This is a long and thoughtful series of articles about the transition to Renewables. A lot to be learned here.
For the blog
“Increasingly favorable economics, corporate commitments, and state and federal actions, like the enactment of the Inflation Reduction Act, are all spurring the deployment of renewable energy resources.
But the pace of new installations is being hampered by a number of obstacles, including interconnection delays, transmission bottlenecks and supply chain disruptions. Solar installations are also being impacted by an ongoing trade case with China.”
Accelerating renewable energy buildout faces big hurdles, even with Inflation Reduction Act: developers
“It’s really important that everyone understand how contingent that capacity expansion is going to be on state-level decision making,” said Tyler Norris, Cypress Creek Renewables VP of development.
By: Ethan Howland • Published Sept. 6, 2022
National models indicate the Inflation Reduction Act may help the United States cut its greenhouse gas emissions by about 40% by 2030, but renewable energy developers are warning there are a range of challenges that could keep those estimates out of reach.
The hurdles include the “three-headed monster” of clogged interconnection queues, permitting delays and a congested transmission system, according to Devin Hartman, director of energy and environmental policy at the R Street Institute.
Organizations estimating the effects of the IRA on carbon emissions acknowledge those real-world issues.
In a report released Aug. 23, Energy Innovation found the IRA’s climate and clean energy provisions could help cut U.S. greenhouse gas emissions 37% to 43% below 2005 levels by 2030 compared with a 25% reduction under a business-as-usual scenario. The Biden administration aims to cut U.S. carbon emissions by 50% to 52% by the end of this decade.
The energy policy group found that by 2030 there would be 795 GW to 1,053 GW of operating wind and solar in the United States, with “clean electricity” providing 75% of all electricity under a “moderate” scenario.
Last year, about 32,300 MW of wind as well as utility-scale and rooftop solar came online, bringing their total installed U.S. capacity to 226 GW, according to the Energy Information Administration.
Energy Innovation’s moderate scenario envisions the U.S. having 877 GW of wind and solar by the end of this decade. Reaching that amount would require adding 81.4 GW a year on average, roughly 2.5 times the pace of last year.
The group warned its assessment doesn’t account for factors that could limit clean electricity deployment.
“In particular, the modeling assumes that necessary transmission will be built, interconnection delays are addressed, supply chains provide the necessary materials to deploy these levels of clean electricity, and a sufficient workforce can supply the labor,” Energy Innovation analysts said in their report.
Success hinges on states, local governments
In a factor not mentioned in the report, state and local governments will play a major role in how effective the IRA is at spurring clean energy deployment, according to renewable energy developers and advocates.
“It’s really important that everyone understand how contingent that capacity expansion is going to be on state-level decision making,” Tyler Norris, Cypress Creek Renewables vice president of development, said.
In many regions, state utility commissions will have a significant effect on determining the future resource mix through their rulings on utility resource plans and rate cases, according to Norris.
“The success or failure of the Inflation Reduction Act rests at public service commissions because if the utilities are not making good decisions and the commissions are not regulating appropriately, then those states are going to be left behind,” Simon Mahan, Southern Renewable Energy Association executive director, said.
The national models estimating how much carbon emission reductions the IRA may achieve are helpful, but they don’t take into account issues such as county moratoria on solar and wind farms or state processes that devalue solar, according to Mahan.
“Those models are based almost entirely on economics, not on politics or sociological activities that are going on locally,” Mahan said. “It’s just going to be really critical that the folks that have been so engaged at the federal level don’t rest on their laurels and say the job is done.”
In some states, the process of developing long-range utility resource plans will be a focus for groups like the SREA, according to Mahan. IRP processes vary, Mahan said, noting Alabama, for example, lacks a public process, preventing stakeholders from offering suggestions as plans are developed and reviewed.
Aligning state policies with the IRA is a two-part process, according to Pari Kasotia, senior director and head of policy for DSD Renewables, a company that develops commercial and industrial projects as well as community solar.
First, states need to set top-level goals, such as expanding their renewable portfolio standards, she said.
Second, they need to make sure their permitting and generation interconnection processes are timely and efficient, she added.
“A number of states, I’m sure, have already started to think about what that alignment looks like, but I think policymakers and policy advocates will be doing a lot more work in making sure that alignment is there,” Kasotia said.
The IRA, coupled with high natural gas and other costs, is making rooftop solar combined with energy storage less expensive than utility rates across the country, according to John Berger, CEO of Sunnova, a residential solar company.
That will lead to pitched battles at state utility commissions over rules ranging from net metering to allowing customers to shop for power from non-utilities, Berger said.
“Congress certainly didn’t unknowingly set us up for an absolute Big Bang in consumer choice and regulatory discussions with the passage of this bill,” Berger said. “The regulatory framework is going to change and have to change fundamentally on a state-by-state basis. It’s going to be a war.”
Getting onto the grid
The interconnection process is another top challenge in expanding the pace of adding clean energy to the grid.
“There has to be a huge shift in how much renewable energy gets added to the grid every year to meet the goals under the IRA,” Kasotia said. “And in order to do that, that has to be aligned with the state policies and processes on how quickly you can get through an interconnection application.”
There are about 1,400 GW of planned generation and storage capacity in interconnection queues across the U.S., reflecting a surge in solar, energy storage and wind development, according to a report released in April by the Department of Energy’s Lawrence Berkeley National Laboratory.
As the queues have grown larger, it takes longer for transmission providers to complete interconnection studies, which determine if grid upgrades are needed to bring proposed projects online, according to the report. It took 3.7 years on average between a project entering the interconnection queue and coming online in the last decade compared to 2.1 years for projects built between 2000 and 2010. The Federal Energy Regulatory Commission proposed reforming the process earlier this summer.
“What we ask of our grid operators is an enormous task given the acceleration in the number of [renewable energy] projects and the size of the projects,” said Cary Kottler, Pattern Energy senior vice president of North American development. “So making sure that they are able to make their way through these interconnection queues is going to be crucial to meeting our goals.”
Transmission is needed, but hard to build
Even if the interconnection processes are improved, is there enough transmission to deliver power from clean energy facilities to the places where it would be used?
“It’s great to incentivize low-cost renewables — and the demand is there from customers and it’s growing, whether it’s from utilities or big corporations, or small corporations, that are hungry for carbon-free power — the demand is there, but if you don’t build out the grid, you can’t get the power to the load,” Kottler said.
The power sector needs to be “forcefully behind” the transmission build-out to make sure renewable energy can grow fast enough to meet governmental and corporate goals, he said.
The blueprint for reaching 70% and higher renewable penetration levels will be building a growing web of transmission lines that can move electricity from renewable energy sources with different profiles, coupled with energy storage, back and forth regionally, according to Kottler.
However, that plan depends on making sure the transmission gets built, or it will be a struggle to reach emissions-reduction goals, he said.
“Transmission has traditionally been the hardest thing and has the longest time horizon to get done. So that’s the rub,” Kottler said.
Georgia Power is delaying shuttering some coal-fired units because the state’s transmission system can’t handle their exit from the grid or the renewable energy additions that would be needed to replace the power plants, according to Mahan.
“The transmission system, if it is not fixed and expanded on, will restrict the success of renewable development in many states,” Mahan said, noting FERC has proposed reforms aimed at improving the transmission planning process.
“We are so far behind that I don’t think folks understand how far behind we are and where we need to be with regards to robust transmission planning so that we can fully implement what could be done with the Inflation Reduction Act,” Mahan said.
Permitting reform, renewable energy bans
Currently, project permitting and zoning is governed by a patchwork of local and state requirements, and there aren’t federal plans to address the issue for generating projects, according to Norris.
In a related challenge to meeting carbon reduction goals, it typically takes about four years to complete a renewable energy project after it has been procured, Norris noted.
While there is generally a strong awareness of the permitting challenges energy infrastructure developers face, there is less understanding of how long it takes to build interconnection upgrades to connect generating sources to the grid, Norris said.
“What we’re ultimately going to see, especially because we have such a limited window here, at least for the 2030 target, is more build-out occur in the states and jurisdictions that have more streamlined and efficient permitting processes,” Norris said.
Permitting is a challenge, but so too is a rise in bans on renewable energy development, according to Kasotia.
“Certain communities in various states are imposing moratoriums on land-based solar development,” Kasotia said.
