FERC on Monday released its fiscal year 2024 budget request, with the regulator seeking a total budget of $520 million for the year.
The commission recovers the full costs of its operations through annual charges and filing fees assessed on the industries it regulates and deposits that with the Treasury, offsetting its congressional appropriations entirely.
The funding request is about 2.3% above fiscal year 2023 and includes the hiring of 58 additional full-time equivalent employees, bringing the total number of staff at FERC to 1,566.
“The additional resources will allow the commission’s program offices to undertake forward-looking strategic studies and expand external engagement efforts with a wide range of stakeholders,” FERC said. “In addition, targeted FTE investments will enhance the commission’s advisory services, strengthen organizational capabilities, streamline processes and minimize inefficiencies to address the commission’s evolving mission requirements. The FTE increase will continue to directly staff the new Office of Public Participation established in FY 2021.”
The first priority that the document lays out for FERC in the next fiscal year is to modernize electricity market design.
“Current market designs may not allow for the operational flexibility needed to address changing system needs that are being driven by an evolving resource mix and changing load profiles,” FERC said. “The commission will work with stakeholders to explore the gaps in current electricity market designs and identify potential reforms to modernize them.”
FERC started that work in FY 2022, requiring additional information in parties’ electronic quarterly reports. It has also worked to improve credit rules in the ISO/RTO markets.
This year and next, FERC will continue to evaluate the impact of the new database on the market-based rate program and evaluate credit rules, it said.
Another priority is to facilitate the development of the electricity infrastructure needed for the changing resource mix, FERC said. A large amount of new transmission is needed to address the challenges of and facilitate the interconnection of large quantities of new renewable resources in the markets while preserving reliability. The commission has issued some proposals on transmission planning and interconnection queues, and it will continue to evaluate those going forward, it said.
On its enforcement efforts, FERC said it was starting to make use of new technology and plans to transfer key data assets into the cloud by the end of this fiscal year. Moving surveillance screening and analysis to the cloud will make it work better and improve staff’s ability to monitor electric and natural gas markets, it said.
Another one of FERC’s goals for the fiscal year is to continue safeguarding infrastructure from threats to reliability and security, such as extreme weather, climate change and cyberattacks.
“The commission will address this priority through an integrated set of targeted actions designed to mitigate or avoid the adverse effects of widespread and extended power outages caused by these threats,” FERC said.
Western Power Pool CEO Sarah Edmonds would like to see the Western Resource Adequacy Program (WRAP) become “binding” on its participants as soon as possible, but making that transition could still be years away, she said last week.
After winning FERC approval for the WRAP tariff last month, WPP now has the option to initiate the binding phase of the program during any season between 2025 and 2028. At that point, participants will subject to “very, very significant” penalties for not meeting their resource adequacy obligations outlined under the program, Edmonds said in a briefing to WECC’s Board of Directors on Wednesday.
Edmonds emphasized that the WRAP is not the product of any state or federal requirements but was developed by electric industry participants as a voluntary program to address concerns about imminent RA shortfalls in the West.
“Once [load-serving entities] are in the program, they are obligated at least for a period of two years to fully comply with all the [RA] metrics, so to get these companies comfortable with jumping into this compliance framework, where there are significant consequences, we have to offer some flexibility about when the binding season will occur,” Edmonds said.
The current “nonbinding” phase continues to offer important lessons for participants, she pointed out.
“To be candid, some load-serving entities are in better shape to go binding than others. Others need a little more time to adjust their procurement strategies and their positions relative to what they see coming at them,” she said.
Edmonds said the WPP is in a “very active” discussion with the WRAP’s current 19 participants about when to enter the binding phase.
“I will certainly be pushing for the earliest possible binding season, but we also have that built-in flexibility, and that was the bargain that we struck to get this program off the ground,” she said.
‘Insurance Policy’
Edmonds outlined some of the challenges — and risks — participants face in entering the binding phase. She said the WRAP is “a little novel” compared with other RA programs in that it includes a strict deliverability requirement, which stipulates that a resource must have 75% firm or conditional firm transmission from source to sink to be considered compliant with the program’s counting rules.
Seven months ahead of a season, a participant must provide WPP a “workbook” of “forward showings” of their RA, which the program operator evaluates to ensure the participant is meeting its specific allocation of the WRAP planning reserve margin.
“When we say you’re a little bit short, and you have few months to cure, if you don’t cure, you are subject to pretty significant penalties,” Edmonds said. “They are of such significance that they’re really trying to send an economic signal that you should not lean on this program. You cannot rely on this program to serve your load; you need to solve your own problem.”
Once a season becomes the current operations period, the program operator will monitor conditions and notify participants of any expected RA deficits relative to their workbooks seven days in advance of an operations day.
“If they want to go out and fix that problem without relying on the program, we encourage it. The program is not meant to be the first go-to place for serving load; it is meant to be an insurance policy … a backstop,” Edmonds said.
