Solar energy generates 4 percent of the world’s electricity, according to The International Energy Agency  — the result of record-breaking growth in clean energy over the last 20-plus years. That’s the good news. At the same time, 8 million metric tons of solar panels are nearing the end of their (25-30 year) life expectancy and could be headed to landfills by 2030. Not so good.

Preparing for this onslaught of decommissioned solar panels requires us to advance the solar panel recycling process. It’s a critical step to fortify the solar industry’s effectiveness and reputation as a sustainable source of clean energy. 

Solar panels can be recycled, but only 10 percent currently are. The rest go to landfills because of the expense and complexity of recycling. There are two reasons why this is a problem.

1.Many solar panels contain cadmium and lead, which are considered hazardous waste. 

 2. Not recycling solar panels wastes valuable materials, driving the need for new raw materials. Proper recycling could recover them. 

The process of recycling solar panels involves separating a solar panel’s materials. Today, this is still too difficult and expensive. NREL estimates the per panel costs at $1-$5 (landfill) versus $5-$45 (recycling). 

Mechanical 

This involves dismantling solar panels to extract their components — removing the panel’s aluminum frame, for example. The remaining glass, silicon, and wiring are then ground separately. The success of this process depends on how well a panel’s components are separated.

Chemical/Thermal 

A promising new method separates a panel’s elements on a molecular level. The French start-up called ROSI Solar is using this technology.

Reusing is another facet of recycling where materials are extracted from a solar panel so they can have another life.

Recyclable materials from solar panels are valued at $170 million. And that number is set to grow exponentially. CleanTechnica predicts they’ll be worth more than $2.7 billion in 2030.

The solar market’s growth is accelerating the recycling market expansion. A win/win for consumers and businesses for two reasons: It will lower prices and preserve valuable raw materials.

One start-up claims to have an even better solution.  Solarcycle says its proprietary technology can extract 95 percent of high-value metals in solar panels and reuse or repurpose them in the supply chain. They say each recycled solar panel saves 97 pounds of CO2. 

The US Department of Energy (DOE) has developed a new recycling initiative aiming to be simpler and less expensive. They’ve invested $56 million, which they anticipate will incentivize the manufacturing and recycling of solar. 

States are taking action.

Washington, by 2025, will require solar companies to take back and recycle solar panels at no cost to the consumer.

The California Solar Initiative (CSI) incentivizes solar manufacturers to participate in recycling programs. 

Massachusetts and New York developed initiatives to inform the public about the correct disposal of solar panels. 

More solar companies have instituted takeback programs that cover the cost of recycling and disposal of end-of-life solar panels.

SunPower is a leader in the solar industry and has modeled ESG values for many years. Their recycling program takes a multi-pronged approach.

A new landscape of companies are planting the seeds of progress for solar panel recycling. Their efforts, coupled with government incentives and new technology, are moving us in the right direction. 

A reminder about the crucial need to reuse precious metals in solar panels. For example, two rare elements used, gallium and indium, are expensive, and there is concern that their supply is increasingly limited. Recovering them for reuse will lessen supply chain problems, ultimately reducing the cost of solar.

Check to see if your solar panel supplier has a solar takeback program. Ask questions about their supply chain sourcing strategy. If you’re a solar panel manufacturer, do your due diligence. Make sure your products are made sustainably, and if you don’t yet have a recycling strategy, build one.

Clean Power Marketing Group works with clean energy innovators, helping them grow in all the right ways. 

Contact us to learn more.

Solar energy companies have been fighting the good fight on solar policy for so long that when news broke that the Inflation Reduction Act (IRA) would include $369 billion (with a B) for climate and energy, it seemed almost too good to be true. But there it is, in black and white: a 10-year extension of the solar ITC, a standalone energy storage tax credit, and enough EV incentives to enable consumers to affordably enjoy complete clean energy systems for their homes.

Once the bill passes the House, which appears imminent, and is signed into law, it will give the solar industry better tailwinds than we’ve ever had. It’s not a leap of faith to expect that market demand – from both consumers and businesses — will be swift.

How can you take advantage of the momentum?

Now is the time to reassess your marketing strategies to make sure you’re ready for the rollout of the Act. Is your web site as engaging and effective as it could be? Is it up to date with the latest incentive information from the bill as well as local incentives?

Do your blog posts and social media channels educate and inform your prospects, not just about the process of going solar, but about the advantages of choosing your company in particular?

Is your brand message clear and distinct?  

While demand for solar is bound to be strong over the next few years, the competitive “noise” is likely to increase too. Making sure your company has a clear and differentiated brand message has never been more important.

Clean Power Marketing Group can help. We’ve been working with solar companies across the country since 2015. Because we understand renewable energy – and more importantly, how to talk about it in a clear, powerful and persuasive manner – we hit the ground running to build marketing campaigns and processes that help close sales more efficiently.

Are your marketing and sales systems talking to each other?

It is more important than ever for solar companies to quickly respond to sales inquiries, answer questions, close deals and complete installations on time. It is crucial, especially at this moment, that consumers and businesses alike have a positive experience when they install solar — beginning with the first conversation to the completion of the project. The future of our industry – and our planet – depends on it.

You want your customers to be not only delighted with the experience, but to become advocates about solar in general — and your company in particular.

We’ll help you put in place the right strategies to build and nurture your pipeline. This includes everything from auditing your web site to make sure it’s operating efficiently to optimizing customer reviews as well as developing content like blogs, case studies, email marketing, sales tools and videos. Think of us as a virtual extension of your marketing team.

We can also test your sales systems to make sure your response time is competitive and that leads are being handled with care. This combination of marketing and operations follow-through ensures that your marketing dollars are well-spent, with excellent ROI.

The IRA is indeed good news, but we have miles to go before we reach our emissions goals. As an industry, we’ve been waiting for this moment. Together, we will succeed – beyond our expectations.

Contact us today for a free, 30-minute consultation to discuss how we can help. Or make your own appointment with us here.

It’s no secret that the future of energy lies in harnessing renewable sources, like solar, wind and energy storage. The recent IPCC report highlighted the urgency of the clean energy transition. For those of us involved in marketing clean energy and other climate solutions, our jobs just went from challenging…to critical.

How can you make your marketing efforts more effective when the planet’s clock is so relentlessly ticking?

Perhaps it goes without saying, but we’ll say it anyway: Marketing goals should be specific, measurable and achievable — and carefully aligned with business objectives.  Engage the management team in setting the goals. Talk with your sales team to understand what kind of help they need to support their efforts. At this stage you are listening more than talking.

Before setting down to doing the marketing work, take a beat to understand your customer’s journey. It can be tempting to skip this step in the interest of time, but don’t do it. If you do, you’ll only have to revisit the journey when your marketing efforts fall short.

Like other buying decisions, the customer journey for renewable energy starts with awareness – the realization that a consumer or business needs or wants the product or service you offer. While climate reports help spike awareness of the need to take action, it’s not always easy to connect the dots on how a particular product or service can help. This is where a well-timed, consistent content strategy is crucial.

According to the Content Marketing Institute, 50% of content created was intended to generate awareness and spark interest within this first step. Not surprisingly, this is where we find our first “do” on the list: content marketing.

Content is still the cornerstone of digital marketing. In marketing clean energy, compelling content – with credible proof points, testimonials and highly evocative visuals – is the linchpin of an effective marketing plan.

Blogs will be one of your biggest sources of inbound traffic, and original press releases or newsletters generate two times more traffic compared to sharing articles. Additionally, blogs grant opportunities for better search engine optimization – a key metric for analyzing user data and the performance of your web site. For example, blogs that pop up on the first page of your SERP (search engine results page) typically have clear headers with key search terms, meta descriptions and are longer than you might think – averaging just under 1500 words. 

Content of interest to your readers could be as simple as photos of the finished system or interviews that describe the customer’s journey to clean energy. All of these are grist for the content mill, to be shared through email marketing, social channels and more. Sharing these examples shows dedication to customer satisfaction and a willingness to constantly improve.

Once you’ve written a blog don’t forget to share it – everywhere. Email marketing is still one of the best ways to do this – in fact, email marketing has the highest return on investment for B2B companies, achieving a whopping 4400% return. This is to say that for every dollar spent, the return can average around $44. 

For B2B companies, marketing emails are most effective when they feature original content that is informative and educational — and most of all, interesting. Good content is like a good story: It has an arc. For example, if you’re a solar company who sells to commercial businesses, customer case studies will be a key part of your content arsenal. Businesses need to see that other businesses, particularly those in their own industry, have successfully made the transition to renewables — and how.

One of the most frequent questions we get as a B2B marketing agency is, what role do social channels play in the decision-making process? The answer, not surprisingly, is significant. B2B customers are people too, and they have media habits that are not that different from consumers. But that doesn’t mean you have to be equally active on all social media platforms. It’s better to choose two or three channels and focus on authentic engagement as well as posting. For B2B clean energy, Linked In and Twitter are perhaps the most influential social channels, though even Youtube videos can play their part (yes, people watch Youtube videos at work).

According to LinkedIn data, 80% of B2B leads come from the platform. When posted content from the company page is shared by employees, the click-through rates from that reposted content is twice as high as the original post. Not all posts have to be blogs; listicles, or “list posts,” are short-form content that outline the important information in quick bullet points. Listicles are very effective, as they generate twice as many shares as “how to” tutorials and outperform infographics as a whole. 

Once your prospects are aware of your business, they embark on the consideration part of the buying process, in which your product or service undergoes a comparative process with competitors. Content that differentiates your company is effective in this stage, but social media still plays a part, especially if you’re posting informative articles on those platforms, specifically LinkedIn. 

Social media can even be useful during the decision-making phase, the final destination of the purchasing journey. Compared to LinkedIn, Twitter is more effective at showing the human side of the business – opinions, conversations with other industry leaders and customer interaction. Twitter will probably not be the last point of sale, but it can sway customer opinion.

Knowing what to do to make your clean energy marketing most effective is helpful, but knowing what not to do may be even more important. Some of the “don’ts” in this list may seem intuitive, but they bear repeating.

Engagement keeps your company top-of-mind, and reassures customers and prospects that your company is responsive. If you’re not able to respond to customer questions, either through email or social media, then you’re not engaging. The customer made the effort to reach out to your company, and they expect that effort to be reciprocated. 

Understanding clickthrough rates, bounces, inbound traffic, length of time spent and SEO are all terms that are imperative to analyzing the current state of your marketing performance. These data points, though not exhaustive, are relatively easy to access and allow for both specific and general insights into your marketing effectiveness.

Most social media platforms house this data natively within the apps and can be accessed through user settings. You can use a social media platform like Hootsuite to measure social efforts, with Google Analytics providing fairly rich analysis of social’s role in your web site performance. A robust email platform like Mailchimp can drill down into email marketing performance such as A/B testing. 

By now, we hope you understand that platforms like TikTok, Pinterest, Snapchat and, in some cases, Instagram and Facebook, are not as effective for B2B marketing.These platforms target different audiences, which makes it difficult to cater posts to the ideal consumer population. For companies in the renewables sector, LinkedIn appeals to a slightly older demographic, although millennials are fast catching up on the platform. Twitter is powerful in the RE world too, when you do your homework on hashtags and influencers. (You know who you are out there…)

Whether you are new to the world of renewable energy marketing or a veteran of the industry, it’s important to reassess marketing efforts on a regular basis. If you’re new to digital marketing, the best way to get started is just to dive in – there is a bit of a learning curve, so don’t get overwhelmed. For seasoned marketers, it’s advantageous to monitor your current marketing status and opportunities for growth.

We know clean energy marketing can be a difficult job, but it’s never been more urgent.

Contact us for help along the way!

New Year’s resolutions on climate action are too quaint for where we stand today: fighting an existential battle that is already well underway.  The 2021 United Nations Report on Climate Change repeated the clarion call from its last report with even greater urgency: We are rapidly running out of time to limit global warming beyond 1.5 degrees Celsius over pre-industrial levels.

As 2022 kicks off, companies face challenges on many fronts:  COVID has yet to loosen its grip, and supply chain constraints continue to vex many industries as record-breaking winter storms blanket parts of the U.S., including vital transportation routes. The climate crisis may seem like a distant threat when you’re facing such immediate concerns. But the truth is, your customers are experiencing a rising sense that climate change is here to stay, and they’re frustrated with the lack of a comprehensive, coherent response plan from both the public and private sector.

For purpose-driven companies, this is where a strong marketing campaign comes in — one that links the reality of climate change with equally real, actionable solutions such as rooftop solar energy, electric vehicles and other sustainable products.

Let’s start with the good news: Public support for climate solutions is growing.

American attitudes on climate have been changing, according to Climate Change in the American Mind (CCAM), a research study conducted twice yearly from 2008 through 2020 by the Yale Program for Climate Change Communication in association with George Mason University.

Americans who think global warming is happening outnumber those who do not by a factor of four to one.

Climate Change in the American Mind, March 2021

While geographic differences in opinion do exist, Americans are, by and large, waking up to the realities of climate change. A majority of Americans (64%) say they are at least “somewhat worried” about climate change.  One in four Americans say they are “very worried.”

And perhaps most significantly, two out of three Americans (64%) now feel a personal sense of responsibility to help reduce global warming, according to researchers.

Now more than ever, Americans are ready to fight climate change with solutions that they can personally control.

Going Local: What Do Climate Attitudes Look Like Where You Live?

It’s all well and good to look at national public opinion, but when it comes to American consumer behavior, location matters. The Yale Public Opinion Maps provide details on the differences in public opinion down to each state, county and even Congressional district. (For a deeper dive on how American views and actions differ by sociodemographic and political factors, check out the CCAM Explorer tool.)

For those in the business of sustainable products and solutions, Yale’s Six Americas tool (first developed in 2008, evolved yearly since then) segments the American public into six audiences that each respond to the issue of climate change in their own unique ways:

Over the years, the proportion of the public that falls into the “Alarmed” category has increased – from 17% in 2008 to 26% today, while the number who are “Disengaged” has decreased. Clearly we are seeing the rise of a more climate-active public, as you can see from the graph below:

Moving from Climate Alarm to Adoption of Climate Solutions

At the heart of the climate action movement is the need to translate the rising concern over the climate crisis into actionable solutions.

Importantly, researchers point out that while the “Alarmed” category of respondents are convinced global warming is real and support strong climate policies, they do not have an equally strong understanding of what they or others can do to solve the problem.

This is why it’s so crucial to put forward a solutions-based message to the climate crisis.