Local governments in nearly every state have adopted policies to ban or limit renewable energy projects, according to a March report by Columbia Law School’s Sabin Center for Climate Change Law. The report’s authors found 121 restrictive local policies and 204 contested renewable energy facilities, up 17.5% and 23.6%, respectively, from a report issued six months earlier.
Renewable energy developers acknowledged many of the IRA’s benefits for their industry, such as a 10-year tax credit for emissions-free resources and stand-alone energy storage as well as incentives to develop domestic production of renewable energy equipment.
“We’re certainly delighted that the bill includes provisions for U.S.-based manufacturing,” Kasotia said. “That’s a great first step. The real question is how quickly can we ramp up production in the U.S. so we can make our supply chain more efficient, more local, and have more certainty around that?”
It will take time for that manufacturing base to be developed and it may take years before new transmission lines can be planned and built, which will require a simultaneous focus on near-term steps that can advance the energy transition, according to Kasotia.
“We have to think long term and fix what we can at this point, but make sure that we continue to work towards long-term goals in terms of the infrastructure that we have to support the energy grid,” Kasotia said.Article top image credit: PBouman via Getty Images
California planned to close down its last nuclear plant by 2025 and replace it with clean energy. What went wrong?
Efforts to replace the Diablo Canyon nuclear plant faced multiple challenges, including disruptions to global supply chains.
By: Kavya Balaraman • Published Sept. 9, 2022
Four years ago, California regulators approved a proposal to retire the state’s last operating nuclear facility, the 2.2 GW Diablo Canyon power plant by 2025.
This month, however, lawmakers scrambled during the last hours of the legislative session to pass a bill – Senate Bill 846 – to preserve the option to extend the plant’s life through the end of the decade. This reversal, prompted in part by Gov. Gavin Newsom, D, comes amid broader concerns around ensuring grid reliability in California.
What went wrong? Experts point to multiple challenges they say have affected efforts to replace the Diablo Canyon power plant with clean energy resources, including regulatory delays and disruptions to global supply chains in the wake of the COVID-19 pandemic.
“I think the expectation, that a fairly substantial amount of new resources would come online prior to 2024 and 2025, basically does not look like that’s actually in the cards,” Jan Smutny-Jones, CEO of the Independent Energy Producers Association, said. “That’s not to say that progress is not being made on those resources, but certainly [it’s] not being made at a pace that will allow the state to shut the plant down” on schedule, he added.
The Diablo Canyon nuclear plant came online in 1985 and produces around 18,000 GWh of electricity annually. In 2016, Pacific Gas & Electric, which operates the plant, filed an application to retire its two units in 2024 and 2025, respectively. As part of that application, the utility sketched out a plan to replace the plant’s power with three tranches of clean resources, including 2,000 GWh of energy efficiency, 2,000 GWh of carbon-free energy and a 55% renewables commitment.
However, the California Public Utilities Commission opted not to greenlight that plan and the associated $1.3 billion in funding that PG&E had requested for it. Regulators reasoned that it was not clear whether PG&E could actually procure that magnitude of energy efficiency resources.
Instead, the commission decided to push the broader question of how to replace Diablo Canyon into its integrated resource planning proceeding. Given the time until the plant’s scheduled retirement, the rapidly evolving electricity market in California, and the growth of renewables and community choice aggregators, “it is not clear based on the limited record in this proceeding what level of GHG-free procurement (if any) may be needed to offset the retirement of Diablo Canyon,” they noted in their decision to approve the retirement of the plant.
It would be easier to make that determination as part of the integrated resource planning process, regulators reasoned.
‘Let’s not buy too much too soon’
Some experts, however, remain skeptical of the decision to move the question around replacing Diablo Canyon into the integrated resource planning process. Diablo Canyon wasn’t the only resource that California was planning to retire, V. John White, executive director of the Center for Energy Efficiency and Renewable Technology, noted – the state was also gearing up for the closure of a series of natural gas plants. Regulators, however, seemed to have implicitly concluded that the state did not need to buy replacement resources right away, and that renewables were more expensive, White said.
“Their philosophy was, let’s not buy too much too soon. So they punted everything … into their integrated resource planning proceeding. And that turned out to be a black hole,” that didn’t lead to resource procurement until much later, White said.
The CPUC has since approved an 11.5 GW procurement package of clean energy resources to help replace Diablo Canyon as well as the 3.7 GW of natural gas plants slated to retire in the coming years.
But “because they delayed that procurement, they also delayed transmission and so suddenly even though we’re ready now to buy those resources to replace the retiring fossil [fuels] and nuclear, we’re not able to because we got such a late start,” White added.
The CPUC could have acted more quickly to bring new resources online, agreed Ralph Cavanagh, energy co-director of the Natural Resources Defense Council’s climate and clean energy program. However, he said, the original joint proposal to retire Diablo Canyon – which NRDC was a part of – has not failed in any way.
“It did what it was designed to do – it kept the plant online, it kept the workforce intact, it treated the communities fairly, and it set in motion … the nation’s largest clean energy resource procurement,” he said.
Delays to renewable energy projects
Another factor that has thrown a wrench into the plan to effectively replace Diablo Canyon is delays to clean energy projects. Last month, Karen Douglas, senior energy advisor to the governor, told lawmakers that while regulators expected some 4,000 MW of new resources to come online by this summer, closer to 2,500 MW of that actually materialized. Assuming similar delays to the procurement that the commission has authorized, the state will end up below its electricity reliability targets, she said.
There are two aspects to the supply chain problem that are affecting projects in California, according to White – solar panel supply chains have been disrupted by a Department of Commerce anti-dumping circumvention investigation into cells imported from Cambodia, Malaysia, Thailand and Vietnam, as well as the Uyghur Forced Labor Prevention Act, which went into effect at the end of June.
Supply chain issues are contributing to the challenges in bringing more resources online, Smutny-Jones agreed. In addition, the state is facing hurdles thanks to a large volume of interconnection requests, as well as building out transmission to get electricity to load centers.
“There are a number of factors that kind of fall into place – each one of them in and of themselves is not something which is “the reason,” but collectively, it creates friction in the ability to move rapidly in terms of getting the resources we need in place,” he said.
Having said that, “we’re making steady progress,” in lowering the carbon footprint of the electricity sector, he said.
What happens next?
Newsom signed SB 846, the bill which allows for the nuclear plant’s two units to be extended through October 31, 2029 and October 31, 2030, respectively, into law last week. The legislation also provided PG&E with a $1.4 billion loan to relicense the plant. The utility has filed an application for federal funding through the U.S Department of Energy’s Civil Nuclear Credit program, it said in a Sept. 2 press release.
“We are proud of the role Diablo Canyon plays in providing safe, reliable, low-cost and carbon-free energy to our customers and Californians,” PG&E Corp. CEO Patti Poppe said in a statement.
Stakeholders are split on the potential implications of the extension of Diablo Canyon until the end of the decade. Gene Nelson, legal assistant with Californians for Green Nuclear Power, said that there will absolutely be a need for the nuclear plant even beyond 2030.
“The sun doesn’t always shine and the wind doesn’t always blow – we always have to keep the lights on though. So the idea that somehow or another we can power this state with solar and wind is just a marketing concept, and it’s a marketing concept that sells lots of natural gas,” Nelson said.
CEERT’s White, meanwhile, said the key lesson offered by the Diablo Canyon extension is that “we can’t rely on models to tell us what’s going to happen – we have to keep track of what’s going on in real-time,” when it comes to clean energy development.
The state needs a multi-year, inter-agency implementation strategy, with the governor’s office acting as a coordinator, to deploy clean energy infrastructure, he said. Article top image credit: “Diablo Canyon Family Open House” by Tracey Adams is licensed under CC BY 2.0
‘It’s a good time to be a banker’: RE+ panel reports massive growth in corporate investment in renewables
By: Emma Penrod • Published Sept. 29, 2022
Private investment in renewable energy projects hit an all-time high with over $10 billion devoted to renewable energy in the past year, Supria Ranade, head of power markets for SoftBank Group subsidiary SB Energy, told an audience at the RE+ conference in Anaheim, California last week.
In addition to the overall increase in investment, the renewable energy market is also seeing a greater diversity of investors looking to put money into renewable energy projects and technology, according to Britta von Oesen, partner and managing director at CohnReznick Capital.
“There is a lot of capital chasing this space and lots of funds being raised looking for deployment,” von Oesen said.
Raising capital for renewable energy projects has become significantly easier over the past 12 months — and will likely only accelerate in the wake of the Inflation Reduction Act, financiers at the RE+ conference agreed.