From an operational standpoint, the WRAP “is really delivering surplus to deficit entities in those hours of highest need,” Edmonds said. “It relies entirely on using traditional bilateral trading mechanisms and transmission which is sold under open-access transmission tariffs. We’re not a market; we’re not creating anything there. We’re relying on what’s out there, but we are matching up the surplus and the deficits and creating the overall structure.”
Edmonds likened the WRAP to a contingency reserve program “in the sense that we are creating a pool with the right to call on the pool.”
“Those entities receive that insurance policy. They get help through that difficult day to serve their load,” subject to paying a settlement price for drawing on the pool, she said.
And while the WRAP has the potential to reduce its participants’ planning reserve margins over time through more coordinated resource sharing and a greater diversity of resources, getting there is part of the broader learning process of the nonbinding phase, Edmonds said.
“Is everyone in a position to yield that benefit right away? Probably not. I mentioned to you that there are some entities that are going to have to adjust into that position over a period of time. But overall, and in the long term, the goal of the forward showing is to get to that lower potential position,” Edmonds said.
WASHINGTON — The Inflation Reduction Act and Infrastructure Investment and Jobs Act passed last year have given the renewable energy industry policy certainty with hundreds of billions of dollars in funding, but the industry faces some challenges in maximizing its opportunity.
“For the long term, we have the challenge ahead of us on transmission, building up the workforce that we need, on supply chain — all those things need to come together,” Enel North America’s head of public policy, Jack Thirolf, said at ACORE’s Policy Forum on Thursday. “And we need to not wait.”
One of the short-term issues facing the industry is waiting for the Treasury Department to implement many of the IRA’s tax provisions, but that has not stopped development, according to Bank of America Managing Director Ray Wood.
“We haven’t stopped to wait for guidance,” said Wood. “We continue to work on transactions. We’re seeing an incredible flow of opportunity to deploy capital. And we’re very excited about the prospects of the IRA bringing down the cost of capital for our clients and for the industry, thereby allowing for more deployment to bring in domestic manufacturing.”
General Electric (NYSE:GE) thinks about the transition to a clean grid globally, which means it has to start making decisions about which technologies to ramp up manufacturing now so they can be deployed as needed, said GE Renewable Energy Senior Executive Director Chrissy Borskey.
“There’s got to be some things that, as an industry, we can start thinking about it, and we can start saying, ‘This is what we need today,’ or ‘this is what we need in the next three months,’” said Borskey. “And we’re going to have to prioritize.”
Meta (NASDAQ:META) Head of Renewable Energy Urvi Parekh said the internet giant has been on average making about 2,000 MW worth of renewable power purchase agreements every year recently, but this year could threaten that streak. The industry needs guidance on exactly how the IRA’s incentives will work, and that uncertainty is leading to more expensive PPAs.
“I’ll know it’s working when we start to see clarity in the prices that we’re seeing,” Parekh said.
Supply Chain Issues Must be Overcome
Another challenge that has roiled the industry along with the rest of the economy recently is the supply chain. The new laws require more domestic manufacturing of goods such as solar panels, which are dominated by China now.
The Chinese dominate the manufacturing of polysilicon and wafers, which are key components to manufacturing solar, said Becca Jones-Albertus, director of the Department of Energy’s Solar Energy Technologies Office.
“A supply chain that has a heavy domestic component brings all kinds of other benefits,” said Jones-Albertus. “Economically, it brings resilience to shipping issues, in which we saw seeing a huge cost increase over the last couple of years.”
Onshoring the supply chain also means more jobs and all the economic benefits that come with increased employment, she added.
Ørsted Americas Head of Program Execution Troy Patton said his firm, which is building seven offshore wind projects off the East Coast, buys from the entire market, so as long as supply can meet demand, the Danish firm does not run into supply chain issues.
“As long as there’s economically feasible supply, we’re happy with the security of supply,” Patton said.
However, while the onshore wind industry in the U.S. has developed its own domestic manufacturing and supply chains, the more nascent offshore industry has not, to the point where Ørsted is having to import all the major components for its first projects, he added.
Securing the solar supply chain is going to involve a lot of tough work, said Nextracker Vice President of Government Affairs Kathy Weiss. Her firm found some success in getting “trackers” that help panels follow the sun built domestically, but that involved reaching out to steel manufacturers and assuring them that the demand for the devices would be there for years to come.
China built up its dominance over 20 years, but the U.S. Commerce Department has issued tariffs on that country, in what has become a bipartisan and popular policy.
“For 20 years, China has been publishing a five-year plan that says, ‘We’re going to dominate,’” Weiss said. “And so now we just figured that out, and we’re trying to react to it; I hope the reaction is one that is smooth and not jarring for the industry.”
An executive order from President Biden gave the industry a stay on the tariffs, which will give it a couple years to rearrange supply chains and use IRA funding to build up domestic manufacturing of solar, she added.
“All our companies across the industries have jumped on that and are working 24/7 to try and stand up fast; to get partners that we’ve worked with offshore to bring them the equipment onshore; to get the equipment set up; get the workers trained; to get the steel prepared,” Weiss said. “So that activity is happening at every renewable energy company across the United States.”