For example, until now, solar marketing campaigns have focused primarily on the financial benefits of solar—and it’s been an effective strategy with a certain demographic. But the evolving attitudes of Americans toward climate suggest that a climate solution message could also play well. When 55% of the public is either “alarmed” or “concerned” about climate change, it begs the question: Are you presenting your message in the most compelling way to every sector of your audience?

One way to check is to use the Six Americas Super Short Survey as a barometer on where your audience stands on climate. With four simple questions you can segment your audience into actionable categories. You can even gamify the tool with landing pages that help you further segment your audience with key demographics.

All of this is to help you better understand your customers and prospects so that you can generate the content they’re interested in – and the solutions they are increasingly focused on adopting.

For more information on how to better segment your audience and make climate action a key part of your 2022 marketing strategy, reach out to us at Clean Power Marketing Group.

by Nancy Edwards, Managing Partner
Clean Power Marketing Group

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by Woody Welch

Shining the best light on your renewable energy projects is imperative when trying to convey an effective marketing message. Investing in professional, creative photography and video will pay for itself many times over in the highly visual world we live in today. Here are some tips on how to create visual assets with great ROI from our talented partner and friend, Woody Welch, who has traveled far and wide shooting some of the most stunning solar photos and videos in the industry. 

The word photography comes from Latin, with photo meaning light and graph meaning to write or draw. What we are doing when we take a photo is writing with light. When it comes to marketing your clean energy company, it pays to ask yourself, “Am I shining the best light on my projects?” 

There are many variables when shooting photos of any renewable energy project. Here are my top 10 tips for getting the best return on investment from your photography and video assets. 

1.) Photograph your solar energy projects in the best light. Shooting at mid-day can actually work well because of the connection with the sun (what I call the “plug-in” moment) or the “angle of incidence.” This plug-in message can often be conveyed throughout the day instead of just at the golden hour at the beginning and end of the day.  The angle of incidence is captured when the sun is at a 45-degree angle to your project, casting the sun’s reflection directly into the lens, whether it be an aerial photo, on a rooftop or on the ground. 

2.) Use the golden hour to create drama and emotion in your projects. This one is simple: Wake up early and shoot the hour starting at sunrise or shoot the hour before sunset and a little after. Additionally you can photograph mid-morning or late afternoon to get shadows to help create depth perception. 

3.) Hire a professional, not a hobbyist. It seems today that everyone is a drone photographer and there are as many fly-by-night shooters as there are raindrops in a thunderstorm. Take the time to look at the professionals’ work. Make certain that their BODY of work is not just a few images they got lucky with but rather multiple groups of great images of many projects that show they have consistently produced value for their clients. A great photographer will produce excellent work for EVERY client. They may cost more up front but your ROI will be vastly better in the short and long run. 

Quick story to highlight this point: I had a client in the high-cost market of LA try a low-cost photographer once instead of paying my team market rate to do the job right the first time. The client was back in less than six months and more than willing to pay my professional prices because he understood the value my photos brought to a sales situation. Here’s what he said to me:

“Your images speak for me. I don’t have to talk when I use your images in my decks. They speak a thousand words and allow me to do what I do best instead of spending hours explaining what it is I do.”

He is still my client 15 years later.

4.) Make sure your photographer is using the highest quality and best camera and/or drone possible. You’ll want to be able to use your visual assets in all situations, from full-screen websites to trade show displays. If you expect your company to grow, as most solar companies today do, prepare for growth with high-ROI digital assets.

5.) Have a plan for campaign-based media placement and a schedule. Don’t invest in high-quality, high-ROI assets unless your plan is in place. If you don’t have an in-house marketing team, hire one like CPMG to help maximize your return on investment. 

6.) Plan plan plan! Dot all your I’s and cross your T’s. Make all contacts with property managers, and get advance clearance for properties and permissions from the FAA for drone flights (where applicable). All properties around airports will not be able to be documented with a drone. Also cities like DC have no-fly zones and you will have to get permission sometimes months in advance. If you hire a reputable photographer, they will do the heavy lifting for you. 

7.) Have backup plans for your backup plans and a thorough rain contingency plan. For obvious reasons, you cannot shoot solar projects in the rain. Additionally your message will be diluted if you shoot in cloudy or overcast weather. Please don’t make me explain this one. 

8.) Be prepared for high-resolution file workflow and build a DAM (Digital Asset Management system) to double or triple archive your visual assets. This is literally an insurance expense and an investment in efficiency that will pay dividends over the life of the images. 

9.) Eliminate variables. Much of photography is about eliminating what is not important in any given image. Many of our clients have sections in their brand standards manuals for visual asset creation to make sure all of their photographers and videographers are “on the same page” and capture assets that feel and look the same creating consistency throughout their assets. This is a much bigger deal than most folks think it is.

10.)  Budget for high-quality assets and plan and prepare for success! Great photography and video can go viral, create more traffic to your website (especially with the right visual SEO), and even win clients. Yes, even that. The right emotional tone in one video or a single photo can create a powerful connection to a customer, even in the commercial solar world.

There are so many factors involved in creating great photography and videos that deliver short- and long-term ROI. When photography is on message, technically precise and of the highest quality possible, your ROI will be many times greater than if you go the cheap and easy route. 

Woody Welch, founder and CEO of Earth Repairian Media and owner of Wood E. Photography, has been in the trenches in the energy industry for over 25 years, documenting some of the world’s largest renewable energy projects, directing commercials and video stories and creating high-ROI, on-message imagery for Fortune 500 clients on time and on budget every time. Get in touch today to transform your solar marketing with powerful visual assets.

By Adam Peltz

Louisiana has a long history of oil and gas development, with 50,000 wells distributed across the state and along the coast. The state has a responsibility to ensure none of these wells become an environmental or economic liability.

A long-abandoned well sits off the shore of the Louisiana coast

About a third of these wells are non-producing but registered as having future utility, meaning the operator claims that they could be economically productive in the future. As a result, the operator isn’t required to plug the well. However, once wells are idled for more than three years, just one in five ever return to service. Often they will only see a tiny fraction of their former production levels.

Ultimately, in the absence of policy change, many of these wells will become orphaned and their operators will disappear. If the orphan wells are ever to get plugged, the state and the people of Louisiana will have to shoulder the costs.

Thousands of oil and gas wells across Louisiana at risk of improper abandonment as they sit idle will become less likely to produce again over time.

This matters because old, unplugged wells cause a host of economic, environmental and even public health and safety problems. They can leak methane and toxic air pollution, contaminate water, reduce property values and prevent other economic uses of the land and the geology.

Louisiana’s efforts to plug old oil and gas wells could create thousands of new jobs, safeguard environment
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Louisiana already has around 4,300 orphaned wells, a backlog that developed because of decades of underinvestment. The federal government is providing Louisiana over $100 million dollars through 2030 to plug these wells.  500 of them have been plugged this year alone.  But the state has a long way to go. There are 17,000 wells currently in future utility status, 50 percent of which have not produced in five or more years, and tens of thousands of low-producing wells that are likely to apply for the same status in the near future. Without better planning and policy, the list of wells that require taxpayer funding to plug could grow many times longer.

To stem the tide of well orphaning, the Louisiana Department of Resources has proposed a new rule that limits extensions of future utility status. The longer a well stays in that status, the more fees operators will have to pay. This provides an economic incentive for operators to plug their wells as opposed to keeping them in this idle status.

EDF estimates that plugging future utility wells will create thousands of full time jobs across the state.

This important reform will not only help the hundreds of thousands of people who live near these wells but will create a wave of job creation in Louisiana’s oil patch. These will be well-paid positions, generating far more economic activity than any future production from these wells.

Louisiana is on a path toward responsible stewardship of its oil and gas resources, which includes ensuring that all oil and gas wells are plugged in a timely fashion, at the end of their useful lives, by their operators. Doing so not only protects the people living near these wells and reduces climate impact but also unleashes tremendous economic potential. This comes directly from well closure jobs and indirectly by facilitating new clean energy uses for some wells and well sites. This year’s reforms curbing long-term well idling are a key step toward Louisiana’s clean energy jobs future.

By EDF Blogs

By Pamela MacDougall and Cole Jermyn

UPDATE: Since the publication of this blog post on April 27, 2023, the New York Public Service Commission has made meaningful progress within its new Medium- and Heavy-Duty Electric Vehicle Charging Infrastructure proceeding. The PSC accepted comments on its initial questions from several dozen parties including EDF, and technical conferences are expected this fall. Despite this, the proceeding will likely continue into next year, leaving many early adopter fleets without sufficient access to charging infrastructure and potentially setting the state behind on its electrification goals. With deadlines from the Advanced Clean Trucks rule and emissions reductions goals from the Climate Leadership and Community Protection Act rapidly approaching, now is the time to kickstart the deployment of truck and bus charging infrastructure in New York. The state must implement interim solutions while the PSC continues to move forward. Primarily, changes can be made to the medium- and heavy-duty make-ready pilot program by expanding its eligibility to be more accessible to different types of fleets, depot owners and repair shops. Additionally, the program’s budget can be expanded, as the Commission’s Staff has already proposed. The Commission must also work with its sister agencies including the New York State Energy Research and Development Authority and the Department of Transportation to support near-term deployments of charging infrastructure. Not only will these solutions help provide the charging infrastructure that fleets need now, but the PSC will have the learnings it needs to have a full-scale medium- and heavy-duty charging program in the future. Environmental Defense Fund commends the PSC for the progress made so far on the proceeding and is looking forward to working with the commission to ensure no time is wasted in deploying necessary charging infrastructure improvements.  

After much anticipation, New York is taking a significant step to accelerate the rollout of zero-emission trucks and buses. Last week, the New York Public Service Commission formally opened a proceeding aiming to deploy the charging infrastructure needed to serve medium- and heavy-duty electric vehicles. This is a critical opportunity for the state and its utilities to make real progress towards achieving New York’s ambitious climate and truck and bus electrification goals.

New York is already on its way to get these vehicles on its roads and to meet these targets — having adopted California’s Advanced Clean Trucks Rule in 2021, which requires auto manufacturers to invest in, produce and sell an increasing percentage of zero-emission trucks. The state also aims for all new school buses to be electric by 2027, with school bus fleets ready to fully electrify by 2035. But to carry these objectives through, regulators and utilities must ensure that there is sufficient charging infrastructure to adequately support the coming zero-emission vehicles.

Although New York has existing pilot charging programs, several issues in the current programs have limited their use. To fix this, EDF, along with a group of other non-profits, filed a petition with the PSC in 2022 calling for this dedicated, comprehensive proceeding.  While improvements to the current pilot programs are coming, the issue of truck and bus charging will not be solved by nibbling around the edges of past programs.

New York Public Service Commission turns the wheel on truck and bus charging infrastructure
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For these charging programs to be effective, there must be a holistic effort that includes support for make-ready infrastructure, requirements for extensive marketing and outreach, proactive planning and managed charging, such as:

The PSC now has an opportunity to be a national leader in the transition to zero-emission truck and bus deployment and push the state closer to its climate goals. Widespread adoption of zero emission trucks and buses will reduce greenhouse gas emissions and harmful local air pollution, benefiting the climate and the health of communities throughout the state. The proceeding must now move quickly and thoughtfully to support the near-term tasks needed to expand and improve charging infrastructure. It is long-awaited, much-needed and EDF is excited to continue to engage in this critical work.

By EDF Blogs

Hydrogen renewable energy production pipeline – H2 can leak easily through joints and valves (if they are not correctly tightened).

By Sofia Esquivel Elizondo

Enthusiasm for hydrogen as a climate-friendly fuel of the future is everywhere. Hundreds of hydrogen energy projects worth more than $500 billion have been announced, and The International Energy Agency says hydrogen demand could increase sixfold by 2050.

Scientists, though, are confident that this leak-prone gas can warm the climate when it escapes into the atmosphere. Just how much warming will depend on how much hydrogen is emitted, and that remains a giant question mark. That’s why Environmental Defense Fund set out to identify the climate risks of future hydrogen emissions and help develop technology that can detect how much hydrogen escapes from today’s infrastructure.

EDF’s groundbreaking 2022 study explained how unchecked hydrogen emissions can severely undercut the climate benefit of switching from fossil fuels to hydrogen. We found that if it’s not done right, using hydrogen could be worse for the near-term climate than the fossil fuels it would replace.

But getting a grasp on real-world hydrogen emission rates is complicated because existing technology can only detect large leaks that pose safety risks at industrial facilities. The tech that can detect smaller leaks – the kind that, when multiplied by the thousands of facilities, can worsen climate change — is just now being developed.

This challenge has resulted in wildly varied estimates of the real hydrogen emission problem through the many stages of the supply chain, from production to end use.

Published in Frontiers in Energy Research, EDF’s new paper analyzed literature to date that estimates hydrogen emissions. Our goal is to provide clarity about what we do and don’t know about how much hydrogen is leaking throughout the value chain.

The bottom line? No one really knows.

Estimates of total hydrogen emissions rates across the value chain range from about 0.0003% to 20%. Estimates also vary wildly for individual stages. The largest ranges in estimated emissions rates are associated with liquid hydrogen because it is easy for it to evaporate, known as “boil-off.” Thus, the stages with the largest variation include the deep cooling process required to transform the gas into a liquid, called liquefaction (0.15%–10%), liquid transport and handling (2%–20%), and refueling (2%–15%),

If these ranges strike you as large, you’re right. They are. If we’re going to invest billions of dollars in a “climate solution” that could actually cause warming, we need better answers.

Known Unknown: Current hydrogen leak estimates vary by up to 100-fold. We need to know more before betting the farm
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More Research, More Caution Needed

Based on the extremely wide ranges of the estimates, the paper echoes concerns and needs that EDF scientists and many others have been raising.

First, there are actions we can pursue now to begin minimizing hydrogen emissions — even before we fully understand where the emissions are coming from and how much is emitted. Because hydrogen (H2) is the smallest molecule in the universe, we know it is prone to leakage, and the practices that reduce methane and other gaseous energy leaks can serve as useful guides.

Second, because the science is clear that hydrogen emissions can cause global warming, we must start incorporating the climate risks of hydrogen systems into decision making when developing plans to scale up hydrogen deployment.

Third, we need high-precision hydrogen detection technology so we can determine the seriousness of the issue and identify mitigation measures and best practices. There is a significant gap in emissions data for the total hydrogen value chain that will only be filled by technology that can detect hydrogen at the parts-per-billion level, as opposed to the parts-per-million level of safety-focused detectors. EDF is leading an effort to pursue this technology and begin measuring emissions from facilities.

