The latest on Energetic and renewable energy trends.
Solving for Infrastructural Bottlenecks in the US Electric Grid
Project developers are no strangers to the infrastructural bottlenecks and regulatory gridlock that constrain the deployment of new renewable energy projects.
Delays are causing electricity costs to rise and are limiting economic development and job creation expected from the Inflation Reduction Act (IRA). Efforts to address these structural issues have thus far failed in congress.1 The current state of affairs has business leaders, policy experts, and academics raising the alarm: the current approach to permitting and interconnection is broken, presenting barriers to the energy transition, and threatening the progress of corporate decarbonization commitments.2
The source of the bottlenecks
Delivering electricity is a complicated is a business that takes time, investment, and more time. Several factors can delay clean energy project development, but two intersecting factors are top of mind for all stakeholders in the industry; permitting & interconnection queues.
Permitting has two layers: siting and transmission.
After a developer has identified a site that makes sense for solar and has negotiated the relevant arrangement with a landowner (no small feat!), they must secure the relevant permits to actually build the project. This requires approval at the local and federal level, and can take up to 3 years.3 This is particularly challenging when a project requires federal permits, often requiring sign-off from multiple different agencies.4
Projects large enough to require new transmission lines are subject to further scrutiny. Transmission lines refer to the short- and long-distance lines that convey electricity from the site of generation to the site(s) of consumption. Projects can be further delayed if additional electric transmission lines and/or permits are needed.
Overall, between siting, permitting, and construction, new transmission projects can take a decade to complete.5
The Progressive Policy Institute highlighted the discrepancy between electrical transmission line permitting times and fossil fuel pipelines, with electric transmission infrastructure permitting taking an average of 4.3 years, which is 8-months longer than the average fossil fuels pipeline permitting process.6 These numbers exclude the many projects ultimately abandoned and not constructed due to overly burdensome costs and delays which may prompt negotiations to fall apart and options on land to expire.
Projects that check all the relevant regulatory boxes still face hurdles. Lengthy interconnection queues, which can reach 5+ years for utility-scale projects, have been an Achilles heel of the market. Interconnection queues refer to the waiting line in which projects are assessed to determine if the electric grid can handle the additional power load the projects add to the system. It now takes about twice as much time to build a typical solar project than it did in 2005 – from 2 years to 4 years.7
Compounding the issue, much of the existing grid is not designed to handle the varying sources of power that developers are looking to bring on line, putting renewables at a disadvantage. Those concerned that gridlock will inhibit achievement of 2030 clean energy targets are in for a frustratingly pleasant surprise - according to Lawrence Berkeley National Laboratory (LBNL), 70% of the renewable and nuclear capacity needed to meet these goals are currently in the 750GW queue.
With time-intensive processes at the backbone of electricity system, it is critical to plan ahead and build out the infrastructure needed to support generation and distribution.
As the Inflation Reduction Act (IRA) catalyzes increased clean energy investment, project development bottlenecks are well-poised to be exacerbated unless the pace and magnitude of grid infrastructure investment ramps.
With the energy transition afoot, a wave of developments expected following the passage of the IRA, and year-over-year growth in capacity in interconnection queues, it's critical to encourage more proactive transmission efforts, and to seek troubleshooting mechanisms. The domestic approach to transmission planning must shift from reactive to proactive.8
But what about today and right now? Can the bottlenecks be avoided?
There is a glimmer of hope. Permitting for renewable energy generation projects is comparatively short relative to transmission or pipelines, on average taking 2.7 years. Structural challenges are fodder for innovation and sea-change. Developers have the opportunity to focus on a road somewhat easier to travel, which serendipitously can enhance grid resilience and energy security.
Distributed generation (DG) offers an alternative approach: mitigate (or avoid altogether) interconnection and permitting delays by generating power where it is being consumed. By prioritizing smaller distributed generation projects with shorter permitting and interconnection processes, developers may be able to accelerate development and get ahead in the market. Distributed generation also contributes to energy resilience and can insulate energy buyers, whether households or businesses, from disruptions in service or shocks to energy prices. It’s an easy way for consumers to take more control of their energy security – after all, it’s impossible to install an LNG-fired plant on your roof!
So what’s the catch?
