operations.
The problem with the sub-allocation system has been particularly thorny. That system is designed to allocate the costs and payments for WEIM settlements back to BPA customers. Testing has revealed discrepancies between CAISO settlement statements and the sub-allocation amounts, BPA’s Rasa Keanini said.
Chang said BPA expects to complete its work on the sub-allocation system by the May 3 WEIM go-live date but also has a contingency plan in place in case fixes provided by the software vendor fail to pass BPA’s testing by that date.
“We plan to have the work delivered no later than June 25, which is the day BPA issues our first EIM bill to our transmission customers,” she said.
Chang said BPA has also encountered “performance issues” with its WEIM outage management software, which went live March 8 when the agency re-entered parallel operations with the market.
“This system is necessary for BPA to participate in the EIM, so issues can potentially result in both safety and reliability problems,” Chang said, adding that BPA has “patched” the system and will continue to monitor it and resolve any problems.
Customer Concerns
Stakeholders on the call voiced concerns about what BPA will do if the software system issues have not been sufficiently addressed by the time BPA official meet on April 19 to make the “go/no-go” decision.
“What happens if things don’t, don’t go quite as well as we expect?” Adam Cornelius, principal utility analyst with Snohomish County Public Utility District in Washington, asked.
“That’s really a great point,” Symonds said, “and it’s one that we’re watching very closely and why we have been working very collaboratively with our vendor to clear the defects that get identified and be able to test the sub-allocation routine and not just validate the routine itself.”
Symonds said he expects BPA to make “significant progress” on that front ahead of the April 19 meeting.
“It is possible that things could go in a different direction,” Symonds said. “That’s why we’ve continued to reinforce our [WEIM] participation principles up and down the line for years — that we have the ability to manage our participation in the market.”
Ed Mount, director of power supply planning and operations at The Energy Authority, pressed the sub-allocation system issue, saying the allocations are “where the rubber hits the road” for his company’s customers.
“Is there a contingency plan for billing customers if there are still discrepancies that are being seen between the sub-allocation system logic and what you’re being billed with CAISO?” Mount asked.
Symonds described the complexity of that system logic and the importance of the quality of the metering data being fed into the system.
He said BPA would contact “selected” customers — mostly those at aggregated customer meter points — regarding the data over the next few weeks “so that we can tackle any of those issues that we think we are seeing now, rather than waiting until after go-live or even our first settlement statement to see it.”
“We also have different contingency plans that we can exercise along the way, in the event that we continue to have any issues with how those calculations come together,” he added.
WASHINGTON — Extreme weather events during the last two years have brought “extraordinary clarity” about the reliability risks posed by the changing climate, NERC CEO Jim Robb said Tuesday.
“These weather systems are … longer, deeper, broader,” Robb told the Electric Power Supply Association’s Competitive Power Summit, citing “heat domes” in the West and the February 2021 winter storm, named “Uri” by the Weather Channel. “And that’s a real problem, because utilities can’t rely as much on transfers [from other regions] to bail them out.”
NERC was able to identify generation that could have preserved ERCOT’s ability to serve load during Uri, “but we’d be wheeling it from peninsular Florida and Montana and places like that,” Robb said. “And the cost to build that transmission is ungodly.”
Uri resulted in several days of rotating blackouts in Texas to prevent a grid collapse, the largest manually controlled load shed event in U.S. history. It also showed that weather can cause outages to more than wind and solar generation. Natural gas-fired units represented 58% of all generating units that experienced unplanned outages, derates or failures to start, a joint FERC-NERC report concluded.
As weather challenges rise, the drive to electrify transportation and heating means the demand for reliability will only increase, Robb said. “Our tolerance for even momentary outages or any sort of disruption is going to go to zero very, very quickly.”
As a result, he said, “we really need much, much better situational awareness between the system operators, the generators and, importantly, the fuel suppliers.”
A common link in NERC’s assessments of major reliability events driven by weather — including the 2011 and 2018 cold weather events — is that “the system operator and the generators just didn’t know whether their fuel was going to show up or their plants could perform. So, the operators are scrambling to make decisions in real time that they should have had the ability to plan for,” Robb said.