Together, these suggestions underscore the importance of doing all we can now to reduce leaks and tempering our hydrogen expectations until we know more. Hydrogen may very well be a game changer for some industries or countries as the world decarbonizes. But for now, we should proceed with measured caution.

By EDF Blogs

By Adam Peltz and Elizabeth Lieberknecht 

Recently, Louisiana, under the leadership of Gov. John Bel Edwards, became the latest state taking action to curb pollution and waste from oil and gas production. In a new proposal, the state says it will limit natural gas venting and flaring and attempt to reduce the risk of thousands of idle wells becoming orphaned. Both actions will help create jobs, protect taxpayers and safeguard the environment. Here’s how.

A future without excessive venting and flaring

Venting and flaring is a particularly wasteful practice in the oil and gas industry. Routine flaring occurs when operators burn off natural gas produced from oil wells instead of capturing it and selling it or putting it to productive use, while venting is the intentional release of natural gas directly into the atmosphere.

These practices not only create air and climate pollution, they also waste a valuable energy resource because methane essentially is natural gas. In 2019, Louisiana oil and gas producers wasted approximately 5.2 billion cubic feet of methane through venting and flaring alone — that’s $16 million of natural gas. That’s enough wasted gas to supply all the households in Baton Rouge for over a year and a half.

New rules could mean less waste, less pollution and more jobs for Louisiana
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Reducing this waste is overwhelmingly cost-effective and can help create good-paying jobs in the fast-growing methane mitigation industry, which already boasts 32 facilities across the state.

Louisiana’s proposal would prohibit flaring at certain wells, require operators to develop a plan for how they will manage gas at any new wells, improve flare safety standards and require companies to report gas that is vented or flared.  These updates will help modernize the state’s oil and gas regulations and reduce wasted gas.  In the Gulf South’s first Climate Action Plan, Gov. Edwards’ administration identified that addressing methane waste from venting and flaring reduces harmful climate pollution and with this rulemaking, and now they are delivering.

Preventing catastrophic tide of orphaned wells

Another problem plaguing Louisiana is the issue of oil and gas wells that have been left by their owners to idle without producing for years or even decades to avoid the cost of proper closure. There are over 28,000 wells across the state that aren’t actively producing energy but also haven’t been permanently sealed. They represent a potential $2.5 billion taxpayer liability if not plugged by their owners — on top of the state’s current liability of $400 million from its existing documented orphan wells. And unplugged wells can cause a host of economic, environmental and even public health and safety problems by leaking methane and air toxics, contaminating groundwater and preventing economically beneficial alternative uses of the geology.

Companies can leave a well idle essentially indefinitely, and many choose to do so to avoid spending money to properly seal or plug it — with only minimal showing of potential future utility for oil and gas production. Over three-fourths of Louisiana’s idle wells are over 30 years old, and over one-third have not produced in ten years or more — with some out of production for more than five decades. Most inactive wells do not produce after a few years of being idle — instead, their risk of becoming orphaned only increases over time. This effectively operates as loophole that threatens a flood of potential orphaned wells on the horizon, ready to slam already overburdened Louisiana taxpayers with the responsibility of addressing the problem that ought to have been addressed by the industry.

Louisiana is already creating jobs through its Orphan Well Program, but requiring the oil and gas industry to plug its inactive wells would create thousands more good-paying jobs across the state.

Proactively addressing this issue and preventing these wells from adding to the state’s sizable orphan well problem is an opportunity to create jobs while safeguarding the environment and public health from future damage — and, as with venting and flaring, curbing orphan wells is a key plant of Louisiana’s Climate Action Plan.

These rules are an opportunity for Louisiana to rein in wasteful venting and flaring as well as require oil and gas companies to pay for plugging their oil and gas wells when they reach the end of their useful life. The proposals from the Edwards administration are an important step in the right direction.

By EDF Blogs

GreenPower electric school bus parked in front of the West Virginia State Capitol building; Charleston, WV

By Ali DySard and Melody Reis

School districts around the country are considering a switch to buses that use less fuel, cost less, and, most importantly, provide safe and healthy trips to and from school. Only one option wins on each of these critical criteria: electric. They eliminate the dirty tailpipe emissions of diesel and other fossil fuel models that harm vulnerable lungs, they save money on fuel and maintenance costs and they can even increase the resilience of the local electric grid.

This clear choice is why the majority of the EPA’s Clean School Bus rebate program applications were for —and nearly 100% of the first round of funding went to — electric buses.

But old technology habits die hard, and propane bus manufacturers have allied with propane lobbyists to push school districts to consider their internal combustion buses. And they’re using some of the fossil fuel industry’s old bag of tricks to take on their electric rivals.

Unfortunately, the truth is not on their side and propane does not come out on top.

On Emissions, Only Electric Buses Get an A+

Today, nearly all of the nation’s 480,000 school buses burn diesel, which emits greenhouse gasses and air pollution that harms human health. That’s one of the primary reasons federal and, increasingly, state governments are investing in a transition to cleaner fleets. And when it comes to improving the air quality our children experience on their way to and from school, nothing compares to the advantages of going electric.

Propane may be cleaner than diesel, but that’s not saying much. Diesel is among the filthiest fuels on four wheels. In addition to climate pollution, diesel exhaust has been linked to a variety of negative health outcomes, including asthma and even cancer. In a similar vein, propane is a highly flammable, asphyxiating gas that, much like its fossil fuel brethren,  emits particulate matter, sulfur dioxide, carbon monoxide and methane into the environment. In fact, a study showed that in city and interstate driving, propane buses emitted more climate-harming carbon dioxide than diesel buses.

On the other hand, electric buses produce zero tailpipe emissions. That’s better for our lungs and the planet. No fossil fuel bus — including propane — can claim that.

For a Clean, Safe Ride to School, Electric Buses Get Straight A’s. Propane? Needs Improvement
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Safety and Reliability? Another perfect score

Electric school buses have an average range of at least 100 miles, well over the distance of a typical route. And their long dwell times and predictable routes allow for convenient overnight charging, which typically coincides with the lowest-priced energy giving school buses the battery charge they need to operate during the day. Just as passenger electric vehicles provide drivers with quick and powerful rides, electric motors deliver school bus drivers the power and responsiveness they need to carry our children safely and reliably.

Fossil fuel bus proponents have claimed electric buses pose new fire risks. But evidence demonstrates that internal combustion vehicles are more likely to catch fire than electric vehicles. Using NTSB data, researchers calculated the rate of fires for various vehicles. The rate of gasoline fires was 1,530 per 100,000 sold. Compare that to the rate of electric vehicle fires: 25 per 100,000 sold. In fact, electric school buses have safety features that make the risk of fire even more improbable, including sophisticated battery temperature controls, weather-durable casing and vehicle design that makes battery damage less likely.

Economic and Community Benefits

Electric school buses are cheaper to operate and maintain compared to propane and diesel buses due to several factors. Electric buses have fewer moving parts and require less frequent maintenance, leading to reduced servicing expenses. Propane engines involve more complex systems, such as fuel injection and exhaust after-treatment, which can be costly to repair and maintain. Furthermore, electric buses have longer lifespans and lower maintenance requirements since they experience less wear and tear on components like engines and transmissions. Overall, these cost and maintenance advantages make electric school buses a more economical and sustainable choice for school districts, benefiting both their budgets and the environment.

Electric school buses offer significant fuel cost savings over propane buses due to their higher energy efficiency and the generally lower cost of electricity compared to propane. Fleet managers and taxpayers who transition to electric stand to see millions in savings over the total lifetime of the vehicle’s cost of ownership. Districts using electric school buses are seeing cost savings of $2,000 on fuel and $4,400 in maintenance per bus each year.

While some school districts are currently seeing inflated pricing, we anticipate costs to come down over the next few years as the market expands.

Additionally, electric buses offer school districts an advantage no other technology can match: their large batteries and predictable schedules make them perfect candidates for bidirectional charging, which allows bus batteries to power homes, schools, and critical facilities during grid emergencies and power outages.

By sending energy back to the grid and directly to buildings, they can power heaters, air conditioners, refrigerators and medical devices — and even keep the lights on at critical facilities during emergencies. The charging patterns of electric buses take advantage of lower-cost energy at night, further reducing fuel costs. And during peak demand periods (like hot summer days when school’s out), buses can make money by selling power back to the grid.

A Smart Choice with Available Funding

Admittedly, investing the upfront costs necessary to purchase new bus fleets is a big decision for school districts and local leaders. But federal and state programs now offer historic funding that can nearly eliminate the up-front costs of going electric.

More than $5 billion in grants and rebates are available for vehicle purchases, charging infrastructure and workforce development. Another $7.5 billion will fund 500,000 new public charging stations across the country, which will supplement private and depot charging stations. Many states are also funding the transition to electric school buses. For example, Illinois and Florida are allocating a portion of their Volkswagen settlement money to electric school buses, and Maryland has set target dates for their transition to electric school buses.

Various campaigns and programs are supporting this transition, like the all-inclusive fleet leasing model started by Highland Electric and other federal grant programs contained within the Inflation Reduction Act, such as the Clean Heavy-Duty Vehicle Program and commercial vehicle tax credits.

In short, electric school buses aren’t just a part of our future — they are a viable option today and the best solution for school districts seeking to improve the health of their children and communities.  No other option comes close.

Melody Reis is the Senior Legislative and Regulatory Policy Manager at Moms Clean Air Force, an affiliate of EDF.

With a long list of new federal tax credits available through the Inflation Reduction Act (IRA) passed in 2022, it can be hard to know where to start. Since tax credits are available through 2032, there’s time to plan your home improvements to maximize your energy and financial savings. This is the first in a series of blog posts on projects that could qualify for IRA benefits.

Before investing in big-ticket items like heating and cooling systems, it’s smart to make sure your home is properly weatherized. This means making improvements that keep air from entering and leaving your home through gaps, cracks and openings. If you add up the small gaps, cracks and leaks in a typical home, it’s the same as leaving a window open year-round.

Fall is the perfect time to address air leaks in your home before the temperature drops. This can include sealing leaky air ducts, replacing caulk or weatherstripping around doors and windows, adding insulation and installing new windows. Making these weatherization fixes alone can lower your energy bills by an average of more than $250 per year, while also improving your indoor air quality and making your home more comfortable.

When combined with bigger-ticket items like heating and cooling systems, weatherization improvements deliver even more value by helping to maximize the energy savings of those appliances. That’s because air leaks make your furnace work harder to control your home’s temperature, making it less efficient and using more energy.

“Proper sealing and insulation allows your heating and cooling systems to operate efficiently, saving you energy and lowering your bills,” said Jose Benitez, a home performance manager with HomeRx and a member of Energy Trust’s Trade Ally Network. “The most important spaces to prioritize are attics, crawl spaces and walls, especially in older homes built before building codes required specific amounts of insulation.”

For example, homeowners who weatherize while also installing an energy-efficient heat pump save between $500 and $800 more per year in energy costs than homeowners who install heat pump but don’t weatherize, according to the American Council for an Energy-Efficient Economy, and weatherization projects can pay for themselves and then some within a few years. For example, weatherization can help bring down the lifetime cost of owning and operating a heat pump by as much as $11,000.

Similar savings and cost benefits apply to other heating and cooling systems installed in weatherized homes.

When it comes to paying for weatherization improvements, Energy Trust offers insulation and window incentives to lower the upfront costs. Federal tax credits of up to $1,200 are available to offset costs of insulation and up to $600 for the cost of new windows.

“I always encourage my customers to take advantage of those offerings,” said Benitez. “There are a lot of people who aren’t aware of these incentives and the impact they can have. It only takes a few minutes. If they click ‘yes’ a couple of times, I can take care of the rest.”

For more advice on where to get started, check out Energy Trust’s DIY resources or find a contractor in the Trade Ally Network who can connect you to incentives and services.

Note: Requirements for federal tax credits and Energy Trust incentives may differ. Energy Trust does not give tax advice. Consult your tax professional for current information on credits available and how to apply. 

The post Why weatherization is the first step you should take to enhance your home’s energy efficiency appeared first on Energy Trust Blog.

Mt. Hood Ductless, an Energy Trust of Oregon trade ally contractor, is a community-focused heating and cooling contractor that helps its customers save money on efficient heat pump installations. Many of the installations that Mt. Hood Ductless completes involve ductless heat pumps (DHPs). DHPs are an efficient option for heating and cooling multifamily and single-family residences as well as small businesses.

Mt. Hood Ductless completed two DHP installations in supportive housing developments in Dallas, Oregon, as part of Energy Trust’s Community Partner Funding initiative. Community Partner Funding provides increased incentives that participating community-based organizations can access for their clients.

Jen’s Place installed 15 DHPs in their townhouse-style apartments, and East Place Apartments installed DHPs in their five-unit complex. The DHPs were installed with no cost to the properties allowing the properties to have more resources available to support their residents. A few weeks after the projects were completed, Aaron McNally, the owner of Mt. Hood Ductless, went back to the communities and talked to the residents.

“It was really nice to hear the feedback from the customers. They said they were much more comfortable, and their utility bills were going to go way down.”
– Aaron McNally, owner, Mt. Hood Ductless

McNally prioritizes keeping Mt. Hood Ductless a small company and connecting with customers. “When you get too big, you lose some of the personal touch and connecting with customers is what is most important to me,” he explains. McNally is committed to working with non-profits and serving communities that have been traditionally underserved by utility programs. “It is important to me that my company supports people who have lower than average incomes,” McNally explains. “These are the communities that really need access to technologies like ductless heat pumps.”

In addition to his focus on serving customers with low incomes, McNally is starting a non-profit called Green NW. Green NW will teach veterans returning to civilian life and individuals from low-income communities how to perform heating and cooling installations. After completing the program, the non-profit will provide participants with job placement opportunities.

Learn more about ductless heat pumps by watching the Efficiency Minute Video.

For information about available incentives for ductless heat pumps, visit the incentives page.

The post Mt. Hood Ductless, a small business making a big impact for affordable multifamily appeared first on Energy Trust Blog.

Energy Trust of Oregon is offering cash incentives that can cover up to 100% of the cost for property managers of multifamily housing and manufactured home parks to create a safe cooling space in common areas, such as lobbies, dining areas, community rooms or laundry areas.

Many of Oregon’s most vulnerable citizens lack cooling in their residences and this can be dangerous during extreme heat events. This is part of a statewide effort to provide safe cooling spaces for Oregonians, especially vulnerable populations. All property owners or managers of multifamily housing and manufactured home parks in Oregon are eligible to participate in the program.