Grid Needs to Triple in Size
Fully decarbonizing the electric sector is going to take massive amounts of new resources, with DOE’s latest modeling showing another terawatt each of wind and solar, about 500 GW of other renewable sources and 300 GW of battery storage. Linking it altogether will also require significant amounts of new transmission, said acting Assistant Secretary for Energy Efficiency and Renewable Energy Alejandro Moreno.
“The modeling that we’ve done looks at sort of the base scenarios that we have increasing transmission by three times above current levels,” he added.
Federal support is needed to get that transmission built out, but it is not enough on its own, said Brian George, Google’s (NASDAQ:GOOGL) U.S. federal lead on global energy market development.
“The large buyers who need access to transmission really have an obligation to be engaged in our communities, in our local environments, to talk about the benefits that these projects have,” George said.
Cost allocation is another key area that needs to be tackled, and that will largely involve states coming to an agreement on where the most beneficial pathways for power are and agreeing to share the costs of new transmission, he added.
The industry has been run the same basic way for 100 years, with policies on top of an original framework that needs to be reformed from the ground up, said Breakthrough Energy’s manager of U.S. policy and advocacy, James Hewett.
“So how do we start to kind of pull those bricks down and build the grid that we know that we need?” said Hewett. “And that’s obviously going to be a really difficult challenge.”
The grid is the “most important machine in our society,” and too often transmission expansion is narrowly focused on the needs that one project will address, said Dominion Energy Senior Vice President of Corporate Affairs William Murray. Such a narrow focus means most people will never be interested in that work.
“What we’re doing instead is strengthening the most important machine in our society for decades and decades,” Murray said. “But we’re also enabling the most significant economic transformation since the internet. And that’s kind of cool.”
FERC is not focused on bringing down barriers to new transmission because it is doing the job assigned to it instead: making sure rates are just and reasonable, said its special counsel, Kim Smaczniak.
The commission has three proposals aimed at improving its transmission regulations, including a Notice of Proposed Rulemaking on transmission planning that would require more long-term planning of 20 years based on various scenarios of a future grid. It also has a NOPR on changes to interconnection queues to speed up the process of connecting new generators, after many of the current rules have led to ever ballooning delays for projects.
The third major rule Smaczniak and colleagues at FERC are working on is an update to the commission’s backstop transmission siting authority from the Energy Policy Act of 2005, which was recently clarified in the IIJA to say that the federal agency can overrule a state that rejects a line.
NEW ORLEANS — The likelihood of a sloped demand curve in MISO’s capacity market earned seals of approval from panelists at Gulf Coast Power Association’s 9th Annual MISO/SPP Regional Conference March 8-9.
MISO Independent Market Monitor David Patton said he recommended the grid operator adopt a sloped demand curve for about 20 years, to remedy its “broken” capacity construct.
Patton said he assumes that stakeholders opposed to a sloped curve are acting in their self-interest. He said members sooner or later must accept that they may have to purchase capacity “that keeps the lights on” in a market structured to reflect capacity’s marginal reliability.
MISO is intent on designing and implementing a downward-sloping demand curve by its 2024/25 capacity auctions. It will replace a demand curve that abruptly cuts off excess capacity’s value when reserve margin requirements are satisfied. (See MISO Charts Course on Capacity Auction’s Sloped Demand Curve.)
The grid operator is proposing four sloped demand curves for each of its seasonal auctions based on separate seasonal reliability targets. Its analyses have shown an incremental value for capacity procured beyond the summer reliability target.
“Historically, as an industry, resource adequacy was binary. Either you had it or you didn’t,” said Todd Ramey, MISO’s senior vice president of markets and digital strategy.
Ramey said that the paradigm led to the RTO’s longstanding vertical design.
“When we started, we had a pretty healthy reserve margin for the footprint,” Ramey said. “Here we are 10 years later, and we’ve been wildly successful at bumping down our reserve margin.”
He said the static demand curve has produced capacity pricing that is “inefficiently low” to spur new generation development.
Patton said that had MISO used a sloped curve in previous auctions, it would have produced prices in the $100-$150/MW-day range.
“It’s going to hit everybody,” Patton said of reliability issues, especially during winter storms.
“We can’t maintain reliability without a capacity market that functions,” he said. “We need to realize that keeping the lights on is way more important than spending a little more on capacity.”
Patton also said stakeholders must get comfortable with MISO placing a marginal value by resource type on capacity.
“You get to a point that you have enough wind that building more wind isn’t going to have reliability value,” he said.
Brett Kruse, Calpine’s vice president of market design said he was surprised that MISO is willing to bend its demand curve after years of opposition. He said he considered it inevitable.
Kruse said a demand curve sending “investment signals” is meant to keep existing baseload generation online. He said new merchant thermal generation is unlikely to be built without developers first securing 20- to 30-year power contracts.
Peregrine Consultants President Charles Griffey said MISO doesn’t need a three-year forward market if it can develop incentives within its one-year spot market.
“The problem is do we really have that incentive in these areas?” he asked rhetorically.