He also repeated his call for a different “mindset” on reliability and resource adequacy, saying the calculation of peak annual load plus reserve margin is no longer sufficient because of intermittent generation and gas plant fuel risks.
Concerns are most acute in California, Texas and New England, “the three hotspots for how the world has evolved,” Robb said. “This will be coming to the theater near you soon. It may take a while, but the dynamics are clearly there.”
Also speaking at the conference, Paul Sotkiewicz, president of E-Cubed Policy Associates, said ERCOT needs “some sort of reliability call option.
“I’m not going to use the term ‘capacity market’ because that’s a dirty word in Austin. … But the whole point is that you need some sort of reliability call option to say, when the system gets to a certain condition — I don’t care if it’s summer peak, winter peak, the shoulder period — if I need you, I can call on you.”
Calpine CEO Thad Hill echoed Robb’s concern, saying the Biden administration and some state energy policymakers are causing “changes to major tariffs in the markets, where it’s about emissions first, cost second and reliability third.”
Obligation to Perform
Robb said the wholesale markets must redefine generators’ “obligation to perform.”
NERC learned that many generators shut down by Uri had made “a pure economic decision” not to winterize, Robb said.
“They said, ‘Look, it’s not worth it for me to invest in this amount of winterization for this unit because I just won’t show up that day. And sure, I may forgo a day of very high prices, but I don’t [think] the probability of that happening justifies the investment.
“We have to create the proper set of incentives and … penalties so that a generator saying, ‘I’ll be there’ — they’ve got to be there. And if they’re not, I’m sorry, they should get whacked on the knee. And they should be incented to be there under a broader range of conditions than we might have thought of before. Because the tails in the distribution of outcomes — these tails are becoming really, really important.”
Educating Rate Regulators
Devin Hartman, energy and environmental policy director for R Street Institute, said NERC needs to help educate policymakers about the need for flexible natural gas units and services such as ramping. (See related story, EPSA Members Renew Call for Carbon Price; See Long ‘Bridge’ for Gas.)
State utility regulators “are really struggling with prudency decisions now. They’re looking at this and saying, ‘We don’t even understand you’re talking about ‘ramp,’” Hartman said.
“This has never been classically built into [integrated resource plan] considerations. And they’re really struggling to kind of operationalize it at that level. Increasingly, reliability cost and environmental performance are a function of regional portfolio conditions. And that means … you actually have to have enhanced information flows and better coordination.”
Arnie Quinn, vice president of FERC-jurisdictional markets for Vistra (NYSE:VST), said the grid is unlikely to see “reliability catastrophes” as a result of the transition to renewables.
“I think it will be more likely that we will see a lot of resource adequacy RMRs [reliability-must-run agreements] and fuel security RMRs and a bunch of other little RMR actions and things that bury costs,” he said. “And quietly, costs will go up in a way that’s very non-transparent.”
Glass Half Empty
Asthana and Hartman expressed optimism that RTO stakeholder processes will develop the market designs needed to support efficiency and reliability.
Robb was less confident.
“We got to get the stuff figured out now so that as we redevelop the system over the coming 10, 20, 30 years, we’re leaving something behind that we’re going to feel proud of,” he said. “Right now, it’s not clear to me that we’re going to get there. You guys are optimistic. I’m paid to be the [glass] half-empty guy.”
The long-standing fight over Eversource’s planned East Boston substation is not over.
The utility is asking the Massachusetts Energy Facilities Siting Board to expedite approval of 15 state and local permits and certificates it says have been delayed or not considered quickly enough.
But in doing so, Eversource has given the project’s many vocal opponents another opportunity to state their case for why the project shouldn’t go forward at all.
The EFSB initially approved the project, which has served as a powerful example of the conflict between regional transmission planning goals and local siting concerns, last February. (See Controversial East Boston Substation Approved.)
Eversource’s Case
Eversource, backed by Massachusetts officials, has warned that the substation is necessary to fill a fast-growing capacity need.
“Electric service in the East Boston and Chelsea area is at risk,” said Craig Hallstrom, the company’s president for regional electric operations, at a public EFSB hearing Wednesday.