For priority properties, defined as multifamily Tribal, affordable, nonprofit-managed, senior, and agricultural workforce housing and manufactured home parks:

100% of project costs reimbursed, up to a maximum of

For all other properties:

60% of project costs reimbursed, up to a maximum of

Energy Trust can also provide free technical assistance to select the best equipment and cooling capacity for the available space.

For more information, visit www.energytrust.org/coolingspace or contact Energy Trust to speak with someone today.

The post Keep residents safe during heat waves appeared first on Energy Trust Blog.

Energy Trust and Portland General Electric have teamed up to investigate how smart inverters on individual homes can help create a smarter, more resilient electrical grid.

An inverter plays an important part in solar energy installations, converting direct current power from solar panels to alternating current, the kind of electricity used in a home. Now, the PGE Smart Solar Study is looking at how customer-owned smart inverters serve an even bigger role, helping to better manage the grid and shape Oregon’s clean energy future.

“We aim to assess how PGE can optimize the grid’s capabilities by using smart solar inverters to their fullest potential, providing a more efficient, resilient grid for our customers and making it possible to continue to add more renewable energy to our system,” said Matthew Mills, technical program manager, PGE.

Smart inverters already communicate with the grid to disconnect a solar system if there is a power outage or other problem. This study allows PGE to explore how smart inverters can be used to improve power quality—minimizing voltage irregularities—and help make the whole grid more efficient.

In 2022, Energy Trust began working with PGE on the Smart Solar Study, part of the PGE Smart Grid Test Bed. The demonstration project is now recruiting qualifying participants.

Homeowners with solar panels and qualifying smart inverters in designated North Portland, Hillsboro and South Salem test bed areas are eligible to participate in the study. They will receive $250 for signing up and a monthly $10 credit on their electric bill while they are enrolled in the study. The study runs through December 2024.

“We’re excited to work with PGE on this innovative project,” said Jeni Hall, Advanced Solar program manager for Energy Trust, who explained how Energy Trust helped identify both the smart inverter technology that will best serve the study and the areas where there are enough homes with existing solar to fit the study’s criteria. “If homeowners can benefit from their renewable energy projects through lower monthly bills and those systems can also help utilities operate the grid more efficiently, then we’re all working together to build a clean energy future.”

Do you have solar power? See if you qualify for PGE Smart Solar Study. Interested in going solar? Request a free analysis and bid.

The post PGE’s Smart Solar Study recruiting homeowners to help strengthen the grid appeared first on Energy Trust Blog.

In spring 2023, three affordable housing providers came together to celebrate their accomplishments in the first year of Energy Trust of Oregon’s Multifamily Strategic Energy Management (MFSEM) offering. The virtual gathering hosted by Energy Trust gave members of each participating organization the opportunity to share their progress towards embedding energy management into their daily operations. Through the offering, participants discovered how to educate their residents on energy use as well as new ways to save energy in their buildings. Participants’ collective efforts earned them a total of $80,000 in cash incentives and saved over 100,000 kWh of electricity across their enrolled properties.

The three organizations collectively engaged over 200 residents through 21 in-person energy conservation workshops led by program partner Community Energy Project (CEP). CEP workshops were hosted at participating properties and demonstrated a variety of ways residents can take charge of their energy and water use while staying comfortable and healthy in their homes. Residents who attended workshops were provided with free box fans in the summer and weatherization supplies in the winter.

“We appreciated participating in the CEP workshops for our residents. Our residents enjoyed the classes and learned methods of staying comfortable with less energy use,” said Deborah Theisen, Housing and Urban Development (HUD) support office manager at Schnitzer Properties. Schnitzer coordinated with CEP to offer multiple workshops in Farsi and Mandarin to reach residents more comfortable communicating in their native languages. NeighborWorks Umpqua did the same to offer a workshop in Spanish to several of their residents.

Property staff also shared tips for conserving energy with residents in the form of monthly newsletters, door hangers, posters and staffed tables in common areas.

With the guidance of energy coaches, property staff conducted assessments of their buildings in search of ways to reduce energy use. In hosting these “Treasure Hunts,” first-year participants identified over 200 energy-saving ideas, from regular cleaning of dryer vents to seasonal adjustments in outdoor lighting timers to align with daylight hours. Two properties were inspired to take a closer look at their unit turnover checklists, adding multiple items that reduce energy waste and increase unit comfort for the next resident.

Theisen shared that her organization “had always been committed to energy savings but found most opportunities too expensive to pursue.” MFSEM enrollment illuminated new opportunities and gave Schnitzer the ability to tackle projects that were already on their wish list. “Through the program, we learned about additional places where we would be able to lower our energy consumption. Working with Energy Trust to make energy upgrades that we didn’t have to pay for ahead of time – like the LED lighting upgrades – that was fantastic,” Theisen added.

In addition to savings and incentives, participants saw positive change in their organization’s culture as a result of enrolling in MFSEM. For NeighborWorks Umpqua, the offering connected staff from departments that had previously not worked together. “Multifamily SEM got our whole organization involved in thinking about our energy usage across our entire portfolio and brought together a broad group to work creatively together,” said Albion Spahn, design & construction project manager of NeighborWorks Umpqua in Roseburg. Spahn added that these connections fostered a new level of mutual respect and appreciation among NeighborWorks staff, inspiring the organization to address energy use across their five enrolled properties. All three housing providers re-enrolled in the MFSEM offering, ready for another year of learning and saving.

MFSEM partners housing providers with Energy Trust’s technical expertise to evaluate their energy use and pursue low- and no-cost ways to improve the efficiency of their buildings. Participating organizations receive cash incentives for engaging residents and staff in ways that promote long-term savings.

Learn more about how you can save energy at your multifamily property with support from Energy Trust at www.energytrust.org.

The post Multifamily Strategic Energy Management celebrates its first year appeared first on Energy Trust Blog.

Horizontal drilling in the last decade materially altered oil and gas production in Texas. Horizontal wells allow producers to unlock vast mineral resources otherwise inaccessible to traditional vertical drilling.1 Commentors have even credited horizontal drilling as the “heart” of a “revolutionary reorientation in global energy markets, decreasing the United States’ energy dependence on foreign suppliers."2 While technology for, and development of, horizontal drilling rapidly matured, the law lags behind.3 Important questions about horizontal drilling remain unanswered by Texas courts. Among them: can a mineral lessee may drill a horizontal well that crosses lease lines without pooling authority?

According to the Austin Court of Appeals in R.R. Comm’n of Tex. & Magnolia Oil v. Opiela, No. 03-21-00258-CV, 2023 WL 4284984 (Tex. App.—Austin June 30, 2023, no pet. h.), the answer is “yes.”

Neighboring tracts are sometimes pooled together so that drilling operations on any particular tract are treated as occurring on all the tracts within the pooled unit. Importantly, before an operator can drill on pooled tracts, the Texas Railroad Commission (the “Commission”) must determine whether the operator has both a valid lease and pooling authority.

Horizontal wells often cross lease lines. Like vertical wells, operators may pool multiple tracts for horizontal wells. This presents a problem when a lessee is unable to form a pooled unit. Texas does not allow compulsory pooling outside of limited exceptions. Without an exception to the pooling requirements, the lessee may be at a dead-end. The Commission has responded to this concern by permitting horizontal wells that cross lease lines without pooling authority. These non-pooled horizontal wells fall within two categories: (1) wells under production-sharing agreements (“PSAs”) and (2) allocation wells.

PSAs are simply agreements between lessees and royalty owners that determines how production will be allocated among the tracts.4 At least 65% of the mineral and working interest owners must consent to the PSA for the Commission to issue a permit. An allocation well, on the other hand, horizontally crosses lease boundaries that have not been pooled and where no agreement exists among the royalty owners for production sharing.5 Both PSA-wells and allocations wells have become prevalent throughout Texas.

While the Commission permits these alternatives to pooling, Texas courts have not yet fully addressed whether these wells are legal under Texas law. Opponents of PSAs and allocation wells argue that drilling a horizontal well that crosses lease lines is an act of pooling regardless of what one calls it.6 The lessors in Opiela argued that these actions were pooling, such that the Commission would need pooling authority to issue a permit to drill.

Specifically, the lessors in Opiela filed suit challenging a permit that allowed Magnolia Oil & Gas Operating LLC (“Magnolia”) to drill a horizontal well into a tract with minerals leased, in part. The lessors argued that the Commission erred by failing to consider their lease’s anti-pooling clause, which prohibited pooling “in any manner whatever.” Since the lessors did not consent to pool or to a PSA (and thus lacked pooling authority), lessors urged the Commission should not have permitted Magnolia to drill. This placed squarely before the Court whether a PSA well should be treated as pooling under Texas law.

The trial court reversed the Commission’s order denying plaintiff’s complaint, finding that the Commission erred by (1) finding that Magnolia showed a good-faith claim to drill, (2) adopting and applying rules for PSA wells without complying with the requirements of the Administrative Procedure Act, and (3) failing to consider the pooling clause in the plaintiff’s lease.7

The court first answered whether the Commission has the power to issue permits for multi-tract horizontal wells without pooling authority.8 After considering the history and relationship between pooling and PSAs, the court determined that PSA wells are not the same as pooling and, therefore, do not require pooling authority.9 To do so, the Court evaluated property interests involved, as well as production divisions between PSAs and pooled wells.

For pooling, the court determined the lessee cross-conveys property interest to the tracts within the pool. Finding “a portion of the royalty interest from each of the other tracts in the pool."10 In other words, “production from any tract in the pool is treated as production from every tract in the pool."11 “Proceeds from production from one of the pooled tracts are shared by all owners of the tracts in proportion to the individual tract’s proportion of the pooled acreage."12

The court reasoned PSA wells, by contrast, do not have a cross-conveyance of interest. Nor do PSA wells have to follow the production allocation requirements for pooled tracts. Instead, parties reach private agreements in PSAs for how production will be shared.13 For these reasons, the court found that PSA wells and pooling are not the same and, therefore, the Commission did not err by failing to consider the plaintiff’s lease’s anti-pooling clause.14

Next, the appellate court found the evidence failed to show that 65% of the interest owners agreed to the PSA. Without evidentiary support for the threshold requirements for a PSA, the appellate court affirmed the trial court’s conclusion that the Commission erred in finding that Magnolia showed a good-faith claim of right to drill.15 Because the appellate court determined remand was necessary, it did not reach the question of whether the Commission violated the Administrative Procedure Act.16

Finally, Magnolia requested in the alternative that the appellate court render a judgment granting the permit as an allocation well.17 Magnolia contended that, even if the record lacked evidence to show that 65% of the interest owners joined the PSA, the well could still meet all requirements of an allocation well. The court noted that it did not have the power to make such a ruling since the Order on appeal does not pertain to an allocation well permit.18

While the Austin Court of Appeals did not answer all the questions surrounding PSAs and allocation wells, the case represents a major step forward for providing legal framework around horizontal drilling. And the appellate court’s decision should put operators’ minds at ease at least for now, as the holding preserves the Commission’s current approach to PSAs and hints that allocation wells will be treated in the same manner.

1 Ernest E. Smith, Applying Familiar Concepts to New Technology: Under the Traditional Oil and Gas Lease, A Lessee Does Not Need Pooling Authority to Drill A Horizontal Well That Crosses Lease Lines (Reprint, First Published 2017), 3 Oil & Gas, Nat. Resources & Energy J. 553, 554 (2017).

2 Benjamin Holliday, New Oil and Old Laws: Problems in Allocation of Production to Owners of Non-Participating Royalty Interests in the Era of Horizontal Drilling, 44 ST. MARY’S L. J. 771, 773 (2013), cited in Brief of Amicus Curiae Pioneer Natural Resources Co., in Support of Appellants.

3 Smith, 3 O.N.E. J. at 554–55.

4 Smith, 3 O.N.E. J. at 564.

5 R.R. Comm’n of Tex. & Magnolia Oil v. Opiela, No. 03-21-00258-CV, 2023 WL 4284984, at *1 (Tex. App.—Austin June 30, 2023, no pet. h.) (citing Clifton A. Squibb, The Age of Allocation: The End of Pooling As We Know It?, 45 Tex. Tech L. Rev. 929, 930 (2013)).

6 Smith, 3 O.N.E. J. at 556.

7 Opiela, 2023 WL 4284984, at *1.

8 Id. at *7.

9 Id.

10 Smith, 3 O.N.E. J. at 561.

11 Smith, 3 O.N.E. J. at 561.

12 Opiela, 2023 WL 4284984, at *7.

13 Id. at *8.

14 Id.

15 Id. at *12.

16 Id. at *10.

17 Id. at *12.

18 Id.

The Federal Energy Regulatory Commission (“FERC” or “Commission”) unanimously issued its highly anticipated Order No. 2023, which requires many reforms to pro forma interconnection agreements and procedures under Open Access Transmission Tariffs in an attempt to decrease the time in which it takes to move electric generation projects through interconnection queues and bring electric generating facilities online. The backlog associated with interconnection queues across the country is perceived as a root cause of stymieing the country’s transition to a less carbon-focused electric grid, and is believed to be jeopardizing the reliability of our nation’s electrical grids. Currently, the average time it takes a project to move through the interconnection process is approximately five years, which is an approximate 40% increase from only a few years ago.  Order No. 2023’s changes will impact developer’s at every stage of the interconnection process. 

We expect large number of requests for rehearing will be submitted, and would not be surprised if FERC issues an order on rehearing altering and/or clarifying some of the findings discussed here.  Nonetheless, Order 2023 will lead to significant changes in interconnection processes in many regions.

Highlights of Order 2023:

Order No. 2023 requires Independent System Operators and Regional Transmission Organizations (“ISOs/RTOs”) to submit revisions to their pro forma interconnection procedures 90 days after the rule is published in the Federal Register. FERC will still need to review and accept the ISOs/RTOs’ tariff revisions before they become effective.

A central theme of Order No. 2023 is to require all Transmission Providers to use the cluster study approach.  Cluster studies are currently used by several ISOs/RTOs and Transmission Providers, including the California Independent System Operator, the Midcontinent Independent System Operator, the New York Independent System Operator, PJM Interconnection, L.L.C., the Southwest Power Pool, NV Energy, PacifiCorp, and Public Service Company of Colorado. Cluster studies will now be required in all regions. 