Griffey said demand curved shapes will likely be a “political decision” involving a subjective reliability target, while factoring in carbon-reduction goals.
Patton agreed that forward capacity markets are a “terrible, terrible” idea, saying they interfere with investment, fuel procurement and generator-retirement decisions.
Lisa Duffey, Cleco’s director of strategic market and fuel operation, said she wasn’t sure MISO and SPP were doing enough to make sure that capacity is deliverable to load. She said MISO’s planning doesn’t ever seem to help localized transmission constraints.
“Are we fixing the real problem?” she asked.
Patton said MISO should design its local resource zones to reflect actual load pockets. He said Zone 9, which combines East Texas and Louisiana, is the worst offender for not recognizing natural electrical boundaries.
ERCOT quietly dropped a spring resource adequacy assessment last week that indicated it expects nearly 100 GW of seasonally rated capacity to be available to meet demand.
The Texas grid operator projects demand will peak at 59.5 GW in April and 69.9 GW in May, according to its latest seasonal assessment of resource adequacy (SARA). That assumes the footprint will experience “typical” spring grid conditions, based on average weather conditions during the 2007-2021 spring peaks.
ERCOT announces its spring resource adequacy report. | ERCOT via Twitter
The total capacity includes 63.4 GW of thermal generation, 15.8 GW of wind resources and 10.7 GW of solar resources. It also assumes 844 MW of battery storage capability will be available for dispatch before the highest spring net load hours. Staff calculate net load as total load minus wind and solar generation to represent the demand that must be met with other available resources.
The report includes typical thermal outages of 19.5 GW during the March-April maintenance window and 16 GW during May’s forecasted spring peak. ERCOT based the outage assumptions on historical data for the previous three spring seasons; staff excluded 2021, when February winter storm outages extended into the spring.
The load forecast incorporates expected increases during the peak demand hour from interconnected cryptomining facilities and other large loads. Staff evaluated two risk scenarios: based and moderate, and extreme risk.
ERCOT’s only public notification of the SARA was a tweet Wednesday. It previously issued the report in press releases; follow-up conference calls were discontinued after the deadly 2021 winter storm.
ISO-NE procured 31,370 MW in this year’s capacity auction, the grid operator said Friday in a press release.
Forward Capacity Auction 17, which was procuring capacity for the region for 2026 and 2027, took place on March 6. The preliminary clearing price was $2.59/kW-month in all of ISO-NE’s zones and import interfaces except for the New Brunswick interface, which cleared at $2.551.
That’s largely in line with the prices cleared in last year’s auction, which ranged from $2.531 to $2.639, but ISO-NE noted that this year’s price “was among the lowest in the auction’s history.” The lowest price in the history of the auction was FCA 14 in 2020, at $2.001.
About 750 MW of new renewables, storage and demand response secured capacity obligations this year, 519 MW of which were solar and/or storage and 130 MW were DR.
More than 5,000 MW of renewables, storage and demand cleared in total, accounting for about 16% of total capacity, ISO-NE said.
“This year’s auction secured the lineup of resources — including clean electricity generation, energy storage and resources that reduce demand — needed to meet the region’s power system reliability requirements, at a low price,” Peter Brandien, ISO-NE’s vice president of System Operations and Market Administration, said in a statement. “The results represent clear benefits to New England’s residents and businesses in the form of cost-effective resource adequacy and support for the clean energy transition.”
The auction awarded capacity obligations to 567 MW of imports from New York, Quebec and New Brunswick.
ISO-NE said finalized auction results, including details on specific resources, will be filed with FERC and announced publicly soon.
NEW ORLEANS — Panelists at the Gulf Coast Power Association’s 9th Annual MISO/SPP Regional Conference March 8-9, which attracted a sellout crowd of 230 attendees, made links between long interconnection queue wait times, major transmission expansion, reliability worries, and the inexorable integration of renewable energy.
Terry Chambers, director of the Energy Efficiency and Sustainable Energy Center at the University of Louisiana at Lafayette, said there isn’t a route to achieving the state’s climate goals unless grid operators can bring generation projects online in a timely fashion.
He said MISO and SPP should share more information sooner and publicly so developers can make an informed decision on whether to enter their projects into the queue. He said MISO might recruit more staff to assist with processing and studying the queue.
Kelly Pearce, AEP’s managing director of integrated resource planning, agreed that “four- to five-year delays and the uncertainty” they breed for developers is frustrating.
Recurrent Energy’s managing director Robert Moore said he realized he and a colleague had spoken about the same issue in 2019. He said the dinner discussion then was largely the same as now, other than the fact they dined on grilled oysters instead of barbecue.
Moore said when he tells farmers and county officials they’ll have to wait five years to have certainty on revenue through solar projects “[they] look at me like I’m a moron.”
“I’ve been married long enough [to know] that you want to manage expectations,” Moore joked.
Advanced Power Alliance’s senior vice president of markets and infrastructure, Steve Gaw, said developers need new transmission capacity quickly. He said MISO’s long-range transmission planning (LRTP) is a “huge, huge advance” in incorporating more renewable energy.