Once largely limited to niche, purpose-driven funds, the number of investors looking to get in on the renewable energy boom has grown rapidly, panelists said. Even types of investors that might be considered more conservative than most, including pension funds, have begun to enter the market in recent months, van Oesen said.
“I had one deal where I think we had every type of investor end up at the finish line with a bid,” she said. “Insurance, independent power producers, domestic utilities, infrastructure, private equity — a pension fund showed up. Really it’s not hard to find the capital these days. It’s hard to find the right capital, and that’s what we spend a lot of time doing.”
As competition between investors has grown, the kinds of projects they’re willing to entertain has also expanded. Individual wind and solar projects have captured most of the private investment to enter renewable energy to date, but the latest wave of capital has shown growing interest in new options such as offshore wind, energy storage and even electric vehicles, according to David Felix, senior director of energy development and strategy at Inspiration Mobility. Private investors have also expressed more interest in projects at earlier stages of development, said Eric Stam, senior director of structured finance at Sol Systems. But most investors have so far stopped short of buying the development platforms themselves, he said.
Volatile supply chains and increasing fuel and energy costs have helped bring renewable energy into the mainstream by putting more pressure both on investors’ and consumers’ balance sheets, Ranade said. Between that and the increasingly apparent impact of climate change, customers and stockholders alike have begun to demand that companies make real efforts toward environmental and social progress, van Oesen said. Where ESG goals were a nice to have — or even mere greenwashing — just two to three years ago, she said, they’re now essential and pushing even greater numbers of private and corporate investors toward renewable energy deals. And the Inflation Reduction Act will likely further increase interest in renewable energy investments, she said, by creating a ten-year period of stability for federal tax credits and policy support.
“I’m not going to lie, it’s a good time to be a banker,” von Oesen said.Article top image credit: Courtesy of Meijer
‘Deploy, deploy, deploy’: Renewable sector energized but anxious about Inflation Reduction Act funding
By: Emma Penrod • Published Sept. 26, 2022
The Inflation Reduction Act is “bigger, bolder and ultimately more transformative” for the U.S. energy sector than almost any other legislation ever enacted, Tom Starrs, vice president of government and public affairs for EDP Renewables, told attendees of the RE+ conference in Anaheim, California last week.
While the clean energy provisions of the Inflation Reduction Act were many years in the making, the law’s creation “wasn’t a direct path, and it wasn’t inevitable,” said Alexander McDonough, a partner at political consulting group Pioneer Public Affairs.
McDonough encouraged attendees at the convention to tout funding from the act when announcing new projects in the years to come as a means of winning over Americans who remain skeptical of the legislation.
Last week’s RE+ conference had a celebratory mood, with many conference goers anticipating an influx of capital as a result of the Inflation Reduction Act. But while similarly exultant, participants on a panel covering the history of the act warned that funding recipients must still prove the bill an economic success.
The landmark piece of legislation, which emerged in an uncertain and even hostile political climate in 2018, passed on party lines, and remains a polarizing act ahead of a series of critical elections, McDonough said.
“Even more fundamentally, this could be a race against time depending on future election outcomes,” Starrs agreed. “We need to figure out how to deploy, deploy, deploy in the next couple of years, because people are looking for tangible evidence that this law made a real difference in their lives.”
Erin Duncan, vice president of Congressional affairs for the Solar Energy Industries Association, also called attention to the 2020 elections in Georgia, which saw two democratic Senators elected by thin margins and split the Senate 50-50, with a Democratic vice president for a tie breaker. That, Duncan said, set the stage for tax credit extensions that had languished for two years to gain momentum.
Passing the bill also required building a huge coalition of stakeholders who brought their own interests to the table and led to the inclusion of provisions such as the domestic content requirement to qualify for tax credits and labor standards and new incentives for emerging technologies like carbon capture and hydrogen, Starrs said. While not exactly what initial proponents of clean energy legislation had in mind — the original goal was of renewable energy advocates to extend existing tax credits for wind and solar — Starrs said he believed these additions will ultimately leave the renewables industry better than they found it.
“The entire rest of the energy sector — coal, natural gas pipelines, all of it is heavily unionized,” Starrs said. “The solar industry and clean energy in general is the last of the holdouts [without prominent unions], in the energy sector. And we kind of got by because we were young and new and expensive, and lots of people wanted to support us. But those arguments only flew as long as we continued to be young and cool and expensive, and as the industry matured, in my view we needed to start stepping up to the plate [with labor protections].”
But the work isn’t done, McDonough said. The next step, he said, is implementing the bill in a way that makes Americans — particularly those who didn’t support the bill — believe the legislation was worthwhile. And that will mean spreading the word as projects that received IRA funds are announced and break ground, he said.
“That’s not just lobbying and campaign contributions,” McDonough said. “It’s about telling the world of [the IRA’s] success — making sure that if a company is building a project that people know about it, that it gets in local news, and that people understand these programs are important.”Article top image credit: lovelyday12 via Getty Images
California legislature aims for 90% clean electricity by 2035 as part of sweeping climate package
By: Kavya Balaraman • Published Sept. 2, 2022
California lawmakers passed a series of climate-related bills this week, including legislation that codifies the state’s goal of achieving carbon neutrality economywide by 2045 and a bill that sets a goal of 90% clean electricity by 2035.
The proposals will add a multibillion-dollar boost to California’s clean energy industry following federal investments from the recently passed Inflation Reduction Act and last year’s Infrastructure Investment and Jobs Act, trade association Advanced Energy Economy noted in a statement.
The California legislature also approved SB 846, legislation that provides funding and authorization for the state to delay the retirement of its last nuclear plant, the 2.2-GW Diablo Canyon facility, by another five years.
Among the bills that passed through the California legislature this week were Assembly Bill 1279, which codified the state’s plan to reach economywide carbon neutrality by 2045, originally outlined by former Gov. Jerry Brown, D, in 2018.
“This is a pretty extreme ask — but it’s an extreme ask to deal with extreme circumstances,” Sen. Bob Hertzberg, D, said during the Wednesday vote.
In addition, lawmakers passed Senate Bill 1020, which puts the state on the path to achieving 90% renewable energy and zero-carbon electricity by the end of 2035 and 95% by the end of 2040 as milestones to an eventual target of 100% by 2045.
Separately, the legislature also passed SB 529 and SB 1174, which, according to American Clean Power’s California chapter, will streamline transmission upgrade approvals and reduce bottlenecks to bring new clean energy resources online.
Clean energy groups hailed the legislative package.
“As California combats dangerous heat waves and the high energy costs that come with them, the need to modernize our electricity system has never been clearer,” Emilie Olson, AEE policy principal, said in a statement.
“This year’s budget deal invests in short- and long-term solutions to California’s energy challenges, like programs that save households money and quickly reduce stress to the power grid on our hottest days…” Olson added.
“We applaud our lawmakers for accelerating our path to 100% clean electricity, protecting communities from pollution from oil drilling, and making a major investment in clean cars, trucks and buses,” Laura Deehan, state director of Environment California, said in a statement.
Meanwhile, the legislature also approved SB 846, a bill reflecting a proposal from the Newsom administration to extend the life of the Diablo Canyon nuclear plant’s two units through the end of the decade. The proposal prompted strong reactions from California stakeholders: While policymakers say the state needs the 2.2-GW facility to ensure grid reliability, ratepayer advocates and other groups have raised concerns about the proposal.
Sen. Bill Dodd, D, told other lawmakers during the early morning vote Thursday that the bill is “an essential tool in the toolbox to prevent widespread rolling blackouts.” California’s current clean energy and storage capacity is not sufficient to backfill the energy production from the Diablo Canyon plant, he said.
“Scrambling to buy costly and dirty out-of-state power isn’t the answer,” Dodd added.
Other lawmakers, however, questioned why the bill was brought to the floor at the last minute.
“I’m befuddled that we have a matter of such importance coming to us at this late hour, at this date,” Sen. Andreas Borgeas, R, said.Article top image credit: DustyPixel via Getty Images
What inflation – and the Inflation Reduction Act – mean for the clean energy sector
While inflation rates could pose challenges for clean energy projects, the passage of the Inflation Reduction Act could more than make up for those impacts, experts say.
By: Kavya Balaraman • Published Aug. 16, 2022
High inflation in the U.S. could make things difficult for the clean energy sector, but the passage of the Inflation Reduction Act could more than make up for those impacts, experts say.