Another theme of Order No. 2023 is to provide interconnection customers with greater amounts of information about potential interconnection costs at a specific location or point of interconnection prior to customers submitting an interconnection request. The Commission found that its current pro forma procedures and agreements fail to adequately provide interconnection customers with cost information that is vital to their businesses and decision-making process about whether a project they proposed to interconnect is commercially viable. This lack of information has resulted in customers submitting (and subsequently withdrawing) multiple interconnection requests at various points of interconnection, knowing that not all projects will be constructed. These superfluous requests helped create the backlog ISOs/RTOs are struggling to manage. By providing interconnection customers with valuable information and implementing more stringent readiness and site control requirements, Order No. 2023 intends to reduce the time it takes to interconnect generators to the electric grid.

On July 15, 2021, FERC issued an Advanced Notice of Proposed Rulemaking (“ANOPR”) requesting comments on proposed generator interconnection reforms and long-term transmission planning reforms. Deciding that a single rulemaking to accomplish both reforms was too aggressive, the Commission issued separate proposed rulemaking on April 21, 2022 (“Long-Term Transmission Planning Proposal) and on June 16, 2022 (“Generator Interconnection Reform Proposal”). Order No. 2023 finalizes and adopts many of the proposed reforms outlined in the Commission’s Generator Interconnection Reform Proposal. FERC has yet to finalize its Long-Term Transmission Planning Proposal; however, a final rule may be published by the end of the year. Both proposals aim to accelerate generator interconnections and re-prioritize the investment in transmission projects needed to incorporate the new generation projects into the grid.

Through the Inflation Reduction Act and other legislative initiatives, the United States continued investment in renewable generation projects, including wind, solar, and integrated battery storage systems, has resulted in a proliferation of such projects trying to interconnect to the electric grid. ISOs/RTOs have struggled to keep up with the increased number of interconnection requests. Project developers face years of interconnection studies, uncertainty surrounding interconnection costs, and severe time delays, which makes developing and financing new generator projects exceedingly difficult. Order No. 2023 aims to focus on interconnecting projects that have the greatest chance of achieving commercial operation in a more timely and cost-efficient manner.

Overview of Cluster Study Approach

To the extent they have not already done so, ISOs/RTOs will now be required to adopt a cluster interconnection study method when evaluating generator interconnection requests. Under this approach, individual interconnection requests are grouped into clusters based on the time in which the requests are submitted and will be studied in those clusters. Developers submitting interconnection requests will be subject to more stringent readiness requirements (including demonstrating a certain amount of site control to construct their project) and financial commitments as their requests proceed through the interconnection queue. FERC anticipates that the cluster approach will help to diminish queue backlog in part by reducing the number of re-studies required if a project drops out of the queue. Under the serial approach currently used in many regions, a higher-queued project that modifies or withdraws its request often triggers a domino-effect of re-studies that increase the time and costs associated with interconnection.

Cost Allocation of Interconnection Upgrades

To facilitate accelerating the interconnection process under a cluster-study approach, Order No. 2023 adopts the Generator Interconnection Reform Proposal’s to allocate network upgrade costs based on a proportional impact methodology:  generators in a cluster are assigned costs needed for a targeted system network upgrade, rather than project-specific network upgrades. ISOs/RTOs must update their procedures to establish a methodology for assigning costs towards these upgrades for each customer. Also, they will need to adopt certain terminology designed to avoid disputes between customers over who has the right to construct interconnection facilities.

The order does not, however, adopt the Generator Interconnection Reform Proposal’s to require later-positioned clusters to contribute to funding network upgrades in early clusters that they might benefit from. Instead, the Commission states that its revisions to its proportional impact funding mechanism, which creates an exception for the ISOs/RTOs to allocate costs for substation network upgrades that are only needed by specific generators (and not by all generators in the cluster) to those generators only, will ease such concerns. The Commission also explains that its existing crediting policy will alleviate later-in-time customers from benefitting from upgrades built by earlier-in-time customers. For system network upgrades, costs will be allocated based on each generating facility’s proportional impact on the upgrades identified in the respective cluster study. And the costs associated with any needed transmission provider’s interconnection facilities or interconnection customer’s interconnection facilities will be assigned directly to the customer(s) using those facilities. Order No. 2023 further contemplates situations where interconnection customers in a cluster agree to share interconnection facilities, and the costs associated with these facilities will be allocated on a per capita basis, based on the number of generating facilities that will use the shared interconnection facilities, unless the customers mutually agree to an alternative cost sharing mechanism.

More Stringent Financial Commitments, Withdrawal Penalties, and Readiness Requirements to Disincentivize Speculative Projects       

To decrease the number of speculative projects in the interconnection queues, the Commission will require more stringent financial commitments, withdrawal penalties, and readiness requirements.

Study Deposits. Order No. 2023 requires interconnection customers to provide increased study deposits in a tiered approach based on the proposed size (measured in MW) of the generating facility, as demonstrated in the following diagram:

Size of Proposed Generating Facility Associated with Interconnection Request

Amount of Deposit

> 20 MW < 80 MW

$35,000 + $1,000/MW

≥ 80 < 200 MW

$150,000

≥ 200 MW

$250,000

These deposit amounts apply to large generating interconnection facilities, which are facilities that are larger than 20 MW. Unlike the Generator Interconnection Reform Proposal, the Commission will not require a phased study deposit approach that would have included multiple study deposits. Rather, the Commission states that it will require only a single initial study deposit to cut down on the administrative burden on the ISOs/RTOs to collect multiple deposits.

Demonstration of Site Control. The Order largely adopts more stringent site control demonstrations proposed in the Generator Interconnection Reform Proposal. Initially, at the time the interconnection request is submitted, the Interconnection Customer will be required to demonstrate exclusive rights to develop, construct, operate, and maintain the proposed project. The Commission did not, however, provide technology-specific land requirements. Additionally, at the time the Interconnection Customer executes the facilities study agreement and when executing or requesting the Large Generator Interconnection Agreement (“LGIA”) be filed unexecuted, it will be required to provide evidence of exclusive land rights necessary to develop their project.

The final rule adopts a definition of “reasonable evidence of site control” to mean providing documentation establishing: “(1) ownership of, a leasehold interest in, or a right to develop a site of sufficient size to construct and operate the Generating Facility; (2) an option to purchase or acquire a leasehold site of sufficient size to construct and operate the Generating Facility; or (3) any other documentation that clearly demonstrates the right of Interconnection Customer to exclusively occupy a site of sufficient size to construct and operate the Generating Facility.” Importantly, the Commission further clarified that the right to “exclusively” occupy the site means both that the right belongs only to the Interconnection Customer and that the right is “solely for purposes of a single interconnection request.” The Commission also clarified that Interconnection Customers are prohibited from submitting evidence of site control over the same parcels of land for multiple interconnection requests unless the parcel is large enough to support the construction and operation of multiple facilities. However, co-location of projects where more than one project will be located at the same site behind a single point of interconnection is allowed, but Interconnection Customers must be able to demonstrate site control and shared land use via an agreement between the parties.

According to the final rule, demonstrations of site control also include:

Interconnection Customers will be allowed to use a deposit instead of site control demonstrations in limited circumstances where regulatory limitations may prohibit customers from obtaining site control, e.g., when they are developing a project owned or controlled by a governmental entity. Interconnection Customers that face regulatory limitations that may prohibit them from obtaining the requisite site control may submit a deposit of $10,000/MW subject to a $500,000 floor and a cap of $2 million. The deposit will be returned once the customer can demonstrate 90% site control prior to the facility study agreement’s execution or 100% site control at or after the execution of the facilities study agreement.

Demonstration of Commercial Readiness. In a decision supported by merchant developers, the Commission will not require Interconnection Customers to provide power purchase agreements or executed term sheets as evidence of commercial readiness. Rather, the Commission adopted the Generator Interconnection Reform Proposal requiring Interconnection Customers to demonstrate commercial readiness via financial deposits that correlate to the size of the proposed project. The deposits must be made at the beginning of each phase of the cluster study process: the initial cluster study, the cluster restudy, and the facilities study. The initial commercial readiness deposit will be an amount that is two times the study deposit amount to enter the cluster study that is outlined above, while the second and third commercial readiness deposits will be based on percentages of the Interconnection Customer’s identified network upgrades. The Commission hopes that tying the second and third deposits to the size of identified network upgrades will encourage customers with large network upgrade cost estimates that makes their projects unviable, to withdraw earlier in the cluster study process to reduce any need for restudies.

LGIA Deposit. Order No. 2023 adopts the Generator Interconnection Reform Proposal to require a deposit at the time an interconnection customer executes its LGIA (or requests that the LGIA be filed unexecuted). The LGIA deposit is equal to 20% of the estimated network upgrade costs identified in the LGIA. This deposit will be subject to withdrawal penalties if the project is withdrawn after the LGIA is executed or is filed unexecuted.

Withdrawal Penalties. In an effort to further disincentivize speculative projects, Order No. 2023 subjects Interconnection Customers to withdrawal penalties that will impact any study deposit refunds they may be eligible for, in the event they withdraw their project prior to execution of the LGIA. Specifically, withdrawal penalties may apply to projects where “(1) the interconnection customer withdraws its interconnection request at any point in the interconnection process; (2) the interconnection customer’s interconnection request has been deemed withdrawn by the Transmission Provider at any point in the interconnection process; or (3) the interconnection customer’s generating facility does not reach commercial operation (such as when an interconnection customer’s LGIA is terminated prior to reaching commercial operation).”

The amount of the withdrawal penalties ranges from twice the amount of study costs up to 20% of the network upgrade costs, and the penalty amounts increase as the Interconnection Customer proceeds through the interconnection process.

Phase of Withdrawal

Total Withdrawal Penalty (if greater than study deposit)

Initial Cluster Study

Two times study costs

Cluster Restudy

5% of network upgrade costs

Facilities Study

10% of network upgrade costs

After Execution of, or After Request to File Unexecuted, the LGIA

20% of network upgrade costs

Any collected withdrawal penalty funds will be used to fund studies conducted under the cluster study process in the same cluster as the withdrawn project. The remaining withdrawal penalty funds will be used to offset net increases to required network upgrades for other customers that remain in the cluster that are directly affected by the withdrawn project. If there are any penalty funds remaining after being applied to study costs or increased network upgrades for non-withdrawn projects, the penalty funds are to be refunded to the withdrawn Interconnection Customer.

Order No. 2023 states that Transmission Providers may only impose penalties where the withdrawal has a “material impact on the cost or timing of any interconnection requests with an equal or lower queue position.” Further, the final rule exempts customers from paying a withdrawal penalty if (1) the interconnection customer withdraws its interconnection request after receiving the most recent cluster study report and the network upgrade costs assigned to the interconnection customer’s request have increased by 25% compared to the previous cluster study report, or (2) the interconnection customer withdraws its interconnection request after receiving the individual facilities study report and the network upgrade costs assigned to the interconnection customer’s request have increased by more than 100% compared to costs identified in the cluster study report.”

Transition Period Process

For Interconnection Customers whose projects have pending interconnection requests being evaluated under a serial study process, Order No. 2023 identifies three options to transition to the new interconnection rules.   Note these transition processes do not apply to projects in regions where the Transmission Provider has already adopted or is currently transitioning to a cluster study process.  Transmission Providers will be required to offer existing interconnection customers the following options:

Withdrawal of a project that has opted to enter a transitional study will be subject to a withdrawal penalty equal to nine times the customer’s study deposit.

The options to be offered each Interconnection Customer will depend in part on a project’s current interconnection phase.  Option 1 must be offered to all Interconnection Customers with a tendered facilities study agreement (whether executed or not) as of 30 days after the Transmission Provider’s Order No. 2023 initial compliance filing. Option 2 must be offered to Interconnection Customers with an assigned queue position as of 30 days after the Transmission Provider’s Order No. 2023 initial compliance filing. Either of these groups of Interconnection Customers can also avail themselves on Option 3 and withdraw their requests without penalty prior to the commencement of the transition period process.

As previously noted, Transmission Providers will have 90 days to submit revisions to their pro forma interconnection procedures after Order 2023 is published in the Federal Register.  Those submissions will incorporate the transition options.  Interconnection Customers will have 60 calendar days after the Commission-approved effective date of the Transmission Provider’s filing to choose a transition option and, depending on the option chosen, demonstrate site control and provide the required deposit.

Order No. 2023 Eliminates the “Reasonable Efforts” Standard

The time in which Transmission Providers are expected to review interconnection requests and perform various interconnection studies is currently guided by a “reasonable efforts” standard, which many argue has contributed to the queue backlog developers are experiencing today. Order No. 2023 eliminates this standard and will require the pro-forma Large Generator Interconnection Procedures (“LGIP”) to include penalty provisions for delayed/late studies assessed against Transmission Providers:

Type of Study

Penalty Amount (per business day beyond tariff-specified deadlines)

Cluster Studies

$1,000

Cluster Restudies

$2,000

Affected System Studies

$2,000

Facilities Studies

$2,500

The final rule does include certain exemptions for study delay penalties and places a cap on penalties of 100% of the initial study deposit received for all interconnection requests in the cluster for cluster studies and restudies, 100% of the initial study deposit received for the single interconnection request in the study for facilities studies, and 100% of the study deposits that the Transmission Provider acting as an affected system operator collects for conducing the affected system study. Transmission Providers will also have the ability to appeal these penalties to the Commission.

Incorporation of Storage Resources Operating Assumptions

Order No. 2023 directs Transmission Providers to incorporate an Interconnection Customer’s planned operating assumptions for the proposed charging of a battery energy storage resource, including standalone facilities, co-located facilities, or hybrid generating/storage facilities, which may be included as an operating condition in the resource’s interconnection agreement. The order does provide an exemption to this general rule where the Transmission Provider finds the customer’s proposed operating assumptions conflict with reliability standards or good utility practices.

Affected Systems Reforms

Recognizing that the affected system study process is contributing to the interconnection queue backlog, Order No. 2023 adopts certain reforms to improve the process of assessing a generator’s impact on neighboring systems, aka “affected systems.” These reforms include the adoption of new terms, notification processes, study and cost allocation procedures, and financial penalty assessments against the affected system provider for causing certain delays in studies or restudies.

The final rule also requires Transmission Providers to study affected system interconnection requests in clusters and adopt a pro forma Affected System Study Agreement and pro forma Affected System Facilities Construction Agreement.

Under the new rule, affected system transmission providers are instructed to perform affected system studies under the Energy Resource Interconnection Service (“ERIS”) standard instead of the higher Network Resource Interconnection Service (“NRIS”) standard, which transmission providers currently have the discretion to choose, regardless of what type of service the Interconnection Customer requests on its host system. NRIS provides a higher level of interconnection service than ERIS and is often associated with higher network upgrade costs and restudies. To support this decision, the Commission stated that studying under the ERIS modeling standard “should reduce the number and total cost of affected system network upgrades assigned to affected system interconnection customers, which will reduce instances of ‘sticker shock’ from affected system network upgrades.”