“Certainty is the issue that most developers face. We need to get this transmission built earlier, and we need more certainty,” Gaw said. He added that developers enter queues without a firm estimate of their interconnection costs or how many restudies their projects will be subjected to.
Gaw said MISO’s and SPP’s efforts to reduce wait times has largely raised the developers’ financial risk by requiring more capital upfront.
“It just becomes a question of how long can you afford it and how long can your company afford it to know that your project is viable,” he said.
LRTP to Aid Transition
Increasing renewable energy is the thrust behind MISO’s ongoing LRTP effort.
“On July 25, 2022, we shook up the world,” MISO Vice President of System Planning Aubrey Johnson said, referencing the MISO Board of Directors’ approval of the first LRTP portfolio, valued at $10 billion. MISO has now embarked on a second portfolio again aimed at its midwest region. (See MISO Says 2nd LRTP Portfolio Still in Flux.)
Johnson said parties might have doubted the RTO’s ability to bring forward another comprehensive, forward-looking transmission portfolio after its 2011 slate of multi-value projects.
He said MISO envisions requiring about 330 GW of renewable energy over the next 20 years to meet goals set by states and members. That will require dramatic transmission expansion, he said.
“And I have a lot of people sitting on their hands. They take long breaks and take a lot of vacations,” Johnson joked of his overtaxed planning team.
Johnson said MISO needs to keep focus on “regulatory support” needs for long-range transmission expansion. He said MISO is counting on its incumbent developers to convey to state regulators how crucial LRTP projects are.
David Kelley, SPP’s vice president of engineering, said SPP is seeking to “innovate and completely transform” its transmission planning by using a consolidated process. He said SPP must devise “a fair and equitable manner” to divide the costs of an optimized grid. He added that SPP is being “very deliberate” about planning for more common extreme weather.
“We have to continue to learn from each other,” Kelley said.
Jim Dauphinais, an energy consultant representing multiple MISO end-use customers, said his clients are disappointed that MISO has already devised and is now coming up with a new cost allocation for LRTP projects. (See MISO to Test Long-range Tx Allocation Benefits.)
He said MISO had a durable and comprehensive cost-sharing method in its existing market efficiency project allocation and relies on adjusted production cost savings, avoided reliability projects, and savings when a project can reduce dependency on the transmission constraint between its Midwest and South regions.
“Somehow, that got tossed aside … That’s highly problematic,” he said. “There are tens of billions of dollars being talked about in transmission investment.”
Dauphinais called for a refocus on LRTP cost allocation and “a lot of care” in selecting which projects are needed now. He said cost-allocation challenges are behind MISO’s delay to plan LRTP projects in the south until it completes two planning rounds for MISO Midwest.
“Quite frankly, I believe, the cost-allocation issue is a sensitive issue for the MISO South commissions,” he said.
The Regulatory View
In a panel focusing on the regulators’ perspective of recent events, Kansas Corporation Commissioner Andrew French said the industry is realizing that one grid operator’s reliability risk affects another grid operator’s reliability status.
Michigan Public Service Commission Chairman Dan Scripps said MISO’s 2022/23 capacity auction, which resulted in a Midwestern shortfall, was “a wake-up call for MISO and the country.” He said the RTO’s LRTP portfolio represents “a best-in-class” transmission planning exercise to facilitate the generation fleet’s evolution.
But Scripps said it’s currently taking too long to bring generation online through MISO’s queue process. He questioned whether the first LRTP planned projects are sufficient to meet the fleet evolution, “the ground literally moving under our feet.”
Scripps said he thought the second LRTP portfolio’s preliminary possibilities is a good start. He said the first two portfolios that focus on MISO Midwest should be relatively uneventful compared to the third and fourth packages in which planners will analyze MISO South’s transmission needs.
“I think it’s really interesting in terms of tranches three and four,” he said, saying the fourth portfolio is where MISO will get to the “holy land” of better connecting its Midwest and South regions. Scripps said MISO’s current postage-stamp allocation applying to Midwestern LRTP projects probably won’t pass muster in MISO South.
“That approach is one that, let’s say, hasn’t been fully embraced by people in [MISO] South,” he said.
But Scripps said a “free flow of electrons and benefits” between subregions is necessary for a unified MISO system.
“The current bifurcation of the MISO footprint does no favors, I think, on either side,” he said.
Louisiana Public Service Commissioner Davante Lewis, noting he was only 69 days into the job after upsetting incumbent Lambert Boissiere III in a December runoff, said his priorities include helping renewables gain quicker access to the grid, customer affordability and grid hardening. (See Lewis Upsets Boissiere for Seat on La. PSC.)
“I know we talk about how the contractors and developers can’t wait. People can’t wait,” Lewis said of more affordable energy.
Lewis warned that there’s an inflection point at which customer disconnections due to nonpayment will begin to accumulate.
MISO Counsel Calls for Collaboration
MISO Senior Vice President and General Counsel Andre Porter said the GCPA audience has “no other choice [but] to be a high-performing team” in managing the evolving grid. He said the alternative is to be territorial, insular companies, “dysfunctional” and “engaging in disputes [and] spending too much time solving to the last decimal place.”