In the U.S., consumer prices in July were up 8.5% compared to the previous year, albeit slightly lower than June’s 9.1% year-over-year increase. Late last week, the House of Representatives passed the Inflation Reduction Act, which authorizes $369 billion in funding for climate change-related and clean energy initiatives. The legislation includes a wide range of incentives and tax credits for clean energy, electric vehicles, nuclear power, and clean hydrogen, among other things, and is projected to decrease U.S. carbon emissions by 40% by the end of the decade.
Clean energy projects that began to get underway as inflation ramped up face two countervailing forces, according to Harry Godfrey, managing director at Advanced Energy Economy: on the one hand, as natural gas gets more expensive, interest in solar and wind, for instance, is likely to increase. But at the same time, the primary way to combat inflation is to raise interest rates, in an attempt to “cool” the economy, which means that the cost of capital for clean energy projects will also rise.
“So while there is, I think, a greater appetite to build these projects because they are deflationary, there is also [the fact that] the cost of the capital I need to raise to then build a multi-million dollar – let alone a multi-billion dollar – project has gone up. So those are the two forces at work there,” he said.
Two countervailing factors
It’s difficult to ascertain the impact that inflation has had on the solar sector, particularly because it’s been an especially weird time for the industry, according to Dan Whitten, vice president of public affairs at the Solar Energy Industries Association. In March, the U.S. Department of Commerce announced an anti-dumping circumvention investigation of solar cells from Cambodia, Malaysia, Thailand and Vietnam, in response to a petition from California solar panel assembler Auxin Solar. A few months later, President Joe Biden implemented a two-year exemption on tariffs for solar panels imported from these countries, which the industry expects will continue in parallel to the investigation.
“There are a lot of outside forces beyond pure economic analysis that have influenced the price of solar over the last year, tied to supply chain, tied to trade policy – and so it’s really hard to evaluate the impacts inflation is having in solar based on those other forces,” he said.
At the same time, renewables do not lend themselves to price volatility, Whitten added – “and so therefore, we don’t think it’s as bad as it has been for other energy sources.”
Clean energy projects tend to be inherently anti-inflationary – if not deflationary – in nature, Godfrey agreed. Conventional resources like coal, oil and natural gas are coupled to the global commodities market, and therefore subject to significant price volatility – but renewable projects, which don’t involve a fuel factor risk, can be viewed as a kind of “shock absorber” in the economy.
“The greater your share of that, the less you’re going to see your energy prices rise as those commodity prices rise,” he noted.
But future renewable projects face a different dynamic, according to Morten Lund, partner with Stoel Rives. Take a solar project for instance – a developer would essentially need to spend nearly 100% of the lifetime cost of the project in building it, he noted. Which means that an inflationary cost of construction, including the cost of financing, will be baked into the power purchase agreement price for a new solar project – essentially locking it in for 20 years.
“So then in five years, when oil prices come back down, those solar PPAs will still be high,” he said.
The two countervailing factors impacting clean energy development could affect projects at the margins, according to AEE’s Godfrey. That being said, wind and solar projects aren’t only built because they are the least cost resources – they are also driven by emissions reduction goals, as well as a need to diversify energy sources.
“So it’s important to note the cost of capital, and how that can impact these projects, but it’s not the sole determinant of project viability,” he said.
‘A mild headwind’
High inflation has also had implications for storage projects, industry advocates agreed, and the sector is facing several sources of increased cost due to inflationary pressures and supply chain constraints, like materials, labor, and the cost of capital to get things financed, said Jin Noh, policy director with the California Energy Storage Alliance.
“My view is that [inflation] is like a mild headwind” against the backdrop of a larger transition from the conventional, fossil fuel fleet to new energy sources, said Alex Morris, CESA’s executive director.
The impacts of inflation on the ground include some projects getting downsized or delayed, or force majeure invocations, he added.
In California, this has led to responsiveness both from the industry as well as the utility or load-serving entity side to keep project deals intact – efforts that signal the industry’s commitment to absorbing a portion of the risk, as well as the power providers’ commitment to moving deals forward and serving load with clean resources, Morris said.
“It hasn’t been perfect, and each load-serving entity negotiates these things and approaches these things differently, so it’s hard to draw a single, standard conclusion – but generally, we are still seeing progress,” he added.
The Inflation Reduction Act
The Inflation Reduction Act, however, could change many of these dynamics.
Take, for instance, the cost of capital. AEE’s first-cut analysis suggests that the provisions in the IRA are going to more than offset the increased, underlying cost of capital driven by inflation, according to Godfrey. The IRA would restore to full value and extend the Investment Tax Credit and Production Tax Credit for clean energy projects, as well as institute a credit for standalone storage. It also includes a variety of adders, like meeting domestic content requirements, and when stacked together, “for the ITC, you can get like a 50% tax break on it for a big project – that’s huge,” he said.
Another meaningful aspect of the legislation is that it will continue many of the tax credits into the 2030s, providing developers with more certainty and a clearer line of sight, said Godfrey.
“I think what’s in the IRA more than counterweights the inflation of this moment,” he added.
In California and the West, there is already a fundamental drive toward more renewables and storage, and the IRA essentially reflects a continued commitment and reduced cost to achieving that, said CESA’s Morris. In addition, the legislation could also lead to changes in how storage is configured and shows up on the grid.
“We’ve seen a lot of storage paired with renewables – we know that that can make a lot of sense, but it’s also linked to the investment tax credit for solar. And now, we may see different configurations of storage, including more independently connected standalone storage not necessarily colocated with solar,” he said.Article top image credit: lovelyday12 via Getty Images
Wind, solar additions slowed in H1 but are expected to jump in next three years: FERC
By: Ethan Howland • Published Aug. 17, 2022
Renewable energy developers added 5,722 MW of wind in the first half this year, down from 7,157 MW in the same period in 2021, while solar additions fell to 3,895 MW from 5,714 MW in the first six months last year, according to the Federal Energy Regulatory Commission.
Looking ahead, there is 66,315 MW of “high probability” solar additions set to come online over the next three years, starting last month, FERC said in its monthly infrastructure report, released Aug. 9. There is 17,383 MW of high probability wind for the same period, according to the agency.
Meanwhile, the Energy Information Administration expects renewable energy, including hydropower, will account for 22% of the electricity produced in the United States this year, up from 17% in 2017. Renewable production will grow to 24% in 2023, the agency said in a forecast released Aug. 16.
The FERC and EIA reports indicate that while renewable energy additions have slowed this year, solar and wind will make up a growing portion of U.S. power production.
The reports don’t reflect any near-term boost the Inflation Reduction Act, signed into law on Aug. 16, will provide to renewable development.
The FERC data shows how the U.S. energy mix is changing. Coal-fired power plants make up 17.7% of all U.S. generating capacity, down from 23.9% five years ago. Nuclear capacity accounts for 8.2% of all capacity, down from 9.1%, and hydro capacity is down to 8% from 8.5% since mid-2017.
Wind farms make up 11.2% of U.S. generating capacity, up from 7.2% five years ago, and solar capacity has grown to 5.9% from 2.3% in that period, according to FERC. Gas-fired capacity has inched up to a 44.2% share from 43.4% in the last five years.
FERC expects some of those trends to continue with about 22,226 MW of coal-fired generation slated to retire in the next three years, starting last month.
On the natural gas front, FERC said there is 21,743 MW of high probability gas-fired generation set to start operating in the next three years, with about 17,400 MW retiring in that period.
Meanwhile, the EIA highlighted a dearth of renewable generation in three regions: the PJM Interconnection, the Southeast and the Florida Reliability Coordinating Council.
“In each of these regions, we expect the renewable share of electricity generation to remain below half of the national average through 2023,” the EIA said. “Natural gas and nuclear sources provide most of the electricity generation in the Southeast and Florida. In PJM, the prevalent generation sources have been natural gas and coal.”
The Southwest Power Pool has had the most growth in the renewable share of electricity generation in the past decade, largely driven by wind generation, the EIA said. Last year, renewables, mainly wind, accounted for 40% of the power production in the SPP footprint, up from 13% in 2013, according to the agency, which expects renewable production to grow to 44% this year.
Renewable energy production in the Electric Reliability Council of Texas increased to a 32% share this year from 10% in 2013, the agency said.Article top image credit: hrui via Getty Images
Why the energy transition broke the U.S. interconnection system
The same processes that created the U.S. power system may now be preventing its transition to clean generation.