He called the plan a “standard utility design” to locate a substation at a customer load center. East Boston, he said, is the only Boston neighborhood that doesn’t have one, instead being served by the Chelsea substation.
A preliminary design concept from Eversource for the facade of its proposed substation | Energy Facilities Siting Board
“Without this new substation … it will be a challenge for this area to be part of the new electrification of systems like EVs and heat pumps,” Hallstrom said.
The project won’t be complete for several years once construction starts, but that hasn’t stopped Eversource representatives from employing grim warnings about immediate danger in their arguments for the plan.
“This summer, we’re hoping we have some beautiful hot weather as things go back to normal and we’re heading out of this pandemic,” said Nicole Bowden, an Eversource community relations specialist.
“You’re coming home from work. Your kids are coming home from camp. Everyone’s tired. You’re ready to get in the shower. You don’t have any electricity. The water’s not hot. You can’t sit down and watch the Red Sox game. The A.C.’s not blowing; the fans aren’t blowing. And it’s going to be three, four, five, six days of this.”
“We want to avoid this,” Bowden said.
Opposition Continues
The project is opposed by many East Boston residents and nearly every relevant elected official in Boston, from city council to the mayor to the state’s two senators. The city’s voters also overwhelmingly opposed siting the project there in a non-binding referendum in November.
Widespread frustration among opponents stems from the project’s location near public spaces, in a flood zone, and in an environmental justice community that has seen a long history of environmental hazards and pollution.
That opposition has extended to the company’s latest request to expedite the 15 certificates.
“As far as my interpretation, this is Eversource requesting to evade the permitting process and build this thing before the appeals that have been filed … are finished,” East Boston resident Leonard Olsen said at the hearing. “It’s equally absurd as the project itself.” Opponents have also challenged Eversource’s claims about the need for the project, noting that past load projections over the long process of planning the project have at times failed to come to fruition.
“It feels a bit like the boy who cried wolf, as we’ve seen what the actual summer peak loads have been in comparison to some of what the projections are,” said John Walkey, director of Waterfront & Climate Justice Initiatives at the advocacy group GreenRoots.
Some public officials representing the area recognize the need for more infrastructure to meet the area’s demand for electricity, especially considering decarbonization efforts. But they say Eversource has not met the moment.
“The opposition is not that we don’t need infrastructure to meet our greener future, that we won’t need to be able to generate for our EV stations,” said Lydia Edwards, a former Boston City Councilor who was elected to the state Senate in January. “I just think what we’ve been trying to say for the past several years, and in many languages, is that we can be more creative than this. This is not going to prepare us or help us become healthier in our future,” Edwards said.
What’s Next?
Anyone who wants to be a participant or intervenor in the EFSB case has until April 19 to file a petition.
The EFSB will hold an adjudicatory hearing on the Eversource certificate request starting on May 17.
In its consideration, the board will look again at the need for the facility, its design, and whether granting an exemption from state and local requirements is “reasonable and consistent with providing necessary energy supply for the Commonwealth with minimal impact on environment and lowest possible cost,” board member Donna Sharkey said.
FERC on Tuesday conditionally granted Rockland Electric Co.’s request for a new base return on equity (ROE) of 10.54% and a 50-basis-point ROE adder for its continued participation in PJM (ER22-910).
The commission also accepted Rockland’s proposed updated annual transmission revenue requirement (TRR) under PJM’s tariff, suspending it for five months to become effective Aug. 30, subject to refund.
Both the ROE and TRR will be subject to review in hearing and settlement judge procedures established by the commission.
Rockland’s service territory includes parts of three counties in New Jersey that border New York — Bergen (eastern division), Passaic (central division) and Sussex (western division). The company said it turned over operational control of its eastern division transmission assets to PJM in 2001, while Rockland’s central and western divisions, along with Orange and Rockland Utilities (O&R), are members of NYISO.
According to Rockland, New Jersey law does not mandate that it maintain membership in PJM or any other transmission organization. Rockland said its transmission systems with O&R have historically been operated as a single system, “irrespective of state geographical boundaries or regional operating authority jurisdiction,” and O&R “continues to design and operate them as a single integrated system.”