Porter advised his listeners to collaborate, communicate openly and “check in with each other.”
“There are millions of people, companies outside this room relying on us,” Porter said. He said MISO has long believed there are “unsafe consequences of an uncoordinated transition.”
Porter said he is concerned over accredited capacity exiting the footprint and being replaced by even more gigawatts “coming online, but not providing that same level of high confidence.”
He said MISO’s staff vacancy rate is receding to normal levels, and he said the RTO is hiring the next generation that stands ready to tackle reliability challenges.
“There is a tremendous change and a revolution going on,” Gaw said, also stressing the need for parties to work together.
ACES Power Senior Vice President Jason Painter said that for the first time in his career, he’s witnessing reliability concerns take precedence over price considerations.
WASHINGTON — While they recognize that changes to permitting laws are needed to fully realize the benefits of the Inflation Reduction Act, Democratic officials told the American Council on Renewable Energy on Thursday that a package emerging from House Republicans is a poor start.
Successful bipartisan permitting legislation is more likely to come out of the Senate, said John Podesta, a senior adviser to President Biden on clean energy innovation and implementation.
The House of Representatives is “going to produce some legislation, and they’ll pass it,” Podesta said at the ACORE Policy Forum. “My guess is they won’t consult with Democrats very much. They’ll sort of put together what’s their wish list of assets.”
The White House could work with House Republicans if they come up with sensible proposals that “respect science” and do not “undermine core environmental laws,” Podesta said. But several senators are interested in working on serious permitting legislation, including Sen. Joe Manchin (D-W.Va.), who tried to get a bill through last Congress, and his fellow West Virginian across the aisle, Sen. Shelley Moore Capito, Podesta said.
The attention that permitting is getting from senior officials will help move things along in a process that is performed in the agencies with little attention from the heights of government, Podesta said.
“There’s nothing like accountability: having people at the top know that they’re responsible for working through and breaking through unacceptable delays,” he added.
Biden has also directed his cabinet to make sure that they are using their existing powers, which include some backstop siting authorities for the Department of Energy and FERC from the Energy Policy Act of 2005, Podesta said.
Both Podesta and Sen. Martin Heinrich (D-N.M.) have worked for years to try to get Pattern Energy’s SunZia transmission project built, which would bring up to 4,500 MW of wind power from New Mexico to markets in Arizona and Southern California. Podesta recalled working on it in the Obama administration in 2015 and thinking the line would move forward, only to find out that Pattern had not started construction when he started working for Biden.
The line recently received a final environmental impact statement from the Bureau of Land Management, and a final decision on its route over federal lands is expected this spring, said Heinrich.
“As we build out more transmission lines like this one and overhaul our existing transmission infrastructure, we can bring many, many more large-scale clean energy and storage projects onto the grid,” Heinrich said, “but only if we move much more quickly than we have in the past. It has taken more than a decade and a half for a series of developers to navigate the complex siting and permitting processes for just this transmission line.”
Eliminating carbon emissions from the power sector will require doubling, or even tripling, the capacity of the grid, and while Congress passed legislation last session that includes significant funding for transmission, more change is needed, Heinrich said.
“We all know we have to go a lot further,” Heinrich said. “And that means addressing the underlying problem: that financing timelines and the time it takes to get these major infrastructure projects through complex permitting processes simply don’t match up.”
Heinrich plans on introducing bills intended to improve the transmission planning process and would require that the multiple benefits of transmission be considered in cost allocation. He also plans to introduce a tax credit for transmission, which ACORE has found would spur $15 billion in private investments.
On changes to permitting, Heinrich said he was preparing legislation that would give FERC and DOE conditional authorities to expedite siting processes for high-voltage transmission through a collaborative process that involves states, tribes and other federal agencies.
Besides federal changes, Heinrich urged any firms interested in developing major transmission lines to meet early and often with the impacted communities so they can develop alternatives and avoid conflict as much as possible.
“I would encourage developers to look at issues like environmental mitigation and working with tribes as opportunities for positive engagement rather than just confrontational obstacles,” Heinrich said.
Changing permitting laws has a path to get through Congress this session, with Heinrich saying it is one of the few areas where the two parties have some overlapping goals. But he would rather see something like what Manchin proposed last Congress than what House Republicans have floated so far.
“There’s definitely a potential path,” Heinrich said. “And I think the question is, can the House become a bit more pragmatic? It is driven by its right flank right now; it is making a lot of statements; [but] at the end of the day … [you] come to Congress hopefully to get things done, not just make statements. And that’s the pivot that we need.”
Texas lawmakers Thursday laid out a legislative package that threatens the state’s renewable industry and provides generous incentives to dispatchable generation.
Sen. Charles Schwertner (R), chair of the Business and Commerce Committee, listed seven bills and three more by Vice Chair Phil King (R) that he said would address the operational flexibility and resource adequacy “needed to power Texas into the future.” That parroted language used by ERCOT CEO Pablo Vegas during the grid operator’s most recent board meeting. (See related story, ERCOT’s Vegas Makes His Case for PCM.)