Transmission Providers have 90 calendar days from the date Order No. 2023 is published in the Federal Register to revise their LGIP, LGIA, Small Generator Interconnection Procedures, and Small Generator Interconnection Agreements in their Tariffs. Once FERC approves the Transmission Providers’ Order No. 2023 compliance filings by issuing an order setting forth the Tariff effective date, the Transmission Provider will begin the transition study process. Once the transition study process is complete, Transmission Providers not currently utilizing a cluster study approach, will move on to the first cluster study process.

Whether or not Order No. 2023 succeeds in speeding up the time required to bring new generation facilities onto the grid remains to be seen.  Equally critical to reaching that goal will be parallel efforts to adopt and implement major transmission reforms across the country, such as those included in the Commission’s Long-Term Transmission Planning Proposal. 

Under the current system, transmission planning and upgrades have often been spurred by and paid for pursuant to requests submitted by individual generation projects.  This contrasts with the approach taken under the Competitive Renewable Energy Zone (“CREZ”) program in the Electric Reliability Council of Texas (“ERCOT”), where major new transmission infrastructure was planned and constructed even before generator interconnection requests drove the planning.  It would not be easy to design and implement a more holistic transmission planning and generator interconnection process nationwide.  But such a process could lead to significant improvements in the timing and cost of needed improvements to our nation’s electric infrastructure.

Foley & Lardner LLP served as the summit sponsor at Infocast’s CCS/Decarbonization Project Development, Finance and Investment Summit which was held in Houston on July 25 and 26. Eric Blumrosen had the pleasure of serving as the summit’s co-chair. He was impressed with not only the knowledge and insight of the various presenters and panelists, but from the abundance of energy and enthusiasm from this group in what is for all practical purposes, the founding of a nascent industry. 

Fellow partner Sarah Slack co-chaired the summit with Eric, while additional Foley attorneys presented on Qualifying Beginning of Construction Section 45Q Tax Credits (Victoria Roessler) and moderated a panel discussion on Decarbonizing Industrials (Tim Spear). Partner Kyle Hayes participated in the Infocast RNG + SAF Capital Markets conference, presenting on the Status and Outlook for RNG Production and Markets.

Before sharing a few takeaways from the summit, what is CCUS?  It is essentially an array of technologies aimed at mitigating climate change by capturing carbon dioxide (CO2) emissions from industrial processes and power plants, utilizing CO2 for various applications, and storing it safely underground. According to a variety of experts, CCUS technologies will play a vital role in limiting global warming to 1.5 degrees Celsius above pre-industrial levels.  Moreover, CCUS is also essential in enabling the sustainable use of fossil fuels during the transition to a low-carbon economy. The global energy industry is one that is predominantly based on fossil fuels and the need for energy is only growing. CCUS is a vital technology that allows us to meet our energy demands while concurrently lowering our carbon footprint. The International Energy Agency (IEA) estimates that without CCUS, the cost of meeting climate goals would increase by approximately 70%.

While the primary benefit of CCUS lies in its ability to significantly reduce greenhouse gas emissions, another advantage of CCUS is its potential to promote economic growth. Implementing CCUS technologies can create job opportunities and stimulate investment in research and development. In addition, CCUS can offer revenue streams through enhanced oil recovery projects, where CO2 is injected into oil reservoirs to boost oil production, and through other industrial uses.

Notwithstanding the benefits, CCUS faces significant challenges that hinder its broader adoption. Currently, the major obstacle is the permitting process for CCUS sequestration projects, which is long, costly and uncertain. Establishing a predictable regulatory framework for  CCUS facilities involves complex legal and environmental considerations, which may vary across different jurisdictions. Streamlining and expediting the permitting process are essential to encourage more investment in CCUS projects.

Financing is another major challenge. Building and operating CCUS facilities require substantial upfront investments, and the financial viability of these projects can depend significantly on the availability of incentives and support, particularly with sequestration projects. Governments' policies, including tax credits and other financial incentives, play a crucial role in attracting private investment in CCUS technologies.

With respect to tax credits, they have been an important driver for encouraging CCUS deployment. In the U.S., the 45Q tax credit incentivizes carbon capture projects, offering a financial incentive for each ton of CO2 captured and securely stored or used for enhanced oil recovery or other applications. However, the stability and longevity of such tax credits are essential to provide certainty to investors and ensure long-term commitment to CCUS projects which will last well beyond the tax credit scheme currently in place.

Despite the challenges, CCUS remains a crucial tool in the fight against climate change. To overcome barriers and foster its broader implementation, collaboration among governments, industries, and other stakeholders is necessary. Investing in research and development, promoting policy consistency, and supporting technological advancements are key factors in unlocking the full potential of CCUS and advancing toward a sustainable, low-carbon future.

The Inflation Reduction Act of 2022 (the “IRA”) and the Infrastructure Investment and Jobs Act of 2021 (the “IIJA”) set in motion an ongoing series of changes that are aimed at transforming, among other things, the automotive sector in the United States.  As Foley has highlighted over the last couple years,1 the federal government has been making regular updates to rules and guidance aimed at molding the automotive transportation system into an electrified system.  Two recent developments provide a glimpse into how the federal government is attempting to balance knock-on effects from the IIJA’s and IRA’s preferences for domestic production and manufacturing. 

On March 31, 2023, the IRS released new proposed regulations (the “Proposed Rules”) related to the Plug-In Electric Drive Vehicle Credit (the “EV Tax Credit”) under Section 30D of the Internal Revenue Code (the “Code”), as it was amended under the IRA. The Proposed Rules provide additional guidelines and requirements relating to the purchase of qualifying new clean vehicles and the critical mineral and battery component requirements for new electric vehicles and new qualified fuel cell vehicles. The IRS closed the window for comments on the Proposed Rules on June 16, 2023. Critics of the Proposed Rules noted that they were either too restrictive or not restrictive enough with respect to pushing domestic manufacturing

As amended by the IRA, to qualify for the EV Tax Credit, a “new clean vehicle” must be manufactured by a “qualified manufacturer” and meet certain requirements (as previously discussed by Foley here) in order to be eligible. Certain additional requirements also apply to the purchaser of a new clean vehicle in order to qualify for the EV Tax Credit. The IRA also disqualifies certain vehicles from the EV Tax Credit if the battery of the vehicle contains critical minerals or battery components from a foreign entity of concern. If eligible, the maximum possible credit per vehicle available is $7,500, of which half relates to the vehicle meeting certain requirements relating to critical minerals (the “Critical Minerals Requirement”) and the other half relates to the vehicle meeting certain requirements related to battery components (the “Battery Components Requirement”).

New Section 30D(e)(1)(A) provides that the Critical Minerals Requirement for a battery is met if the percentage of the value of the applicable critical minerals contained in such battery that were (i) extracted or processed in the United States, or in any country with which the United States has a free trade agreement in effect, or (ii) recycled in North America, is equal to or greater than the applicable percentage set forth in the chart below, as certified by the qualified manufacturer of the vehicle:

Date Vehicle is Placed in Service

Applicable Percentage

After April 17, 2023 and before January 1, 2024

40%

During calendar year 2024

50%

During calendar year 2025

60%

During calendar year 2026

70%

After December 31, 2026

80%

The Proposed Rules provide a three-step process for determining the percentage of the value of the applicable critical minerals that contribute toward meeting the Critical Minerals Requirement.

New Section 30D(e)(2)(A) provides that the Battery Components Requirement for a battery from which the electric motor of a vehicle draws electricity is met if the percentage of the value components contained in such battery that were manufactured or assembled in North America is equal to or greater than the applicable percentage set forth in the chart below, as certified by the qualified manufacturer of the vehicle:

Date Vehicle is Placed in Service

Applicable Percentage

After April 17, 2023 and before January 1, 2024

50%

During calendar year 2024 or 2025

60%

During calendar year 2026

70%

During calendar year 2027

80%

During calendar year 2028

90%

After December 31, 2028

100%

The Proposed Rules provide a four-step process for determining the percentage of the value of the applicable battery components that contribute toward meeting the Battery Components Requirement.

In applying these criteria to existing EV offerings, the effect does seem to be a winnowing of eligible EVs as evidenced by the U.S. Department of Energy’s listing of eligible vehicles, available here.

Perhaps relatedly, the administration is also hoping to enhance the American manufacturing capacity for EVs, including its component parts.  On June 28, 2023, the Office of Manufacturing and Energy Supply Chains (“MESC”) within the U.S. Department of Energy issued a Notice of Intent to Issue a Funding Opportunity Announcement relating to Domestic Manufacturing Conversion Grants.  As another outgrowth of the IRA, MESC is looking to encourage domestic manufacturing capacity through $2 billion in grants, specifically deployed through grants and loan guarantees to clean vehicle manufacturers and suppliers, including component manufacturers.  The opportunity will prioritize refurbishment and retooling of existing manufacturing facilities that have either ceased operation recently, or will cease operation in the near future.  Funding opportunities may range from $25 million to $500 million, with MESC anticipating to make approximately 9-15 awards.  Cost sharing by applicants is expected to be at least 50%.  Applicants will also be judged on their Community Benefits Plan in addition to the technical merits of an application. 

The notice of intent does not constitute a Funding Opportunity Announcement, and to the extent this opportunity is formalized, MESC will issue such a FOA.  Nonetheless, this notice highlights yet another prong of the federal government’s overall push to transition the automotive transportation economy from internal combustion engines to electrified vehicles, with an emphasis on retooling the American economy to be a manufacturing hub for these vehicles.  Funding opportunities like the one forecast in this notice of intent will hopefully enable even more EVs to be eligible for the EV Tax Credit.

Foley is continuing to monitor developments in the EV ecosystem and is available to help clients put these developments into practice for their businesses.

1 See our prior articles on EV infrastructure and EV developments from the federal government including: https://www.foley.com/en/insights/publications/2022/01/as-ev-adoption-rises-infrastructure-inflection, https://www.foley.com/en/insights/publications/2022/02/us-dot-releases-nevi-formula-program-guidance, https://www.foley.com/en/insights/publications/2022/05/doe-announces-3-billion-funding-supply-chain, https://www.foley.com/en/insights/publications/2022/06/us-dept-of-transportation-proposed-ev-charging, https://www.foley.com/en/insights/publications/2022/08/ev-charging-station-tax-credits-are-back, https://www.foley.com/en/insights/publications/2023/03/new-rules-ev-tax-credit-inflation-reduction-act, and https://www.foley.com/en/insights/publications/2023/04/us-dot-finalizes-ev-charging-infrastructure-rules.

The Internal Revenue Service (“IRS”) and Department of the Treasury earlier this week released extensive proposed regulations relating to direct cash payments for certain tax credits pursuant to Section 6417 of the Internal Revenue Code (the “Code”) (the “Proposed Direct Payment Rules”) and transfers of certain tax credits pursuant to Section 6418 of the Code (the “Proposed Credit Transfer Rules”).  In each case, taxpayers may rely on the proposed regulations until final regulations are promulgated, and parties interested in commenting on the Proposed Credit Transfer Rules or Proposed Direct Payment Rules before final regulations are issued may submit written comments to the IRS by August 14, 2023.

Additionally, the IRS and Treasury released temporary regulations relating to taxpayer registration requirements with respect to tax credits for which a direct cash payment will be claimed pursuant to Section 6417 of the Code and with respect to tax credits transferred pursuant to Section 6418 of the Code (the “Registration Rules”).

The Inflation Reduction Act (the “Act”), passed in August 2022, allows certain entities, including tax-exempt entities, states and political subdivisions, the Tennessee Valley Authority, Alaska Native Corporations, and Indian tribal governments, to claim a direct cash payment equal to the amount of certain specified credits under new Section 6417 of the Code.  This election is available for the production tax credit under Section 45 of the Code (“PTC”), credits under Section 45Y relating to technology neutral PTCs beginning in 2025, the investment tax credit under Section 48 of the Code (“ITC”), credits under Section 48E relating to technology neutral ITCs beginning in 2025, and several other credits.  Taxable entities may elect to claim cash payments in lieu of tax credits only with respect to the Section 45Q carbon capture and sequestration credits, Section 45V hydrogen production tax credits, and Section 45X advanced manufacturing production tax credits, and subject to certain limitations provided in the Act.  The election must be made no later than the due date for the tax return of the year in which the election is made. 

The Act also permits taxpayers to sell all (or a portion of) ITCs, PTCs, Section 45Y PTCs, or Section 48E ITCs (as well as certain other tax credits) to another taxpayer under new Section 6418 of the Code.  The election to transfer must be made no later than the due date for the tax return of the year in which the credit is determined (or, for a transfer of the PTC or Section 45Y PTC, for each taxable year during the 10-year period beginning on the date the facility is placed in service).  Once made, the election is irrevocable. 

To properly sell credits, the buyer must pay for the credit in cash, and the buyer is not allowed to deduct the amount paid for such credit or subsequently transfer the credit.  The payment will not be included in the gross income of the seller.  Penalties apply for excessive credit transfers.

The Proposed Direct Payment Rules provide guidance on a number of issues relating to the direct payment of certain tax credits, including additional detail regarding certain eligible entities, rules relating to how the applicable tax credit amount is determined, clarification regarding how certain taxpayers eligible for credits under Section 45Q, 45V or 45X may elect to claim cash payments under Section 6417, reporting requirements, rules related to reasonable cause to avoid the 20% penalty for excessive credit transfers, anti-abuse rules, and other election mechanics.  Among the highlights:

The Proposed Credit Transfer Rules provide guidance on a number of issues relating to tax credit transfers, including which taxpayers may transfer credits, rules relating to recapture of certain tax credits, timing for transfers and claiming transferred credits, reporting requirements, rules related to reasonable cause to avoid the 20% penalty for excessive credit transfers, anti-abuse rules, and other election mechanics.  Among the highlights:

The Registration Rules adopt a pre-filing registration process for eligible entities intending to claim direct cash payments pursuant to Section 6417 of the Code and to sellers engaged in tax credit sales pursuant to Section 6418 of the Code.  In connection with the pre-filing registration process, each taxpayer required to register will be required to provide certain information through an electronic registration process through an IRS portal, including the identity of the applicable taxpayer, all applicable credits with respect to which it intends to claim cash payments or sell, and each applicable credit property that contributed to the determination of such credits.  These pre-filing registration procedures are intended to permit the IRS to prevent duplication, fraud, improper payments, or excessive payments.  In each case, upon completion of the pre-filing registration process, the applicable electing party (either the direct payment claimant under Section 6417 of the Code or the seller of tax credits under Section 6418 of the Code) will be provided with a registration number that it will be required to include on its tax return claiming the direct cash payment or identifying the transferred tax credit, as applicable.  In the case of tax credit transfers under Section 6418 of the Code, the buyer taxpayer will be required to include the applicable registration number in connection with claiming the applicable transferred credit.