Cost is often noted as a primary challenge for distributed generation projects. On a dollar per watt basis, distributed generation projects can be more expensive. This is driven by a lack of basic economies of scale: DG projects tend to be smaller, and supply chain pressures make it difficult to rapidly install systems across disparate sites. One way to mitigate cost pressures is to ensure that a behind-the-meter system is able to export power back to the grid. Alternatively, there are many favorable jurisdictions that offer incentives or programs that allow these projects to easily benefit from the investment in DG.
Where do we go from here? What are the mechanisms to bring the $/w cost of small projects down?
Stakeholders should encourage expanded virtual net metering. Increased virtual net metering can benefit non-proximate energy consumers and production systems by easing the accounting and exchange of clean energy production, and by doing so, improve distributed generation project economics.
Microgrids and other aggregation strategies could be effective approaches, however, if deployed at scale these projects could run into the same permitting and transmission delays as larger projects. We encourage the development community and other stakeholders to keep their eyes and efforts on supporting robust, modernized, and expanded transmission infrastructure to support clean energy deployment, enhance grid reliability, and mitigate power outages.
Have questions on how Energetic Insurance can help increase the bankability of distributed generation projects, contribute to a lower cost of capital, and expand market access?
This article does not constitute and is not intended by Energetic Insurance to constitute financial advice or a solicitation for any insurance business.
Sources: 1. https://news.bloomberglaw.com/environment-and-energy/common-ground-elusive-as-manchin-permitting-bill-awaits-action
2. https://cleanenergygrid.org/new-report-finds-current-transmission-interconnection-process-unworkable-inefficient-raising-energy-costs-customers-stifling-job-creation/
3. https://www.progressivepolicy.org/publication/americas-clean-energy-transition-requires-permitting-reform-policy-recommendations-for-success/#_ftn3
4. https://www.resources.org/common-resources/reforms-to-federal-permitting-can-speed-solar-energy-deployment/
5. https://yaleclimateconnections.org/2022/10/permitting-americas-next-big-climate-conundrum/
6. https://www.progressivepolicy.org/publication/americas-clean-energy-transition-requires-permitting-reform-policy-recommendations-for-success/
7. https://www.utilitydive.com/news/energy-transition-interconnection-reform-ferc-qcells/628822/
8. https://www.utilitydive.com/news/gridlock-in-transmission-queues-spotlights-need-for-ferc-action-on-planning/603128/
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Virtual PPAs, Being Proactive in a Seller’s Market
The virtual power purchase agreement (VPPA) market has changed. Today there is a steep market imbalance; there are “five-to-seven IG offtakers for every one VPPA project.”
How did we get here?
A significant market shift occurred over the past 12-18 months. Unsurprisingly, this is due to the age-old factors of supply and demand.
Demand for renewable energy has grown exponentially in recent years, especially as corporate ESG commitments proliferate.
This demand will further expand as electrification increases. Further, there has been a broader attention and appetite shift to clean energy sources and assets within the current macro-economic and geopolitical environments. This growing demand for renewable energy has prompted scarcity.
Simultaneously, supply has not kept pace with demand.
The pace and volume of project development have been held back. Regulatory challenges have plagued the market for years. Lengthy permitting processes and interconnection queues have resulted in waiting periods that can exceed 36 months. This means that it takes years for projects to go live. Supply chain challenges are pervasive – from market availability and pandemic-related supply contractions, to limits in panels that meet ethical manufacturing requirements, to onshore panel availability and concerns about meeting new domestic content requirements – equipment procurement hurdles abound. Finally, every corner of the market is affected by inflation and the broader macroeconomic environment. Inflationary costs have been added in all components of the value chain from input costs for silicon, to transportation, to labor costs. Taken as a whole, these supply challenges result in challenging project economics as costs rise across the board.
Simply put, limited supply is compounding the impact of unprecedented demand. Today this environment affords developers the luxury of selecting from a variety of investment-grade offtakers, However, this environment is unlikely to persist. Transactions and offtaker identification will not always be this easy.
Preparing for long-term success
A long-term view and intentional strategy can help. As corporates reach pledge targets and market obstacles ease, supply and demand will return to balance. Sophisticated developers today understand this and are engaging in pipeline planning to remain competitive in the future market.