The bills would create a reserve market of 10 GW of gas-fired generation; require that, effective next year, 50% of capacity installed in the state be dispatchable; institute a firming requirement for all resources and load-serving entities; and mandate that generation be built closer to load to reduce transmission costs.
Asked whether the legislation can be interpreted as saying that lawmakers want to focus more on dispatchable energy rather than renewable energy, Schwertner, flanked by signs that read “Powering Texas Forward,” said, “That’s absolutely correct.
“I think it is important that we state the facts,” Schwertner said. “Certainly, renewable penetration is significant, and when it gets too high, because of the variability and lack of performance at critical times … we need that dispatchable generation to balance out and assure that we have a grid that’s performing in times of critical need.
“We’ve got companies that are wanting to invest here. We have to have generation that performs when it’s critically necessary, and that’s dispatchable generation that can be counted on when the wind is not blowing and the sun is not shining. It’s absolutely critical that we level the playing field and balance out that market,” he added.
Advanced Power Alliance CEO Jeff Clark said many of the bills would “dramatically” raise consumer costs, distort the free market and “stifle” advancements in innovative technologies that would provide “a more affordable, reliable and resilient electric grid.”
“Serious policy proposals have been put forth by stakeholders since Winter Storm Uri, and this suite of anti-renewable bills spits in the face of the many productive conversations that have taken place regarding how best to solve the issues we face in Texas,” Clark said. “Grid reliability events are caused by a variety of factors, and the Texas Legislature should be laser-focused on addressing those issues, not searching for ways to tax cheap energy and increase profits of existing generators. The Texas Senate is playing a high-stakes game of politics, with no attention paid to who will lose in the end: Texas consumers.”
The legislation is a response to the deadly February 2021 winter storm, also known as “Uri,” that almost brought the Texas grid to its knees, killed hundreds of residents and inflicted billions in economic damage. A joint FERC–NERC inquiry into the storm found natural gas facilities accounted for more than 50% of unplanned outages, de-rates and failures to start during the storm. (See FERC, NERC Release Final Texas Storm Report.)
The gas fleets in ERCOT and other RTOs and ISOs suffered similar problems during the winter storm in December last year.
Texas Lt. Gov. Dan Patrick (center), standing with state senators, explains the need for more thermal generation in the ERCOT market. | The Texas Senate
Lt. Gov. Dan Patrick, who leads the Senate, called the proposals a “bold agenda” that will “fix the Texas power grid once and for all.”
“I have been abundantly clear that we need to bring new dispatchable (primarily new natural gas plants) generation online as soon as possible to make sure that Texans have reliable power under any circumstance,” Patrick said in a statement.
He has included two of the bills, SB6 and SB7, as two of his top 10 priorities for the current legislative session that ends May 29. Schwertner drafted both bills.
SB6 would establish an “energy insurance program” by offering state-backed loans as low as 1% to build 10 GW of natural gas generation, similar to a program that the state uses for water projects. The units in the program would operate under a last-on, first-off construct. The program’s transmission and distribution costs would be allocated to retail customers in ERCOT.
“This is not building a capacity market; it is an insurance product,” Schwertner said. “The energy-only market has been very successful here in Texas at keeping costs down. But it is again important to have a backup system so that Texans can be reassured that we have the power necessary in times of crisis.”
SB7 would create a new day-ahead ancillary service product, a dispatchable reliability reserve service with two-hour ramps and four-hour runtimes, targeted at dispatchable resources. The bill would also address “market distortions” caused by federal tax credits for “less reliable generation,” Schwertner said.
“Reliability comes at a cost, and for too long that cost has not been shared equally between intermittent and firm generation,” he said.
The bill would also institute a firming or reliability requirement “in a nondiscriminatory manner” on a cost-causation basis. Procurement costs for ancillary and reliability services would be allocated to both dispatchable and non-dispatchable resources and LSEs “in proportion to their contribution to net load variability over the highest 100 hours of net load in the preceding year.”
SB2015, authored by King, would require the Public Utility Commission to monitor each generation company, municipal utility or cooperative operating in the state and to ensure they meet the legislature’s intent that 50% of capacity installed in Texas after 2023 is dispatchable.
The bill would also direct the PUC to establish a dispatchable generation (e.g., natural gas) energy credits trading program. Power providers that are short of the 50% requirement would be required to purchase enough credits to satisfy the requirement.
A second King bill, SB1287, would set a cap on the cost Texans pay when new generation is interconnected to the grid, the idea being to site them closer to existing transmission.
“Everything above, that is going to be paid for by the company that’s building that power facility,” King said. “That will be a tremendous incentive to better site those instead of going out and looking for the cheapest land, which often ends up in a very remote area.”