Although the guidance is comprehensive, certain issues are not resolved by the guidance that was released yesterday, and Foley will continue to monitor developments relating to tax credit transfers and direct cash payments.

When we look at everything we want from government: better education, universal healthcare, common sense gun laws, etc., we see immediately why all these items are out of our reach; Big Money is interfering with our lawmaking processes.

The most obvious remedy for this is a constitutional amendment that would overturn the 2010 Supreme Court decision “Citizens United,” which provides corporations the right to spend much as they like influencing our elections.  The high court found that the First Amendment’s protect of free speech applied to corporations, and now, here we are as plain U.S. citizens, disenfranchised from our democracy.

The words of the late Ruth Bader Ginsburg speak for the vast majority of American voters.

Twain was a humorist and not an anthropologist, and thus we can accept what he said here with a grin, even though it’s clearly untrue.

Religion was one of humankind’s first attempts to explain natural phenomena, before science came along and gave us another way forward.

The concept of a God in the sky, commanding us to worship and obey Him, in exchange for His love and protection–even after the death most of us fear–made perfect sense at the time, just as it does for many of us today.

This New York Times podcast on the changing perspective on the value of a college education examines the two most powerful forces at work:

1) Personal finances.   Until quite recently, one of the broadest assumptions about parenting in the U.S. was that, almost without exception, children should go to college, primarily because of the “income delta.” I.e., their income stream over the course of their lifetimes has historically been significantly higher than that of their high school diploma-only counterparts.  Now, the rising tuitions and other costs, exacerbated by the student loan debt burden that many graduates carry with them through the bulk of their lives, has largely destroyed this economic model.

2) Politics.  Conservatives find their viewpoints underrepresented vis-à-vis liberals among students, and more importantly, professors. As a result, many modern-day Republican families find the entire college experience objectionable. This position is reinforced by right-wing media, an entity that hadn’t fully taken form and penetrated our society so deeply until the last decade or so.

One thing that never seems to be discussed in conversations like these are the intangibles, issues that are not directly related to finance or politics.  It could be argued that college graduates enjoy richer lives, in a broad sense of that word, and that this should count for plenty.  They are more likely to enjoy reading and museums, to travel outside the U.S., to learning foreign languages, and to take pleasure from intellectual pursuits like astrophysics and philosophy.

We need to consider the factors that affect enjoying their careers. It makes sense that teachers and doctors take a higher level of reward from their careers than auto workers or employees in the retail industries.

Of course, this is a truly subjective matter, and perhaps that’s why it’s avoided by podcasters.  But it’s a shame that we have learned so little from Socrates (“the unexamined life”),  and the words of Confucius, Gandhi, Marcus Aurelius, and the thousands of others who came before us, each of whom sought to teach us the value of learning, wisdom, and the pursuit of virtue.

If we have only one shot at life, shouldn’t it be our best one?

One of the great mysteries in U.S. politics is how the Democrats lost their connection to the working class.  Until very recently, there was a huge stasis in this country in which labor aligned with the Democratic party, and management aligned with the Republicans.

My theory, and I know I’m not alone here, is that:

• Almost all the new wealth that came into the United States over the last 40+ went to the upper 1%, which gutted the middle class, and left more than half the country with virtually no savings, living paycheck to paycheck, and deeply frustrated.

• Educational standards declined sharply over this period of time.

• Republicans, Trump in particular, exploited this combination of ignorance and frustration, blaming the Hollywood elite, the Deep State, Dr. Fauci and other “corrupt” scientists, immigrants, people of color, and liberal “wokeism” for the financial pain that is inflicted on white America’s workers.

Having said all this, it is quite possible that the great labor strikes of the day will be effective at alerting us to the plight of labor.

It’s also true that the GOP has gone too far for even the most poorly educated Americans.  Its leader by a huge margin is Donald Trump, who, by virtue of his status as a traitor to his country, doesn’t stand a prayer in the 2024 election.

In many ways, we’re a pathetic country, the butt of jokes from peoples around the globe.  But even many Trump supporters have a limit, one that was crossed when the former president came within a gnat’s a** of overthrowing the U.S. government.

A couple of points on the meme here:

Nike is worth $146 billion and change.  They’re among the top brands on the planet, and they don’t care what a former Yankees pitcher thinks.

The vast majority of Americans pride themselves on their concern for the well-being of others.  We don’t care what a hateful moron thinks, either.

The long-awaited next phase of renewables-plus-storage is finally approaching the mainstream!

Our market research indicates a massive renewables-plus-storage momentum and a sizeable pipeline ready for some clarity to reach a final investment decision. How can asset owners, IPPs and Funds optimally value their hybrid projects?

Pexapark’s energy storage desk reports for duty! In this guide you will learn:

Download our report, bringing together our in-house expertise and contributions from Fluence, a global market player in energy storage products and services, to delve into the juicy era of co-location!

By Maritina Kanellakopoulou, Senior Insights Analyst & Content Manager, Brian Knowles, Director of Storage & Flexibility and Jo (Xuejiao) Han, Lead Storage Quant

Pexapark and AFRY have formally launched the ‘Daily Valuation Curve’, a new pricing data offering that will give investors and lenders greater certainty over the lifetime value of renewable energy projects.

The result of a partnership between Pexapark and AFRY, confirmed in Q4 2022, the Daily Valuation Curve seamlessly combines Pexapark’s market-based price approach, trusted by 150+ energy companies, and AFRY’s unique fundamental price curves – which have been a long-term reference point for the energy industry for over 20 years.

By providing a consistent valuation framework and distribution of price scenarios for the short and long-term it overcomes a longstanding obstacle to reliable investment and portfolio management decisions, as well as Power Purchase Agreement (PPA) pricing.

The product has been launched at a moment when demand for reliable pricing data to support renewable energy investments is at an all-time high.

Early findings from a market survey polling over 1,255 energy market participants reveal that future prices within the liquid time horizon and fundamental price curves, combined with independent market reports, represent the top three sources of data currently used by renewables investors.

Furthermore, both future prices and fundamental price curves are expected to top the list of new data services procured by renewables investors in 2023 – followed by generation forecasts, real-time data from exchanges and power networks, as well as independent market reports.

Dr. Jan Wierzba, Senior Principal, AFRY Management Consulting, said: “These recent survey findings highlight the importance to investors of combining short-term future prices accounting for current market volatility, with long-term fundamental price curves that track changes in technologies and commodities.

But these two pieces of price information are a bit like water and oil – they do not easily mix.  This is where the unique ‘blending’ methodology developed for the Daily Valuation Curve will bring great benefits for new and existing assets alike.”

Luca Pedretti, COO & Co-Founder, Pexapark, said: “PPA markets have evolved dramatically over the last year. Faced with market volatility and regulatory change, renewables stakeholders are rapidly arming themselves with data, tools and systems they need to evaluate risks, close PPAs, and make confident investment and portfolio management choices.

Innovative products such as the Daily Valuation Curve, we believe, will become a standard data set required for investment decisions that drive forward the energy transition.”

The Daily Valuation Curve is now available through Pexapark’s Price Reference Platform, PexaQuote, and to users of AFRY’s Independent Market Reports.

Pexapark is an award-winning enterprise software and advisory company, specialised in renewable energy. With more than 21,000 MW of renewable PPA transactions supported, Pexapark is the reference for buying, selling and managing renewable energy.

Founded in 2017 with the purpose of accelerating the energy transition towards net zero by creating an efficient market for renewable energy, Pexapark’s PPA reference prices increase transparency across 19 markets and 34 price zones. Our advisory team and software suite enable leading companies to close successful PPA transactions, manage their risk and grow their renewable energy revenues.

Get in touch with tiranth.amarasinghe@pexapark.com for more information.

AFRY Management Consulting works globally to address challenges and opportunities in the energy, bioindustry, infrastructure, industrial and future mobility sectors through forward looking market analysis, strategic advice, operational and digital transformation as well as M&A and transaction services.

You know you want a Corporate PPA and all the perks that come with it. You issue a tender and receive plenty of bids. Do you know how to read the numbers? We created a guide to explain the main drivers behind Corporate PPA pricing in simple terms.

A Corporate PPA is a bi-laterally negotiated contract between an energy seller and a corporate entity looking to buy energy for own consumption. It’s a tailor made arrangement defining the duration, the volume, the price and the risk allocation between the two parties. The tenor of a PPA is usually long-term (≥10 years), but there are also shorter arrangements which are getting more popular.

Corporates can buy either straight from the asset owner (developer) or through a utility/trader which needs to manage its position. Both options can serve the purpose of a corporate PPA.  Some corporates want to have close contact with the asset they are buying from, so for additionality reasons they would prefer to sign a contract with the asset owner. It’s worth noting that often utilities own generation assets as well.

PPAs take a long time to negotiate, although deal-making becomes quicker as the market matures. One of the most strategically important elements to agree upon is the price. The PPA price is not an independent, standalone element of the negotiation but a result of multiple negotiation points.

Pricing a PPA is dependent on some elements:

LCOE of the project – When project owners start establishing the negotiation range of the price they are willing to sell their hard-generated MWh, the very floor they will set is their Levelised Cost of Energy (LCOE) to cover their basic costs and calculate the desired profit accordingly.

LCOE is not just the project owner’s consideration. Many buyers who wish to enable new projects to get financed, built and come online (additionality) want to make sure that the PPA price they are offering achieves this goal. LCOE costs coming down over the years is a primary driver of more buyers having the ability to agree on competitive prices.

In the past, LCOE costs were significantly higher and green energy would come with a premium. Even though renewables achieved a steep decline in their costs, LCOE levels change depending on a number of factors.

For example:

Even though corporates signing a PPA with utilities sometimes don’t have a link to a specific project (except if the utility owns the project), LCOE is already incorporated in the utility’s price for the energy from the renewable project.

Corporates starting a negotiation for a PPA backing a new project need to ask as much as possible about how LCOE costs are evolving. Costs often change, resulting in requests from the seller to re-negotiate the initially offered PPA price.

Market-based fair value of the energy – Electricity is a particularly volatile commodity. Prices change based on market circumstances, and electricity’s fair value changes at each point in time. For example, today’s market value of electricity can be seen on the spot markets.

But PPAs are long-term contracts, so the parties need to review how much buyers pay today for electricity delivered in the future. One of the main tools to assess the long-term market value of electricity is futures and forward markets; the main elements of what is commonly referred to as the forward curve.

Daily evolution of PEXA Euro Composite, December 2018- October 2022

Source: PexaQuote

The forward curve is a core element of Pexapark’s benchmark PPA prices model, which is back-tested with market evidence of transacted deals pricing. Our signature PEXA Euro Composite illustrates the average PPA prices across all European markets, for all technologies, for a 10-year Pay-as-Produced (PAP) PPA starting one year ahead. Although the Index does not represent benchmark prices, it does illustrate a trend.

As pricing information for futures transactions is obtained daily from exchanges, benchmark PPA prices indicating the fair value of each PPA product are updated accordingly.

Electricity is the most volatile commodity. Day-to-day percentage price changes have reached up to 230%. However, not all periods are the same – and this is where market circumstances come into play. Realised volatility is significantly higher in a turmoil period than in a relatively stable period.

Electricity, and therefore energy, is a global game. Innumerous actors are impacting pricing on a daily basis. Therefore, the timing of when buyers and sellers sign the agreed PPA price is important.

Risk allocation and discounts – A PPA is a game of risk allocation. Every risk has a price, and depending on who’s assuming it, the PPA price evolves accordingly.

For example, the fair market value of a PPA changes depending on the volume structure.

In a Pay-as-Produced (PAP) PPA, the buyer will offtake any MWh produced at any time of the day. This means that profile risk sits with the buyer. The corporate will need to buy energy from the market during the hours that the plant is not producing.

In an Annual Baseload PPA (BLA), the producer has to deliver a determined amount of energy every hour of the year. This means that profile is mostly with the seller. Because if the plant is not producing the required amount of energy, they will have to buy from the spot markets to honour the agreement with the buyer.

Finland onshore wind 10-year PPA, PAP and BLA pricing comparison

Source: PexaQuote Note: Values hidden to protect customer value

Baseload PPAs come with a price premium because of the seller’s additional risks. Similarly, PAP is a cheaper option for the buyer, because of the profile discount applied on the buy side.

Profile risk is only one of the major risk components, and based on readily available tools such as PexaQuote can be calculated in seconds. There are major risk components such as price risk, volume risk and capture risk that also need to be reflected in the price – and this is where the negotiation game begins. The secret sauce is the ability to fairly quantify the ‘cost’ of each risk.

For example, when a corporate launches a tender and receives bids from various sellers, these will typically look fairly different. That’s because they carry different risks, and are also priced based on the seller’s appetite. A corporate needs to be in a position to learn to read the numbers between the lines.

Tenor of the PPA – To a certain extent, the length of a PPA reflects the price risk. How much does a corporate ‘charge’ the uncertainty of agreeing on a long-term fixed price? Typically, the longer the tenor, the lower the price because of the price risk discounts applied.

The tenor of a PPA is an increasing concern amid market turmoil periods, where uncertainty is high. For example, a high-pricing environment in the spot markets also results in increases in the forward curve, ‘transferring’ the potentially temporary high prices to the long term. In such occasions, some corporates may pay a higher price for a shorter-term PPA, in exchange of the limited price risk appetite they demonstrate.

German PAP solar PPA, 10-year and 5-year tenor comparison

Source: PexaQuote Note: Values hidden to protect customer value

Most corporate PPAs are fixed-price, but this doesn’t mean there are not diverse configurations. Ideally, buyers and sellers want cash flow certainty, so fixed-price serves both parties. In fixed pricing, both parties take pricing risk. The seller agrees on a price no matter whether prices could increase in the future, and the buyer takes the risk of prices decreasing over the tenor of the PPA.

Other pricing structures include configurations that have a bigger linkage to the movement of prices. It could be a floating price arrangement, where the PPA price mirrors movements in the spot markets; a floor price where the seller sets a minimum price no matter how much prices fall; or a collar price with both a floor and a ceiling.