“Prior to joining PJM, Rockland contends that it did not have its own annual transmission revenue requirement or transmission rates on file with the commission,” FERC said in its order. “However, upon joining PJM, Rockland separated its annual transmission revenue requirement for its eastern division from O&R’s transmission rate.”
Rockland said it conducted a “variety of transmission projects to expand and improve the safety, reliability, and capacity” of the integrated transmission system from 2016-2020 that “justifies” it updating its transmission rates. The company said it derived its updated annual transmission revenue requirement by:
calculating the 2020 annual revenue requirement for the integrated transmission system of $73,637,503 and
multiplying it by the ratio of the 2020 Rockland system peak load of 395 MW to the 2020 integrated transmission system peak load of 1,416 MW.
Rockland said it applied the calculation with a reduction of $187,217, which “accounts for the annual passback of net excess accumulated deferred income taxes (ADIT),” coming up with an updated annual transmission revenue requirement of $20,354,318, equating to $51,530 per MW/year.
The company said the updated rates were just and reasonable because they are “derived from a methodology the commission has already approved” and “reflect a composite fixed charge rate composed of reasonable factors derived from reasonable calculations.”
Rockland also requested a 50-basis-point adder to its base ROE for continued participation in PJM, saying the commission approved the participation adder in its 2017 rate case. The company said its PJM membership “continues to be voluntary.”
The New Jersey Division of Rate Counsel argued that Rockland “improperly proposes to include the costs of facilities that are physically located within the footprint of and under the control of NYISO and are not available for use by PJM transmission customers.” The Rate Counsel also argued that Rockland’s load ratio share methodology “leads to a result in which a PJM transmission customer physically located in the PJM footprint is paying a portion of the costs of O&R facilities located within the NYISO footprint that NYISO operates and controls.”
“Rate Counsel argues if the combined O&R and RECO transmission facilities are an integrated transmission system, then the customers on the two systems are similarly situated and it would be unduly discriminatory for customers on an integrated transmission system to pay different rates as a result of where on the overall system they connect,” FERC said in its order.
Rockland responded by saying the Rate Counsel attempted to “inaccurately paint a picture that the integrated transmission system consists of two separate and distinct pieces that are operated and controlled by two different regional transmission organizations.”
The company also said that if the commission adopted the Rate Counsel’s rationale, it “may have widespread dramatic impacts on transmission ratemaking with respect to any transmission system that is owned by more than one utility.”
Commission Finding
FERC conditionally granted the request for a 50-basis point adder, saying it was consistent with Section 219 of the Federal Power Act and commission precedent.
“Rockland is a member of PJM, and there is no evidence in the record suggesting that its membership is not voluntary, such as evidence suggesting New Jersey law mandates Rockland maintains its membership in an RTO,” FERC said.
The commission conditioned its approval on the adder being applied to a base ROE shown to be “just and reasonable,” with the resulting ROE required to fall within “the applicable zone of reasonableness,” to be determined in the settlement judge procedures. Approval of the incentive was further conditioned on Rockland’s continued membership in PJM.
The commission found that its preliminary analysis suggested the proposed rate changes “may be substantially excessive” and would be “more appropriately addressed in the hearing and settlement judge procedures.”
FERC suspended the rates for five months and encouraged the parties to the proceeding to “make every effort to settle their dispute” before hearing procedures begin.
Commissioner Mark Christie issued a concurrence, saying an ROE “should reflect the market cost of equity capital, no more and no less, to the best of the regulator’s ability to determine, including pricing in risk.”
“An ROE adder, by definition, awards the utility more than the market cost of equity capital,” Christie said. “An ROE adder is literally an involuntary gift from consumers to a monopoly provider. While I recognize that ROE adders for RTO membership reflect current commission policy dating back several years, it is my hope we will finalize our proceeding initiated last year. This is particularly salient at a time when transmission charges are among the fastest growing components of consumers’ bills.”