The offtake market for VPPAs is diversifying as it expands
Demand from unrated and sub-investment grade counterparties is increasing. The ability to address this demand requires intentional planning and structuring. Bankability of long-term energy agreements with unrated or sub-investment grade offtakers will require increased collateral and/or security requirements. Corporate procurement teams and sustainability advisors need to be aware of emerging market solutions, and leading developers are being proactive.
Experienced developers see credit emerging as a procurement barrier for a large segment of the market
They are already scoping solutions that will allow them to support the sub-IG market segment, viewing it as a significant component of their future development plans. A few strategies leading developers are pursuing are:
- Proactively building long-term relationships with clients with substantial energy needs who are not viewed as top-tier offtakers in today's environment. Many of these current and prospective clients will increase demand for clean energy and efficiency solutions, especially if they have franchise locations and/or subsidiaries that are often unrated or sub-investment grade.
- Assessing project structures that can ease the transaction process when the need to move downstream arises, for example; parent guarantees, multi-offtaker load subscription to decrease cashflow dependence on any single obligor, increased buyer credit supports, stronger security rights, offtaker reserves
- Assessing external risk mitigant products like credit sleeves and credit insurance products
Overall, developers are planning ahead to increase confidence in offtake from traditionally unbankable counterparties so that they will be well equipped to meet the needs of a notoriously underserved market.
The clean energy ecosystem will benefit from increased project development. Developers need all the help they can get from market participants to ensure viable project economics and offtake. We’re calling on all participants – developers, suppliers, financiers, advisors, and buyers – to collaborate and solve alongside eachother to increase the competitiveness of projects. Are you already contributing to this effort? Tell us how!
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Have questions on how Energetic Insurance can help increase the bankability of projects, contribute to a lower cost of capital, and expand market access? Contact us here.
This article does not constitute and is not intended by Energetic Insurance to constitute financial advice or a solicitation for any insurance business.
Energetic Insurance Helps Redaptive Secure $50 Million Credit Facility from Rabobank
Energetic Insurance has played a key role in helping Redaptive, a San Francisco-based Energy-as-a-Service provider, secure a $50 million credit facility from Rabobank. By providing a unique credit insurance structure, Energetic has enabled Redaptive to finance over 1,000 energy efficiency projects, supporting growing demand from commercial and industrial (C&I) customers to reduce energy consumption.
This partnership allows Redaptive to diversify its credit counterparties and access lower-cost capital, advancing energy efficiency solutions in the market.
Read more about this innovative financing deal here.
What Changes to Expect in the Renewable Energy Industry in 2023
Developers, sponsors, financiers, and industry experts recently gathered in Austin, Texas for the Proximo US Power and Renewables Finance 2022 conference. Market participants were aligned on one overarching topic; change is coming to the renewable energy industry.
Cautious optimism in a time of industry transition
Attendees and speakers alike conveyed long-term optimism, primarily driven by the passing of the Inflation Reduction Act (IRA) and continued commitments by governments and large corporations to transition to renewable energy. Given the previous lack of new incentive legislation, the IRA was heralded for providing more certainty in the 10-year development horizon. Expanded and new incentives will yield continued and magnified investment in project development. Government incentives for renewable energy have attracted new capital to the sector, bringing with it the need for investor education, along with the unique problem of finding a way to efficiently deploy the influx of funds.
Positive tailwinds driving the industry forward were met with short-term questions around the impact of the broader macroeconomic environment, and what the interplay between the two opposing forces may yield. Heard throughout the event was the affirmation that projects set to close in 2022 should remain on track, subject to minor repricing. More emphasis was placed on forecasts around the 2023 funding market. Despite the aforementioned influx of capital into the energy transition, the short-term availability of capital could get tighter. However, the expectation is that market liquidity will still be available in 2023.
There seems to be an expectation that the renewable industry will see multiple operating entities aim to acquire funding via the public equity markets. This shift in funding sources may impact how developers weigh the benefits of retaining ownership of sites themselves, as opposed to building to sell. Interestingly, there is a belief that these deals will be viewed by the broader equity markets as growth investments rather than traditional dividend paying entities. Along with many other financial markets, the IPO market will likely remain dormant through the end of the year. But be on the lookout for deals to come into the public eye early to mid 2023.
How will projects be impacted?