By: Emma Penrod • Published Aug. 22, 2022
Boone Staples, director of transmission analysis for the engineering and construction group at energy developer Tenaska, has been doing essentially the same job for the last 15 years. And in spite of his tenure, he says he can’t remember a single solar project that hasn’t run into interconnection delays.
“We have projects in the [Midcontinent Independent System Operator] queue that have been there for four and a half years now. In [the Southwest Power Pool]…we’re looking at eight years start to finish on a project. In PJM we have projects that have been there since March 2019 – these projects were shovel ready. They have offtake contracts completed with full permits ready to start construction, just waiting on PJM,” Staples recounts. “Those have been put on pause. With queue reform it looks like they will get kicked out to late 2025, so that’s pretty severe for us.”
Tenaska, Staples says, is ready and willing to participate in interconnection studies and pay for transmission upgrades. And yet the ever-growing queue times, he says, continue to cost the company projects. Power purchase agreement negotiations have fallen apart, and options on land have even expired, as projects wind their way through the lengthy interconnection process – difficulties that can trigger the cancellation of an entire project.
Data from the Lawrence Berkeley National Laboratory show that interconnection queue times have increased dramatically since 2005, when a typical solar project could be built, start to finish, in two years. Today, the average developer can expect to need four years or more to complete a project, according to Joseph Rand, a senior scientific engineering associate tracking interconnection queues at the Lawrence Berkeley Lab.
But it’s not just that navigating the queue takes longer today than in the past decade, Rand says. Projects are also significantly less likely to succeed. Less than a quarter of the projects that enter interconnection queues around the U.S. will make it through to completion. Between the delays and the need for developers to hedge their bets, the U.S. currently has roughly 700 GW of solar, 400 GW of energy storage, and more than 200 GW of wind energy sitting in overflowing interconnection backlogs – just gigawatts shy of what the Biden administration projects is needed to generate 95% carbon-free energy by 2035.
“Our backlogs are indicating that our wind and solar developers are eager to meet that demand,” Rand says, “but that our transmission and interconnection system and procedures are not keeping pace with meeting that demand.”
So how did we get here? After decades of dominating the energy and technology scenes, the U.S., it seems, got complacent. Instead of upgrading the grid and related bureaucratic systems, industry, regulatory and government leaders took a business as usual posture that assumed the nation’s traditional ad hoc, bottom-up approach to energy development would work for renewables, too.
And it did – partially. But the bottlenecks this process creates, experts say, now threatens the nation’s ability to transition to clean energy with the same speed seen in countries with more cohesive regulatory systems.
One of the fundamental problems contributing to interconnection backlogs around the nation, Rand says, is the lack of transmission. If you could somehow set all the other issues aside – the rapid pace of the energy transition, the inefficient regulatory system, the labor shortages – the U.S. still wouldn’t have enough transmission to connect all the incoming renewable energy to the grid.
Yet it’s not as though the U.S. just stopped building transmission. According to the latest numbers from JPMorgan Chase, U.S. transmission has continued to grow at a steady – albeit slow – pace of roughly 2% per year.
The problem, according to Liza Reed, electric transmission research manager at the Niskanen Center think tank, isn’t so much a lack of transmission in general, but a lack of specific kinds of transmission needed to facilitate renewable energy generation. Renewable generation, she says, requires long-distance, high-capacity transmission. And to understand why the U.S. hasn’t built that, you have to go way back in the history of the electric grid – long before the energy transition glimmered on the horizon.
Because the U.S. was an early adopter of electricity – and therefore of transmission technology – there was no central plan or vision for a national electric grid when the first lines went up. Instead, Reed says, transmission became a local issue, with utilities and grids and interconnections all scaling from the ground up as the system grew.
“The system built out very slowly, but quite expansively. There is electricity all over the United States now,” Reed says. “And it’s largely been a victim of a successful engineering system that works until it doesn’t.”
Even though the scale of the grid grew, regulation of the grid remained – and remains to this day – a primarily local concern. Sure, the Federal Energy Regulatory Commission has some limited authority over transmission, but permitting is still managed at the state level, where each state sets its own rules and priorities.
“I’d describe transmission as a federalism mismatch – the law has not kept up with the regional and national impact that the grid has,” Reed says. “The necessity of sharing power, planning together and having an established set of criteria – none of that has been federalized or standardized, even as the impact of our power systems are seen on a broader scale.”
Now that this system is in place, it’s difficult to go back in and assign oversight of transmission to a federal authority, because the states interpret that as an attempt to seize their authority, Reed says. And to complicate matters, states have generally tasked their public utility commissions with regulating for the least-cost option within a relatively short planning period, such as 10 years.
“Even though transmission is a small percentage of the cost of electricity and the transition toward electrification … it is visually the biggest, so it becomes an avatar for ‘what are we paying for,’” Reed says. “You need a single transmission line for a lot of other projects, but that transmission line has a dollar sign next to it and it’s large.”
That means, Reed says, that it’s much easier for a PUC to approve a new gas plant, which can be constructed near existing transmission, than to approve the construction of a high-capacity transmission line that will unlock a swatch of wind or solar projects, which much be located where the natural resources exist.
Bhaskar Ray, vice president of interconnection and development engineering for energy developer Qcells USA Corp., has observed that this dynamic can manifest in ways that resemble the NIMBY – or “not in my back yard” – phenomenon. But the reality, he says, is much more complicated, with each state looking out for its own interests.
“Whenever you try to build a new line between states, the states start playing politics and saying why should we build a line through Arizona when California gets all the benefits, and vice versa,” Ray says. “That kind of game has got to stop.”
The energy transition began with this groundwork for delays already in place. At first, only a couple renewable projects came online at any given time, so utilities and regional transmission organizations had no trouble keeping pace, recalls Dave Gahl, executive director of the Solar and Storage Industries Institute. But then a handful of projects turned into hundreds, and the influx caught many entities flat-footed, Gahl says.
It wasn’t just that the needed transmission didn’t exist, Gahl says – many transmission authorities failed to allocate an appropriate number of staff to the interconnection process, and existing processes and procedures were woefully inadequate to the task of processing hundreds of requests all at once.
Take the interconnection process itself for example. Regional transmission organizations, generally, do not share enough information publicly for a developer to easily identify the best, most cost effective locations to connect to the grid, Gahl says. So developers have to apply for interconnection with incomplete information – and may learn during the study process that a project will be financially or technically infeasible.
This process has also forced developers, in some cases, to apply for interconnection as a sort of exploratory exercise to identify the best locations to connect to the grid, and therefore to construct projects. But these exploratory efforts take time and resources to study just like any other project – and add to the overwhelming surge of projects waiting for attention from an RTO or utility.
“You want to build the project, but you don’t know where to put it and the only way to get the information is to put in an application,” Gahl says. “Seems to me there is a better process.”
The queue system further exacerbates this dynamic, Staples says, by assigning projects priority status according to when they enter the queue on a first-come, first serve basis. As queue lengths began to expand with growing numbers of projects seeking information on the grid, developers began to submit their interconnection requests earlier and earlier in the development process in an effort to essentially hold their place in line, Staples says. This meant projects began to enter the queue before offtakers or property rights had been secured in some cases – further holding up the process, which in many regions still does not allow a project to jump ahead if the applications ahead of it aren’t prepared to begin the study process.
These early-stage projects, which some have complained are essentially speculative, have drawn numerous complaints and triggered some RTOs to take steps that make it harder to enter and remain in the queue – to the frustration of renewable energy developers.
“Maybe there are some people who carpet bomb the queues with speculative projects, but I think in general they appear to be speculative because people know it’s going to take five years to get through the process, so you have to do that early on,” Staples says. “It would be unwise to fully develop your site prior to entering a queue that you have no certainty on getting through, especially because so many things can change in five years. In a sense, every project is speculative until it can get through the queue process.”
Efforts by some independent system operators to create “clusters” of projects for simultaneous studies have helped make it easier to get through the queue, Staples says. But the clusters have come with their own unique challenges. The large number of projects initially assigned to each cluster means the first series of studies completed tend not to be particularly meaningful or useful, he says. As more projects drop out and the cluster group becomes smaller, the studies become increasingly specific – but after a certain point, each time a project drops out of the cluster, it triggers the need to revisit and revise completed studies. Cost estimates derived from what are supposed to be late-stage studies can still prove highly volatile.