Reaching President Joe Biden’s goal of putting 30 GW of offshore wind off the Atlantic and Pacific coasts by 2030 will require a supply chain capable of producing more than 2,100 wind turbines and more than 6,800 miles of cables, according to a report released Monday by the National Renewable Energy Laboratory (NREL).
And most of the components for those turbines and cables must initially come from Europe, even though “it is unlikely that the international suppliers will have sufficient throughput to support construction of both European and U.S. offshore wind projects,” the report says.
“If a domestic supply chain is not developed in time, bottlenecks in the global supply chain will present a significant risk to achieving the national offshore wind energy target,” the report says.
But Ross Gould, vice president of supply chain development at the Business Network for Offshore Wind (BNOW) sees such supply chain challenges in terms of economic development and job growth. “We know that there is a wide range of opportunities for manufacturing companies in the U.S. to participate in the offshore wind supply chain,” said Gould, who worked with NREL on the report. “These offshore wind projects have the capability of creating tens of thousands of jobs.”
By 2028, offshore turbines using 100% American-made components could create up to 62,000 jobs, the report says, and even turbines with only 25% domestic content could generate about 15,500 jobs, the report says.
But the path to hitting any of those numbers, as laid out in the report, is daunting. For example, while plans are underway to build 11 new OSW manufacturing facilities that can produce major components, such as turbine blades and towers, major gaps exist in the domestic supply chain for the components those factories will need.
Offshore turbines contain around 8,000 components, many of them much larger than similar components for onshore turbines, Gould said.
Offshore turbine blades are as long as a football field, “significantly larger than their onshore relatives,” Gould said in an interview with NetZero Insider. “And so, while we have the capabilities to produce [blades] for onshore, those companies would need investment to upgrade their equipment, as well as potentially training [employees] on the new equipment.”
Other components are not being produced, or produced at scale, in the U.S., the report says. For example, the permanent magnets used in offshore turbine generators require rare-earth metals that are not mined and cannot, at present, be processed in the U.S.
Still another obstacle, the huge size of some offshore components may also mean they can’t be transported by highways, Gould said. They will need to be built near a body of water and port facilities large enough and deep enough for the wind turbine installation vessels (WTIVs) and other ships used to build and operate offshore projects ― which brings up additional supply chain gaps, the report says.
Of the 22 ports on the Atlantic Coast, the Portsmouth Marine Terminal in Virginia is the only one that currently has the capacity to accommodate WTIVs, the report says. Others, such as the New Bedford Marine Commerce Terminal are not large enough but can serve as marshalling areas, using smaller “feeder barges” to ferry components out to installation vessels.
Such workarounds may be less expensive, the report says, but “they also introduce additional risk and logistic complexity to transfer components from the barge to the WTIVs at sea.”
These installation vessels must also comply with the provisions of a 1920 federal law known as the Jones Act, which requires that ships carrying goods between U.S. ports be American built, owned and operated. The report estimates that at least five such ships will be needed, but only one is currently under construction, for Dominion Energy’s Coastal Virginia Offshore Wind project.
Estimated cost per WTIV ranges from $250 million to $500 million, the report says, and each ship could take up to three years to build.
The Next BOEM Auction
The study is the first of two reports NREL and other industry stakeholders, including BNOW, will be producing on the offshore wind supply chain. The first part is intended to set out the scope of the needed buildout and the challenges ahead, Gould said. The second, to be published later this year, will look more closely at the kinds of investments and other support that will be needed to reach Biden’s 30 GW goal.
The push for getting an offshore supply chain up and running as quickly as possible is being driven by the growing number of offshore projects in development up and down the East Coast.
In February, the Bureau of Ocean Energy Management (BOEM) held a record-breaking auction for six offshore leases in the New York Bight, pulling in bids totaling $4.37 billion. If fully developed, the six auction sites could produce more than 19 million MWh of electricity per year, enough to power close to 2 million homes, based on BOEM’s estimate of 3 MW/sq km. (See Fierce Bidding Pushes NY Bight Auction to $4.37 Billion.)