Inflation concerns continue to be top of mind for those worried about the cost of debt and cost of materials. It would be hard to find a developer who did not have their own set of concerns regarding supply chains and the potential impact on existing projects. Fortunately, the resounding consensus was that the worst case was comprised of delays and repricing, not outright cancelation. Most industry experts expect the IRA to fundamentally alter the industry supply chain, but the specifics of how that will occur have yet to be fully fleshed out. The expectation is that domestic manufacturing will increase. However, the timing, scope, and magnitude of domestic manufacturing investments are yet to be determined.
Distributed generation (DG) was a key focal point. Multiple panelists either alluded to, or forecasted outright, an increase in the flexibility of DG structures and a move away from flat power purchase agreement (PPA) prices to a more dynamic way to limit basis risk in these deals.
This prognostication for increased complexity naturally comes with an increase in the level of forecasting and underwriting difficulty. The ratings agencies represented implied comfort with the harnessing of multiple methodologies for risk quantification. There still remains a gap between project developers’ view of risk and the methodologies used to underwrite distributed generation offtake at lending institutions. It is also expected to take time for new investors and sources of capital to become familiar with the renewable energy sector and the inherent risk/return dynamics.
The impacts of credit quality and role of insurance
Investors in the energy transition, new and longstanding, share the desire to mitigate investment risk. Risk drivers and risk mitigants are increasingly a topic of conversation. Developers and investors want to ensure viable project economics, long-term project performance, and reliable offtake demand.
Energetic’s own Jim Bowen took to the stage with others from the insurance industry to discuss the multiple avenues project participants can harness to get deals done more efficiently. Alongside Jim, Jeffrey Abramson, CFA of AXA XL, Jamie Brache of Vantage Risk Companies, Eric Popien of Atlantic Global Risk, Martin Bernstein of LBBW, and Donnie DiCarlo of BPL Global, discussed how insurance should be thought of as a financial product to improve funding terms and distribute risk. They explained why insurance should not be viewed as a mandatory boiler plate product needed to get a deal done, but a way to beneficially spread and share risk.
Panelists emphasized the level of customization involved in each deal and the value clients can gain from a relationship with an insurer. Insurers can get involved earlier in the project lifecycle to help creatively structure deals to make them work for all stakeholders, as opposed to buying and selling vanilla products in the open market.
Have questions on how Energetic Insurance can help improve project economics? Contact us here.
This article does not constitute and is not intended by Energetic Insurance to constitute financial advice or a solicitation for any insurance business.
The Good and Bad News on Renewable Energy & Environmental Tax Credits
Successful financiers and developers are always striving to better understand investment and underwriting risks in the context of long-term political and economic scenarios.
That is precisely what was at the core of the forward-thinking dialogues at the Novogradac 2022 Spring Renewable Energy and Environmental Tax Credits Conference in Denver. The well-attended forum outlined the latest industry trends, emerging technologies, and tax credit equity pricing and financing strategies.
Leading experts weighed in with a mix of bad and good news.
The Bad News:
The market is currently facing significant headwinds. Current law phases down solar Investment Tax Credits (ITCs) and Production Tax Credits (PTCs). In the absence of new legislation, Solar ITCs will drop to 22% by 2023, and the PTC expired at the end of 2021. Unfortunately, the Senate draft of the Reconciliation Bill was stalled by Senator Manchin in December 2021, and its prospects look bleak in this mid-term election year.
Further, the market has been anxiously awaiting the results of a Commerce Department investigation into possible circumvention of duties which could result in more solar tariffs. Jeremy Woodrum, Director of Congressional Affairs, Solar Energy Industries Association (SEIA) is hoping for a statement from Commerce by the end of August. Some of that anxiety was relieved by the Executive Order released after the conference on June 6th suspending new tariffs for the next two years.
Separately, JC Sandberg, Chief Advocacy Officer at American Clean Power (ACP) is advocating for a storage ITC. Storage is critical to a robust and resilient distributed energy system. A storage ITC could catalyze investment in much-needed battery infrastructure. Finally, ACP is also seeking streamlined local and Federal permitting.
The jury remains out on the state of and forecasts for the economy as a whole, and financial markets continue to be volatile. Interest rates are on the rise. Some commentators are predicting a 250-basis point hike over the course of the next year. Credit spreads are widening, and business confidence is wavering.