“It’s still taking five years,” Staples says, “but I don’t see how MISO for example would process that many hundreds of requests in a serial fashion, so it seems essential to have a cluster process.”
As complicated as untangling the queue backlog may sound, there is some good news, according to Rob Gramlich, president of Grid Strategies and co-founder of both Americans for a Clean Energy Grid and the WATT Coalition: fixing the interconnection process is currently among FERC’s top priorities.
At the top of the to-do list, Gramlich says, is sorting out a regional transmission planning process so that in the future transmission is built where it’s needed, and not just where it’s the cheapest or easiest. FERC issued a proposed rule on the subject in April.
Also near the top of the list of needs, he says, is restructuring the interconnection process itself.
“The RTOs are faced with massive lists of generators in the queue, and a dysfunctional process where if one project drops out then others need to be restudied,” Gramlich says. “So the amount of restudy and churn in the queue with projects coming in and out is really unmanageable right now.”
The solution to the problem is two-fold, Gramlich says. Transmission managers must make more information publicly available about their systems so that developers don’t need to apply for interconnection just to determine whether a project is viable. Then, RTOs and generators must be bound by reciprocal expectations that make it harder to miss study deadlines and to drop out of the queue without penalty.
FERC initiated a second round of transmission rulemaking in June that takes aim at these issues. The interconnection reform package FERC envisions includes implementing a first-ready, first-served model, penalties for transmission planners who miss study deadlines, and calls for the adoption of new technologies that would speed the interconnection process.
That last piece, Gramlich says, is an oft-forgotten, but important potential solution to interconnection gridlock. Energy storage, for example, could function as a transmission asset, allowing grid operators more flexibility in how they connect renewables to the grid. Other technologies such as power flow control and optimization software could further enhance RTOs’ ability to accommodate more renewable energy on the grid without extensive transmission upgrades.
“Unfortunately it’s going to take some time,” Gramlich says. “There’s not a magic wand here to eliminate the problem immediately. We’re going to have to build our way out of it, and work our way through the queues, sorting the projects and meeting the timelines – and that takes time.”
So in the meanwhile, some developers have considered taking things into their own hands. Qcells, according to Ray, has begun doing internal studies to locate the project sites with the best transmission resources and shortest interconnection queues.
“That is a strategy we are doing and seeing some degree of success, where we are sailing to the finish line,” Ray says. “But not all developers have the in-house technical capabilities to accomplish that amount of study to understand where we have to go.”
Qcells has also entertained the prospect of entering the transmission business itself by building the transmission projects it needs to complete its generation projects, and then selling that transmission capacity to other developers.
“Developers like NextEra have already gotten into building merchant transmission, and third-party transmission is very much welcomed,” Ray says. “If there are FERC incentives to get into the transmission construction business, we’ll consider it.”
Even with industry and regulators working toward solutions, Rand still believes it could take several years to work through interconnection and transmission backlogs and get the energy transition in full swing. But there’s still reason for optimism, he says.
“Can we hit 100% clean energy by 2035? I get less and less optimistic every year and that’s sad,” he says. “But I will say that – this is a back of the envelope calculation – but we estimated that if all the capacity currently in queue today, wind, solar and storage, if we built that by 2030, we would hit 80% clean electricity share. And that’s factoring for load growth… The transition is right at our fingertips, but to realize it we need to reform our interconnection and transmission processes.”Article top image credit: “Foggy South Dakota Morning – Electrical Lines” by Tony Webster is licensed under CC BY-SA 2.0
The fight for a national clean energy transmission system emerges on three fronts
Two federal agencies and transmission advocates are exploring the possibility of a “macrogrid”
By: Herman K. Trabish • Published May 3, 2022
After years of studies showing a national transmission system is the most cost-effective way to meet growing clean energy and carbon reduction mandates, there is still no nation-spanning solution.
New initiatives at the Department of Energy and the Federal Energy Regulatory Commission are refocusing on that goal. A modern “macrogrid” could access the nation’s diverse clean energy from coast to coast to affordably protect against extreme weather, cyber, and demand spike reliability threats, power system analysts told a March 15 Department of Energy (DOE) webinar.
“A national macrogrid system is an important concept and FERC’s outreach to state and regional stakeholders and DOE’s ongoing study can resolve a lot of the doubts about it,” former Federal Energy Regulatory Commission (FERC) Chair said James Hoecker, now Husch Blackwell senior counsel and energy strategist and Hoecker Energy Law and Policy principal told Utility Dive.
The longstanding hesitation on building a nationally interconnected system “shows the lack of political courage to deal with tough issues, and recent power outages in California and Texas show the consequences,” added former FERC Commissioner Nora Mead Brownell, now a venture partner with Clean Energy Ventures. “An independent DOE review can show the economic, social, and environmental benefits are far greater than the costs of inaction.”
The proposed 2023 Biden budget’s over $3 billion for new transmission adds momentum to a DOE National Transmission Planning Study and FERC efforts to answer key questions like who will pay and where to build, transmission analysts said. Joint federal, regional, and local advocacy could be the way to resolve objections to connecting the nation, they acknowledged.
A nation interconnected
Today’s patchwork U.S. transmission system is inadequate to integrate new clean energy resources, stop rising electricity costs and protect against operational, environmental and cyber threats to reliability, system analysts agreed.
Those can be benefits of new links between now disconnected sections of the system, according to the DOE’s National Renewable Energy Laboratory 2020 Seam study. Such links would allow “substantial energy and operating reserve sharing,” and return $2.50 or more in benefits for every dollar invested in transmission, the study found.
Barriers to linking the seams, especially those to fairly allocating costs among beneficiaries, were highlighted in a June 2020 FERC report to Congress.
But if barriers to inter-regional transmission building were overcome, a national transmission system could offer even better solutions than stitching together the seams, Energy Systems Integration Group (ESIG) Associate Director Debra Lew told the DOE webinar.
ESIG’s proposed high voltage direct current (HVDC) backbone “macrogrid” version of a national system “is the electric system’s national interstate highway system,” Lew told Utility Dive. A macrogrid can cost-effectively deliver the new clean energy resources needed to meet the Biden 2035 100% clean electricity goal, she said.
ESIG proposed an approach for a macrogrid design and identified studies needed to assess the macrogrid’s technical and operational reliability and cost-effectiveness in a February paper. ESIG also proposed a “looped circuit” architecture that would maintain reliability on a macrogrid even if a transmission line went out unexpectedly.
But like most previous studies, ESIG did not consider every factor pertaining to regional transmission organizations, independent system operators and other power system stakeholders, Lew acknowledged.
DOE’s National Transmission Planning Study is part of its Building a Better Grid Initiative enabled by 2021’s Infrastructure Investment and Jobs Act (H.R. 3684). DOE’s Pacific Northwest National Laboratory and National Renewable Energy Laboratory will work with power system stakeholders on a comprehensive study for meeting the Biden 2035 goal.
An HVDC macrogrid is only one of DOE’s scenarios, but the paper’s modeling shows “it is the best choice,” Lew said. New advanced technologies like dynamic line ratings and advanced conductors make meeting the challenges of a high renewables penetration system more feasible, other power sector analysts agreed.
Expansion of inter-regional transmission planning and development are valuable steps forward in meeting federal and state clean energy policies, both Tammy Ridout, spokesperson for U.S. transmission development leader American Electric Power, and Matt Lindstrom, spokesperson for the Midwestern transmission developer Xcel Energy, agreed.
But detailed transmission planning that answers all stakeholder questions is still lacking, most observers agreed.
Ways to get there
The federal agencies and transmission advocates now intend to convincingly show how to build a national transmission system.
At least seven comprehensive studies since 2017 from authoritative research institutions like MIT, NREL and Princeton have failed to produce significant new inter-regional transmission, an October 2021 Brattle Group and Grid Strategies study found.
Key study shortcomings included not incorporating actual state clean energy policies, not identifying feasible transmission projects, and not showing granular economic benefits, Brattle found. Studies also often omitted solutions to barriers like cost allocation, siting and permitting, it added.
One is FERC’s April 21, 2022, Notice of Proposed Rulemaking, or NOPR, on transmission planning, cost allocation, and generator interconnection reforms, he said. Its concerns about threats to reliability from emerging renewables, changing loads, and new technologies echo DOE’s concerns.
Other justifications for regional links could come from either federal legislation requiring regional sharing of reliability “for extreme weather events or renewables variability” or a national clean energy standard allowing FERC to order transmission for integrating new renewables, Pfeifenberger said. But neither is currently feasible in today’s Congress, he acknowledged.