The next BOEM auction, announced Friday, will be held on May 11, for two offshore leases in the Carolina Long Bay, off the coasts of North and South Carolina. According to the BOEM announcement, the two sites, totaling 110,091 acres, could produce up to 1.3 GW of energy, enough to power 500,000 homes. The final sales notice for the auction lists 16 eligible bidders, including Duke Energy Renewables, Ørsted North America and Shell New Energies.
With thousands of megawatts to be built in less than a decade, Matt Shields, senior offshore wind analyst at NREL, estimates that two or three manufacturing plants will be needed for each major offshore wind component, such as blades and cables. Costs per facility could range from $200 million to as high as $900 million, he said.
“These figures typically don’t include additional investments in port capabilities to support these big facilities,” Shields said in an email to NetZero Insider. “We can safely say that, if we do build all these facilities, it will be in the billions of dollars and will require a mix of public [and] private investment.”
While the current report does not address policy, Shields said, “There are a lot of nuances about what exactly is needed. … The most important thing is certainty about projects actually getting built so that OEMs can have low-risk return on investment.”
FERC on Monday approved an agreement between Dynegy and its Office of Enforcement that will have the company pay more than $569,000 to settle allegations that it violated the PJM tariff by misrepresenting the ramping levels of 10 of its combined cycle combustion turbines in 2017 (IN22-3).
Enforcement found that the units’ real-time energy market offers misrepresented that they could “ramp to their maximum oil-based output attained during their summer capacity tests (ICAP) while running on gas.” The office also alleged that Dynegy failed to comply with the requirement that each unit be able to “change output at the ramping rate specified in the offer data.”
Dynegy stipulated to the facts in the agreement but neither admitted nor denied the alleged violations. The company agreed to pay disgorgement plus interest, totaling $119,425 and a civil penalty of $450,000 to the U.S. Treasury and to submit two annual compliance monitoring reports identifying “any known violations” regarding the PJM units identified in the investigation.
“The PJM market and its market participants bore the cost of Dynegy’s violation,” FERC said. “The commission directs PJM to use its best efforts to allocate the disgorgement funds on a pro rata basis to affected market participants.”
Background
The commission said the 10 units identified in the investigation were split among three facilities in PJM: Pleasants Power Station in West Virginia; Armstrong Power Station in Pennsylvania; and Troy Energy Facility in Ohio.
FERC said during PJM’s capacity auctions for the 2016/17 and 2017/18 delivery years, the previous owner of the units offered and cleared capacity “at a level that would require the units to run on oil” to meet their ICAP during a capacity test, with Dynegy inheriting an “oil-based” ICAP for each unit for both delivery years when they were acquired.
“However, these units were unlikely to be able to reach their oil-based ICAP when the units were already running on gas on summer days in 2017 consistent with the ramp rate that Dynegy entered for these units’ real-time offers,” FERC said.
In the summer of 2017, Dynegy’s real-time offers represented that the units could attain oil-based ICAP “in less than a minute if dispatched from a unit’s maximum output on gas that day to the higher oil-based ICAP.”
FERC said for the units to achieve maximum output after starting on gas in the summer months, they would “likely have to switch to oil” by ramping down to about 20 MW and then ramping back up after the fuel changeover was completed. The process would take about 28 minutes to go from the unit’s daily maximum output on gas to the oil-based ICAP.
The investigation found the real-time offers “misrepresented the ramping rate for the segment of the real-time offer curve that could only be reached on oil” and that Dynegy submitted “false or misleading information” to PJM that the units could ramp upward to the oil-based ICAP in one minute.
Dynegy calculated each combined cycle’s maximum generation using a formula incorporating the next day’s forecasted ambient conditions under both gas and oil, the commission said, and the calculations were used to determine the unit’s day-ahead and real-time offer curves and economic maximum for the day.
“In the summer months of 2017, the oil-based ICAPs were generally too far above the daily predicted gas max for Dynegy to reasonably expect that the units could reach their oil-based ICAP on gas alone,” FERC said.
Dynegy sold the Troy and Armstrong facilities in July 2017 to LS Power. Vistra (NYSE:VST) acquired Dynegy, including the Pleasants units, in April 2018.