The Good News:
There is a lot of capital available to finance new projects, and in many ways it’s a seller’s market. Demand and supply are optimistically focused on the long-term. That being said, lenders are reviewing deals on a case-by-case and developer-by-developer basis. For example, some lenders remain cautious with respect to Low- and Moderate-Income (LMI) community solar given the perception of higher credit and subscriber churn risk. Others are wary of adding battery storage to projects as they are unable to assess the risks around re-charging. Nevertheless, offtake demand for renewable energy remains strong; utilities remain front and center and corporates are playing an ever-increasing role.
Solar currently accounts for only 4% of power generation in the US. If the US is to hit its 100 percent carbon-pollution free power by 2035, by 2031, more solar must be installed annually than has been installed cumulatively through 2021, according to SEIA.
Bottom Line:
Investment in clean energy cannot slow – it must increase and accelerate. Successful financiers and developers should pay attention to macro-economic, regulatory, and ESG-related trends and forecasts. They should carefully plan, build partnerships, and harness emerging tools, technologies, and approaches that allow them to ramp distributed energy investments.
The market continues to explore insurance - credit, panel supply, performance, regulatory, and trade – as a tool critical to enabling the achievement of domestic energy goals.
Energetic is proud to be at the center of this drive. Our credit insurance products enable broader and more cost-effective capital provision by covering sub-IG and unrated offtakers in a wide array of renewable energy markets.
Economic and political rough seas are ahead. The strongest players in energy financing know not to stall; they see this as an opportunity to plan and capture long-term market opportunities.
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Thanks to Nathaniel Eng and the whole Novogradac team for organizing the event, and to Sam Kamyans and John Marciano at Allen & Overy, Julian Torres at Scale Microgrid Solutions, Rob Martorano at Greenskies Clean Energy, Dirk Michels at MidValley Power, Craig Robb at City National Bank, Evan Karambelas at Soltage, Rod Eckhardt at Seminole Financial Services, Justin Elswit at Celtic Bank, Winston Chen at Clean Capital, and many more for your insights and company.
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Have questions on how Energetic Insurance can reduce barriers to cost-effective procurement and help support the greening of supply chains? Reach out!
This article does not constitute and is not intended by Energetic Insurance to constitute financial advice or a solicitation for any insurance business.
How the Inflation Reduction Act is Impacting Clean Energy Financing and Development
The Inflation Reduction Act (IRA) was front and center two weeks ago at Novogradac's Renewable Energy conference. We entered the event with several questions - many were answered, but as we peel back the onion, even more questions emerge.
There is no doubt that the IRA will bring about a favorable investment environment across the renewables spectrum, but there is still a lot of dust that needs to settle.
Here are three things we learned:
1. Everyone is waiting for IRS guidance
Getting that guidance could take up to a year. The IRA offers investors 10 years of certainty around tax treatment, but as always, the devil is in the details. As guidance emerges from the IRS, the devils will be revealed, but it will take a long time before anything binding is issued. This bill represents the first time that workforce protections and content requirements have been attached to tax incentives. That, coupled with the sheer size and scope of the bill, lead us to believe that guidance will be slow to emerge.
2. Direct Pay and Transferability will have limitations
Direct pay is useful but is limited to a narrow set of circumstances - tribal lands and other tax-exempt entities. The main winner of direct pay is the manufacturing sector, which will be able to benefit from direct pay to stimulate working capital investment. Similarly, transferability will likely be more limited than initially thought - at least in the near term. IRS guidance will certainly help add clarity, but there remain numerous nuances to consider.
3. Up to 70% of the capital stack in tax equity!
Given the amount of tax equity now available, many are asking whether there is a place for debt in the capital stack. The answer across the conference was a resounding yes, and not just because most of the attendees were bankers. Getting to 70% tax equity requires taking advantage of every adder available, which is unrealistic. The thought does leave us with two unanswered questions:
(1) Will lenders relax their sponsor equity requirements?
(2) If lenders are seeing their ticket sizes drop in favor of tax equity, will they need to identify ways to expand their appetite or addressable market in order to deploy the same capital volume? Time and IRS guidance will likely reveal an answer.
If you have thoughts on likely impacts of the Inflation Reduction Act, reach out or leave your thoughts in the comments.
We’ll keep you posted as we learn more.