Utilities’ past resistance to inter-regional transmission to protect their own generation’s revenues can be overcome, Pfeifenberger said. The opportunity for so much new rate-based capital expenditures would be a “major expansion” of the more than $20 billion now invested annually in transmission and would be an incentive to utilities, he said.
But some see broader obstacles to a national transmission system. Unlike the national interstate highway system, we do not have a “bipartisan national sense of shared purpose on renewables, decarbonization, and transmission,” former FERC and DOE staffer and consultant Alison Silverstein said. “And we have many more spending priorities,” she added.
But federal action can change that, stakeholders agreed.
What DOE can do
DOE’s Transmission Planning Study will compare a macrogrid-like national system scenario and a scenario for closing inter-regional seams with today’s scenario leaving it to each region to meet the Biden 100% clean electricity by 2035 goal, said NREL Senior Analyst and Economist David Hurlbut.
To prevent DOE’s study from ending up on the shelf like others, it must involve the organizations, planners and engineers that build transmission, former Wisconsin utilities commissioner Lauren Azar told the DOE webinar. It could also incorporate 2021 Infrastructure Act-granted leverage to authorize new national interest transmission corridors, Azar added.
“A lot of what happens will be determined by how good the DOE study is and how effective the department is at coordinating its effort with stakeholders,” agreed former DOE and FERC staffer Silverstein.
“This study’s public outreach process will make all costs and benefits of a larger system clear,” NREL’s Hurlbut promised. And it will “add transparency to the process” by presenting interim preliminary results to the public and a technical review committee made up of RTO/ISO and utility planners, state regulators, environmental groups, and others, he added.
The estimated timeline is “about two years” because “we expect to do a lot of new analysis which cannot be done quickly,” Hurlbut said. “Sooner is definitely better because penetrations of variable renewables are growing,” but effort could be wasted if the study is done “faster than the institutional capability of approving transmission,” he said.
New transmission solutions will be needed “before higher renewable penetration begins to cause increased cost and decreased reliability,” Arkansas Public Service Commission Chair Ted Thomas emailed Utility Dive. That means “we better get started fast,”
The biggest opportunity in this study “is finding ways to deliver the most amount of clean energy at the lowest cost with the minimum impacts on the power system and the environment,” Hurlbut said. But the biggest obstacle is demonstrating “the benefits of those solutions in ways that can be used for the next stage of transmission’s evolution,” he added.
Researchers will set aside concerns about opposition from vested power sector interests because “they often change their perceptions of what is in their interests as the process evolves,” he said.
Though it may not be completed before a final FERC rule, the final DOE study will be “a complete response to FERC’s NOPR,” and “will hopefully inform future FERC transmission reforms,” Hurlbut said.
That means important questions on transmission planning will be open for FERC and its stakeholders, analysts and former commissioners said.
What FERC can do
Many of DOE’s concerns about reliability, emerging renewables, changing loads, and new technologies were echoed in an Oct. 12 filing by the National Association of Regulatory Utility Commissioners (NARUC) in FERC’s docket on transmission reforms.
NARUC’s filing followed the formation last June of the FERC-NARUC Tack Force to develop federal-state cooperation on those concerns, according to FERC’s announcement of the task force.
Key among the concerns is a need for better FERC guidance on how to allocate transmission costs based on how the benefits for large-scale inter-regional projects are shared, former FERC Chair Hoecker said. “The different RTO/ISO allocation schemes have become a puzzle with pieces that don’t fit together,” and a FERC ruling could provide “equitable cost allocation principles” to guide future transmission development, he added.
But FERC should maintain “the foundational principle” that transmission costs should be allocated to benefits “solely within the transmission planning region,” NARUC’s filing cautioned. This could keep the puzzle pieces described by Hoecker from fitting together.
RTO/ISOs are “largely caught in the middle between FERC and state-level stakeholders protecting their own local interests,” former FERC commissioner Brownell said. “We need to move away from that kind of cost allocation.”
State regulators and stakeholders may be intimidated by the sheer size of trillion-dollar inter-regional transmission proposals, she said. But “a cost allocation process with clear data on how that may be significantly less than the cost of cyber-attacks and extreme weather could help change their minds,” she added.
New approaches “are beginning to value long-term inter-regional reliability and resilience benefits that far exceed the narrow geography of the current cost allocation calculations,” Silverstein added. A national transmission system offers “national security, environmental, and economic benefits for our children and their children, and FERC can use the NOPR to develop that perspective,” she added.
If the focus of transmission planning was broader, it would show significantly greater benefits and that could lead to transmission-building opportunities, agreed Charles Marshall, vice president of transmission planning for independent FERC-regulated transmission utility ITC Holdings Corp. But that requires a “refocusing of transmission planning policy,” he said.
NARUC endorsed reforms to “better align regional transmission planning with state needs and ensure meaningful opportunities for the states to provide direction and input,” its filing said. FERC should allow the region’s stakeholders “to evaluate transmission system needs,” choose “resources that states want,” and “refrain from establishing overly prescriptive rules.”
By taking on hard issues like cost allocation, the FERC NOPR can make incremental progressive improvements in transmission planning, but that may not lead to a macrogrid, former FERC Chair Hoecker said. The “missing piece” is a vision of how to politically achieve the transmission that is needed and “neither the FERC nor the DOE has articulated that vision yet,” he said.
An urgent issue
The “atmospherics” for a national transmission system are as good as they’ve ever been, Hoecker acknowledged. “But I hope advocates are not blind to the difficulties that still exist in the law and in communications with stakeholders up and down the value chain.”
It is time for Congress and the business community to recognize the need for a national transmission system as “an urgent national issue” and address those difficulties, Brownell said. An “independent accurate analysis of benefits and of the costs of not acting can make that happen, and the current efforts at FERC and DOE can lead the way.”Article top image credit: “Rainbow and Power Lines at the Palo Alto Baylands” by Don DeBold is licensed under CC BY 2.0
Supply-chain squeeze: Solar, storage industries grapple with delays, price spikes as demand continues to grow
Developers are facing price pressures and uncertainties that are making it difficult to complete the projects in their pipeline — or procure new ones, experts say.
By: Kavya Balaraman • Published March 31, 2022
Project developers across the country are seeing the ripple effects of supply chain constraints squeezing both the solar and storage sectors.
Multiple factors are contributing to the problem, experts say, from upstream shortages in labor and equipment parts to more intermediate issues like transportation backlogs and the unavailability of shipping containers. On the storage side, developers have been experiencing tight supply conditions that make it difficult for them to access lithium-ion batteries, as well as other equipment they need to build facilities. The solar sector, meanwhile, has witnessed labor crunches at ports, nautical shipping challenges and other constraints that have contributed to a demand-supply imbalance.
U.S. solar installations were lower than expected in 2021, with gigawatts’ worth of projects pushed into 2022 or later due in part to supply chain and logistics challenges, according to a March report from the Solar Energy Industries Association. About a third of solar capacity scheduled to come online in the fourth quarter of 2021 was delayed by at least one quarter, the report found. Furthermore, developers have postponed at least 8% of the planned capacity for 2022 to 2023 or later and canceled at least 5%, it said.
The project delays and cancellations are not only due to delays in getting products that go into developing a solar project, said Shawn Rumery, SEIA’s senior director of research — they’re also because prices have been going up very quickly at the same time, thanks to those supply chain constraints and inflationary pressures.
“It’s putting a lot of price pressure on developers, and just the general uncertainty there is creating a difficult environment in terms of not only developing projects that you already have in your pipeline, but procuring new projects as well,” he added.
COVID-19 aftereffects, raw material shortages and logistical challenges
The aftereffects of disruptions caused by COVID-19, and the resulting temporary shutdown of manufacturing in various countries, have likely had the most impact on the supply chain, said Adam Walters, a lawyer with Stoel Rives. In 2021, many U.S. renewables projects were pushed back because of delays in equipment supplied primarily from Asia, and some of these delays continue today, albeit at lower levels.
While supply has been constrained, demand has grown, Stoel Rives partner Morten Lund added. The big uptick in demand for solar panels and batteries over the last couple of years “makes it look like the supply problem is bigger than it is because demand is widening,” he said.
“There was just an explosion of demand — a lot of that was led by the electric vehicle market.”