Other bills include:
SB2010, which would require ERCOT’s Independent Market Monitor to immediately report any potential market manipulation or rule violations to the PUC;
SB2011, which would update voluntary mitigation plan requirements to protect ERCOT’s wholesale market against market power abuse;
SB2012, which would add guardrails to the PUC’s proposed performance credit mechanism to ensure any rate increases are “manageable and go directly toward improving reliability through dispatchable generation”;
SB2013, intended to protect the grid against sabotage and hostile foreign powers; and
SB2014, which would eliminate a state subsidy paid by state consumers to renewable generation.
The bills were filed by Friday’s deadline. Any legislation will have to be coordinated with the House State Affairs Committee, chaired by Rep. Todd Hunter (R), who has positioned himself as a protector of consumer costs since the 2021 storm.
PJM’s real-time load-weighted average LMP for 2022 was a record-high $80.14/MWh, more than double that of 2021, the RTO’s Independent Market Monitor reported Thursday.
The 101.4% increase was itself a record, beating 2021’s 82.8% increase from 2020, during which prices were at their lowest amid the COVID-19 pandemic. (See PJM Monitor: Prices, Coal Power Bounced Back in 2021.)
The previous high was in 2008, which saw an average LMP of $71.13/MWh. Monitoring Analytics’ annual State of the Market report attributed nearly two-thirds of the increase to rising fuel costs, particularly for coal and natural gas, the prices for which doubled in the eastern part of the RTO’s footprint.
Real-time hourly average load only increased by 1.5%. While there was an increase in data center load, this was offset by increased use of behind-the-meter solar, according to the report.
The rise in fuel prices was from an increase in global demand for both coal and gas, Monitor Joe Bowring said during a press conference Thursday.
“The cost of coal was up very dramatically,” he said, citing the closures of coal mines in the U.S. Meanwhile, the U.S. exported more LNG last year, he said.
Nevertheless, the Monitor found the results were indicative of a competitive market.
“Market performance was evaluated as competitive because market results in the energy market reflect the outcome of a competitive market, as PJM prices are set, on average, by marginal units operating at, or close to, their marginal costs in both day-ahead and real-time energy markets, although high markups for some marginal units did affect prices,” the Monitor said.
But as he has in the past, Bowring noted that “during extreme weather” — such as the December winter storm, also known as “Elliott” — “there is market power being exercised on the gas side. And that’s outside our direct bailiwick, but nonetheless, we believe that’s something [FERC] needs to pay attention to.”
Bowring also criticized components of how PJM forms LMPs. “Largely because of Elliott … we see emergency demand response contributed 4.3% [of the increase over 2021]. … We don’t think that’s the way it should work.” The transmission constraint penalty factor’s contribution of 3.2% is “a result of PJM de-rating transmission lines in a way that it shouldn’t do.” And 12% was market power-related, which “obviously we don’t think that should occur,” Bowring said.
Capacity Performance a ‘Failed Experiment’
The Monitor found the performance of PJM’s capacity market to be overall competitive in 2022, but Bowring noted that the analysis did not include the latest Base Residual Auction, the results for which were released in February after a delay. (See PJM Capacity Prices Jump in 5 Regions.)
Still, Bowring said that generators’ performance during Elliott indicated that the Capacity Performance construct — a response to an extreme cold weather event in 2013/14 — has not worked as intended. PJM has said that generators may face penalties totaling between $1 billion and $2 billion for as much as 46,000 MW in capacity being offline during the late December storm, including more than one-third of gas resources.
“The CP design is a failed experiment,” the report says. “The fundamental mistake of the CP design was to attempt to recreate energy market incentives in the capacity market. The CP model was an explicit attempt to bring energy market shortage pricing into the capacity market design.”
“Given that the market seller offer cap has already been removed by FERC,” Bowring said, “the remainder of the fundamental element of the [CP] design should be removed. The whole notion of PAIs [performance assessment intervals] and having these extreme penalties … putting resources at risk, creating this huge administrative nightmare for PJM, including subjective elements of when PAIs occur … it’s simply not a rational way to run a market.”
The Monitor also highlighted its concern with the amount of capacity at risk of retirement by 2030: about 51.8 GW. For comparison, it noted that about 47.5 GW retired between 2011 and 2022.
Of the amount the IMM says is at risk, about 23.5 GW is for regulatory reasons. The plants are primarily coal, Bowring said, and the regulations are primarily from EPA.
PJM and the agency have been working together to “try and ensure that all the resources don’t shut down instantly; that resources are given the opportunity to fix their problems, particularly with wastewater treatment, and some have done that,” he said. “Some are not going to do it. So the EPA and PJM have been trying to make sure that any ultimate retirements are spread over time so that they don’t affect reliability.”
Bowring also said that the Monitor is “very concerned about the increase in” reliability-must-run agreements. Some generators “have interpreted the RMR rule as allowing them to recover costs which have already been sunk. …
“So we’re extremely concerned that this high level of retirements could lead to more RMRs, and we think that the PJM RMR tariff needs substantial revision to ensure that units that are required for reliability are paid and paid appropriately — that is, paid every penny of the costs they incur to provide that service, plus an incentive payment — but not paid more than that; not paid two to three times that, which are the kinds of requests we have seen over the last 10 years.”