Senior energy storage research analyst, Wood Mackenzie
The U.S. Department of Commerce’s recent announcement that it will go forward with an anti-dumping circumvention investigation of solar cells from four Southeast Asian countries could also disrupt certain solar projects, industry advocates have warned.
On the battery side, the main supply-chain issue is the availability of raw materials, according to Vanessa Witte, senior energy storage research analyst with Wood Mackenzie. Lithium in particular has been in short supply, leading to skyrocketing prices, and the main issue the industry is facing overall at the moment is the supply and demand mismatch, Witte said. Spot prices for battery-grade lithium in China shot up from $11,000 per metric ton early last year to more than $50,000 this February, Morning Brew reported in February.
“There was just an explosion of demand [for lithium] — a lot of that was led by the electric vehicle market,” Witte said. Building the manufacturing and raw-material capacity to meet that demand could take time, she added. A new mine, for instance, takes around five years to set up, while a battery manufacturing plant would require at least two years.
“These things just take time to catch up, and that’s really been the source of the issue,” Witte said.
The storage industry is also facing logistical issues like transportation delays, which could affect when developers receive the products they need and, in turn, their ability to bring projects online in time. While these delays caught developers by surprise in 2021, many are now taking extended timelines into account when planning their projects, she said.
‘It increases project risk’
The repercussions of supply-chain problems largely depend on where individual projects are in their life cycle, experts said. Where projects already have contracts executed, for instance, equipment suppliers are responding to delays by asking for relief from schedule commitments and, in some cases, for contract adjustments. These negotiations play out under the force majeure clause of the project’s contract, Nate Galer, partner with law firm Mayer Brown, explained. A force majeure clause is a fairly typical clause in most contracts that would basically excuse a party to the contract if something unforeseeable and out of their control occurs.
“That’s really sort of the big legal issue that we’re grappling with a lot in those situations, is how are those delays viewed under the applicable contract’s force majeure [clause],” Galer said.
″[P]rices have actually gone up by a meaningful amount, and so many of these developers that have signed PPAs are now completely out of the money in terms of their economics.”
Partner, Morgan Lewis
Potential projects and deals that aren’t yet under contract are trickier to deal with, Galer said.
“You see a lot of discussions at the commercial level about whether the contract price and the schedule that suppliers are bidding incorporate that anticipated delay or [not]. And you’re starting to see a movement, I think, in those negotiations to specifically address supply chain delays in the contract,” he added.
Another issue that solar and storage developers are confronting is that because the industry has seen a declining cost curve for many years, many of them have been bidding for projects based on a forecasted decline in future costs.
“Well, not only is that not happening, it’s actually gone in the reverse — so prices have actually gone up by a meaningful amount, and so many of these developers that have signed [power purchase agreements] are now completely out of the money in terms of their economics,” Morgan Lewis partner Neeraj Arora said.
Developers can also take a financial hit when supply chain constraints delay projects, according to Arora. Most PPAs require developers to make some sort of payment to the utility if they miss the project’s deadline. And delays that push back a facility’s operation date to the following year could shrink the level of the investment tax credit for which the project is eligible.
The biggest issues solar developers are facing due to supply chain constraints have to do with their contract terms, Stoel Rives’ Walters said. Suppliers now have a lot more leverage and are pushing more difficult terms than he has seen in the last several years. Historically, for instance, developers have been able to get by with paying fees of 10% or 20% of the purchase price to cancel an equipment order prior to shipment. Now suppliers are making it much more difficult to terminate orders.
“It increases project risk because there may be much greater penalties if you lose a project or [it] drops out of your pipeline for whatever reason,” Walters said.
The storage sector is also facing supply-chain challenges related to plant equipment, like transformers, Alex Morris, executive director of the California Energy Storage Alliance, said.
Analysts are definitely seeing some battery storage facilities get delayed, Wood Mackenzie’s Witte said, with projects initially scheduled to come online in 2021 getting pushed into 2022 and 2023, in part because of supply-chain issues.
While Witte hasn’t seen a lot of announced storage projects get canceled, “what we’ve been hearing from developers is that they really had to reassess almost every project in their mid-term planning. So in that sense, there are probably a lot of projects that got canceled, or maybe just [put on the back burner]… that were never really announced,” she said.
A flight toward quality developers
Solar and storage developers are addressing these challenges in multiple ways. Storage company Fluence, for instance, has secured additional shipping capacity and ramped up the size of its supply chain and manufacturing team, Carol Couch, the company’s senior vice president and chief supply chain and manufacturing officer, said in an email.
Fluence has also been transitioning to a more regionalized business model over the last couple of years, forging partnerships with manufacturers in North America and Europe as well as the Asia-Pacific region, Couch said.
“We have selected contract manufacturers for our North American and European locations and expect these facilities will alleviate the burden of a single manufacturing location by expanding production and reducing shipping and logistical costs,” she added.
“What we’ve really started to see from the utilities is kind of a flight towards quality developers and in some cases, an increase in the amount of collateral that they’re requiring from the developers.”
Partner, Morgan Lewis
Another near-term approach developers are employing is to push back on suppliers and try to get them to bear certain risks, such that projects are protected by delay liquidated damages if equipment is delivered late, Mayer Brown’s Galer said. Some are also taking a closer look at the exit options they might have if supply-chain issues arise with their chosen supplier, like a contract “termination for convenience” situation, and seeking another supplier so that the overall project schedule isn’t changed too much, he added.
Utilities, meanwhile, are facing their own concerns that although they’ve signed PPAs, those projects may not be completed, Arora said.
“What we’ve really started to see from the utilities is kind of a flight towards quality developers and, in some cases, an increase in the amount of collateral that they’re requiring from the developers,” he said.
Potential longer-term implications
Experts say it’s difficult to estimate how long these supply-chain constraints are expected to last, although most agree that they will continue for the rest of 2022. Renewable energy equipment prices could be a little higher for the next couple of years because of supply and demand issues, but that’s unlikely to be a long-term trend, according to Walters. For battery storage, Wood Mackenzie anticipates that demand will be higher than supply in 2022, a trend that is unlikely to dissipate until 2023.
But even if it’s only a short-term issue, today’s supply chain constraints could have larger implications for the energy sector.
“I do see it causing some problems in the short term for utilities and corporates and others to meet their near-term climate goals, just because projects won’t be coming online as quickly as they’d like to see,” SEIA’s Rumery said.
Over the long term, however, the solar industry is still in a good position to be competitive and continue to provide the products needed to meet those goals, he added.
Another potential consequence, CESA’s Morris said, is that developers may pay closer attention to battery technologies other than lithium-ion that have different supply chains. Developers are “polyamorous” with storage technologies, he added: They view storage as a box that they have to put on a site, and while that box can have different skill sets and capabilities, the decision frequently comes down to the cost.
One challenge they’ll face in this regard, though, is that when states and utilities are looking to build storage at an aggressive pace, developers don’t always have a lot of time to put together their bid. In that event, lithium-ion technologies have enough data, insurance apparatus and financing apparatus available already for developers to put together a bid pretty quickly, Morris said, whereas that might not be the case with newer, less-deployed technologies.
There is still a lot of optimism that storage prices will continue to go down as new technologies emerge, supplies become less tight, and more manufacturing capacity comes online, Witte said.
“So I think we’re going to have a dent in the market for the next three to five years, just because we lost some of those gains, but I think after that, we’re going to continue to build that momentum,” she added.
What can policymakers do?
The Biden administration has already taken some steps that will help alleviate supply chain challenges, according to Couch. The Infrastructure Investment and Jobs Act, for instance, has provisions that will support the manufacturing, deployment, and research and development of energy storage technologies.
“The Build Back Better Act would also support the industry with targeted incentives to spur new domestic supply chains and technologies, like solar, batteries, and advanced materials, while incentivizing clean energy projects that utilize domestic inputs like steel, cement and aluminum,” Couch added.
In February, the Department of Energy released a plan outlining 40 strategies to improve the clean energy supply chain. The agency also plans to provide nearly $3 billion in funding to two programs aimed at expanding domestic production of advanced batteries.
In a press release announcing SEIA’s recent report, CEO and President Abigail Ross Hopper said the U.S. needs to ramp up clean energy production and eliminate its energy dependence on hostile nations in the face of global supply uncertainty.
″[I]f we pass a long-term extension of the solar Investment Tax Credit and invest in U.S. manufacturing, solar installations will increase by 66% over the next decade, and our nation will be safer because of it,” she added.