No, there shouldn’t be. The only time that attention needs to be paid on the price is when the point of consumption is different to the point of production. This can happen when a country has different pricing zones or cross-border PPAs. You can find out more about the topic in our dedicated guide on cross-border PPAs.

You can discuss more on corporate PPAs with our in-house experts Alex Fels, Senior PPA Origination Manager, and Jorge Seabra, PPA Originator! Feel free to reach out to hello@pexapark.com for a coffee!

Nobel-prize economist Harry Markowitz argued that diversification is the only free lunch in investing, which was our inspiration behind the title of this report.

But what did he mean by this? It’s a reference to a good diversification strategy’s primary benefit: the ability to increase return on investment without increasing your risks!

In this guide, you will learn:

Our guide, curated  particularly to address the needs of Independent Power Producers (IPPs) and clean energy funds, dives into the details of how to quantify your diversification benefits, which could mean saving millions in unnecessary hedges. Better from simply a free lunch, right?

A well diversified portfolio can lead to numerous benefits, and the renewables industry appears to know that, in theory. What is missing though, is the ability to discover the hidden value of diversification through developing a portfolio view.

Download our guide, and enjoy the deep dive!

By David Willemsen, Head of Risk Advisory, Cédric Piaget, Senior Risk Expert &  Maritina Kanellakopoulou, Insights Analyst

Many renewable energy players are new to the concept of an ETRM. In this article we will provide a few quick answers to the most frequently asked questions around the topic, some of which may surprise you!

Energy trading risk management (ETRM) is an enterprise software solution that enables the management of energy commodities’ physical and financial trading. You may have heard of CTRM as well. The difference with Commodity Trading and Risk Management (CTRM) software is that the latter includes all kinds of commodities, not limited to energy-related ones. For example, metals, agriculture and ‘softs’ such as cotton. Therefore, the differences lies in the scope of traded commodities.

ETRM systems have been traditionally used by large trading houses and utilities managing a plethora of energy commodities, primarily natural gas, LNG, oil, crude oil, refined products and electricity. They have been so popular in that sector because they facilitate hundreds of transactions and deals daily, which is in line with the primary business model of trading houses, for example.

This is due to their ability to link the different steps of the trading cycle, connecting business processes conducted across the front, middle and back offices, which has proven very useful for traders and utilities.

Traders & Utilities Typical Set-Up

Front office

Execution of physical or financial contracts

Middle office

Risk Management

Back office

Trade settlement

ETRM consultants perform two functions. First, they help identify which ETRM solution best fits their client’s needs. Typically, a consultant helps the client launch a tender with what services they need and manages the request for proposals (RfP). Not all ETRM solutions offer the same functionality. The elements included in the ‘packaging’ are subject to many factors, such as the size of a portfolio, the variety of commodities included in the portfolio, and the level of sophistication the client needs.

Second, they can help with the implementation of the solution. ETRM systems are not out-of-the-box solutions, and need an integration consultant whose’ services can cost substantial multiples of the software solution itself.

The implementation phase will also require substantial internal resources. Key people need to be heavily involved, and the process will require extensive time investment on their side.

There is no ETRM system exclusively suited for portfolios only comprising renewable energy assets. The concept of traditional ETRM systems was developed and advanced considering the needs of trading housing and utilities. These players have been managing an entirely different portfolio, out of which renewables are only a share, and have significantly different needs.

Added complexity derives from the fact that many ETRMs are based on systems developed to manage equities, bonds and currency positions which have very different risk characteristics compared to energy. Thus, every time a renewables business evolves and requirements change, there’s the risk of starting a new development cycle almost from scratch, with substantial additional cost.

That being said, there is an intense conversation across the ETRM and energy sales world about the need for an enterprise software tailored to renewables. For renewables players that do not need to manage the physical dispatch of power or navigate the time-sensitive intraday trading technicalities (which is performed by other systems, but position management comes from the ETRM), traditional ETRMs provide many features surplus to their requirements. Therefore, there’s a significant risk of paying excessively for features that would never be required by a pure renewables portfolio owner. This is the number one deal breaker.

More importantly, pure-play Independent Power Producers (IPPs) and renewable funds have particular requirements unique to their operating models, which cannot be met by traditional ETRM systems alone.

For example, it is practically impossible to have a growth strategy without the ability to quantify if a new project acquisition will be supporting the organisation’s revenue goals and if the new project will adhere to the set risk limits. This would need advanced quantitative metrics that traditional ETRMs lack.

In addition, to construct high-performing portfolios and take full advantage of diversification benefits, investors need to adopt a portfolio view and understand how the unique risks of renewables correlate – as in, measure the degree to which one risk moves with respect to another. Correlation benefits could provide natural risk hedging and increase secure revenues without increasing the risks. But only if an investor is able to identify the hidden value their portfolio has.

Likewise, renewable players need access to targeted pricing data and deal valuation tools to execute the more secure and revenue-driving PPAs. And when they do, they need to be able to run ‘What If’ scenarios to see how a new deal will impact their portfolio view and revenues.

Very importantly, as renewable investors are new to the realities of the merchant markets, they often require end-to-end guidance on building rock solid risk management processes. Similarly to how ETRM consultants offer guidance with ETRM integration processes, expert renewable risk managers can help businesses in setting up an energy risk policy, establishing best practice procedures to manage the unpredictability and volatility of electricity markets.

Pexapark’s Operating System for Renewables has been designed to specifically support the unique challenges of managing 100% renewables portfolios. Our enterprise-wide offering meets all the crucial day-to-day needs of renewables operators: from trading decisions, position keeping, portfolio optimisation, risk management and deal execution through to financial reporting and revenue management. It is an end-to-end solution for market players with ambitious growth strategies.

It is particularly suitable for funds and asset managers turning into Independent Power Producers (IPPs) that want to employ utility grade risk management due to their increasing exposure to market prices and associated risks.

Step 1 – Identify Risks

As a first step, you need to identify the risk drivers of your portfolio. Every portfolio holds unique and evolving risks based on: technology, location, asset performance, marketing agreements, and sales contracts. Don’t forget what risk really means: drivers that will impact the uncertainty of your revenue.

Step 2 – Develop Strategy

The main goal of a strategy is to balance risks and desired revenue targets. A comprehensive strategy needs to incorporate some key elements:

Risk management needs to be systematically defined. From setting the floor and the ceiling of the hedging ratio, to reviewing the horizon of how far forward you want to optimise. In this step, it’s very important to set target levels that trigger a review. For example, market conditions,  production levels or breached risk limits. And then, you lay out hedging instruments that are approved and well understood to choose from.

Step 3 – Quantify Solutions

Once you know what hedging options are suited for your target results, the next step would be to conduct an optimisation analysis and test different expected outcomes to evaluate hedging options. You’d need to use the right quantitative tools to assess the best deal and the optimal PPA volume structure and hedging ratio. This way your selection will be backed by data-driven analysis to know that at that time, you genuinely opted for the best possible solution. In addition, you’d need to pursue a ‘What if analysis’ to stress-test the impact of the deal in your portfolio.

Step 4 – Execute Hedges

Once a decision is made on the best hedging instrument, you need to employ an optimal and cost-effective execution strategy. For example, if you have opted for a 10-year pay-as-produced PPA, you must sign the best price possible, and ensure that the contract terms and conditions do not affect the price. To this end, access to first-class PPA pricing data for the volume structure and tenor of choice and country insights will give you significant power in the negotiation room.

The same PPA pricing granularity applies to short-term hedges which can be significantly higher in value depending on the market conditions. For example, an EEG revenue optimisation PPA in Germany. Or, a short-term PPA to underpin the financing of a new plant instead of a long-term one. Yes, we have seen this happening already.  

Step 5 – Actively Manage

Revenues and risks need to be actively monitored. Frequent reality checks of both short-term and long-term positions will ensure that revenue targets will be met. How? Through access to readily available data to trigger correction actions when limits are breached.

The Pexa OS provide enterprise software solutions to manage portfolio risk and revenue, guidance on risk management, quantitative analysis to compare hedging options, and data transparency to get the right price. Our solution is used by leading pure-play renewables IPPSs, funds and asset managers across Europe such as Encavis, Ardian and CEE Group.

Depending on individual needs, the PexaOS can be used as a substitute to ETRM, or in a complementary manner through integration with an ETRM software.

If you’d like to learn more about the PexaOS, reach out to Kashif Javaid at kashif.javaid@pexapark.com to book your chat. Kash has more than 10 years’ experience in traditional ETRM systems, as well as enterprise solutions exclusively suited for renewables. He will be happy to answer more of your questions!

P.S He also thoroughly enjoys sharing tips for biking adventures in the UK, so feel free to surprise him with your enquiries!

We were very keen to put on a solar battery to backup our solar panels and it was a way of obviously using solar electricity into the nighttime to contribute to the greater picture, to even out the peaks and troughs because there’s a lot of people taking on solar panels. But I do like the idea of generating power close to the source and using it where we are and using the battery to sustain things through the evening for our local use and for moving to the whole grid.

We’ve put on high quality panels with this latest installation, and they’ve been very good. Our first set of panels that we installed around 2008 wasn’t nearly as efficient as the new ones so we’ve moved those to a less good part of the roof and put our best panels in the best sunspot. So many people say that panels don’t work when the sun’s not up, but we see that on a grey day, even on a wet day, we are actually producing quite a lot of power and it’s really impressive and we’re really thrilled.

I do like the way we can now also check the output of our panels through the apps, which we weren’t able to do with the panels we had in the beginning so we can see they actually perform very well.

I particularly wanted to get a local company (E-Smart Solar) that we knew would have to have a good reputation locally. It was good to have somebody come to the house and do a quotation, look at your situation. The team from E-Smart Solar were very consultative. They asked what we wanted every step of the way, they did very neat work and worked extremely hard and our little cottage looks very good. I also liked the fact that the battery and solar installation is quite visible so I can share it with friends and visitors and say, look, this actually works.

Planning on going solar but you’re not sure where to start? E-Smart can help you with that. Contact us today for more information.

Meet our dear customer, Fiona. Read her story of what her environmental reasons are for buying a high quality solar power system.

I’m Fiona, we’re in Katoomba in the Blue Mountains. John and I are both very keen and passionate birdwatchers, and we’re conservationists and I see alternative energy as a wider umbrella that we all fit together to contribute back to the planet.

I love nature. I want things to continue to be beautiful and I think we’re part of a bigger picture and we all need to contribute to that but we need to make this planet last longer and be as beautiful as it always has been.

We’ve been very happy to become more self-sustainable, environmental and I thought doing solar energy was our first step. It was very achievable and I do like that domestic way of making a contribution to the larger picture.

Solar energy is a big part and something we have really concentrated on. We really wanted to be early adopters on taking on the solar revolution so that we could personally make a contribution that we felt we could do and we’ve actually found it quite easy to do, not as intimidating or as difficult as you’d think. We’re now completely self-sufficient without electric power. I think we’ve paid about 18 cents in power since we went solar.

I would recommend a high quality solar. I’ve always been very keen on buying good quality products and E-Smart Solar was able to provide that. I want things to last and don’t want things to go to the tip all the time, it’s a lot of waste. If you can buy good quality stuff in the beginning, make it go for a long time. It’s good to have a local company like E-Smart Solar that will come and give you back up if there are any problems, tweak things a little bit if they need to be and if you want to expand in the future, which we plan to do.

Help the environment today by going solar. Talk to us.

We are proud that E-Smart Solar is the first solar company in NSW to be Climate Active certified. Climate Active certification is an important step in our journey to being a more sustainable and environmentally conscious organisation.

We are located at the base of the World Heritage listed Blue Mountains, so we understand the importance of our environmental impact as a business. We have chose to be carbon neutral, hoping this heritage site can be enjoyed, as it is today, for generations to come.

The Climate Active brand is a simple yet powerful way for companies to demonstrate to customers and stakeholders that they have a credible and transparent claim of carbon neutrality. It is the only government accredited carbon neutral certification scheme in Australia.

The Climate Active brand represents Australia’s collective effort to calculate, reduce, and offset carbon emissions to lessen our negative impact on the environment. The Climate Active certification is awarded to businesses and organisations that have credibly reached a state of achieving net zero emissions, otherwise known as carbon neutrality.

The best thing homeowners can do to support us is to take the time to understand the solar system they are buying. Additionally, customers can also support us through understanding that the environmental benefits of solar power are the main reason we do what we do as well as helping homeowners and business owners to reduce their carbon footprint – not just their power bills.

Speak to our expert solar team about how you can reduce your carbon footprint.

We first started thinking about solar to be more environmental, and we’re quite environmentally aware here at home and we’d thought it’d be a great benefit better for us. We decided that it’s the right thing to do. I think it’s very important to try to be as environmental as possible, renewable energy is the way to go.

Fossil fuels are obviously causing damage to the environment so we’ve got to think about our future energy usage. It’s our environment, it’s the future. We’ve got to think about what’s going to happen, it’s just so important. We’ve got to think about climate change, biodiversity, the environment, and just got to look after the world and start somewhere.

Renewable energy is growing and we’ve got to use it. Every little step that people can do is fantastic. Solar, solar panels, solar energy, is a small thing we can do. It’s getting less expensive all the time and it’s worth giving a go if we can. We’re actually exporting power to the grid. At the moment, we’re getting 21 cents a kilowatt which is making it a little bit more financially rewarding as well too. We’re using energy from the sun to power our house and we’re also exporting power to the grid. It’s a win-win situation.

We initially did have a system put in several years ago. It was a small system of 1.5 kilowatts, but it was a start for us. It cost about $3,000 for the system at that time. The new panels are probably twice the power of the old panels and only marginally 50% bigger, giving us a greater output from the same sized space we’ve got on the house. They’re twice the efficient and we’re getting more power out of the sun. We had the old panels sided to a less efficient part of the house -the roof and so we got the new panels on the more efficient part of the roof, which was fantastic. There was a combination of the old and the new and it’s working tremendously.

We decided to spend more on our panels this time because we wanted something that we could trust, something that was reliable and we decided that we just wanted quality solar panels. That, as well as the brand name which also gives the best performance. We wanted to have quality products.

Since we’ve had the new panels and a power wall installed, we’ve been 100% self-sufficient energy-wise. It’s all worked tremendously, it’s been seamless. If the power goes out in the street, we don’t even notice it at home. It just completely kicks in.

Earlier this year, in a stride toward a more sustainable future, the U.S. Environmental Protection Agency (EPA) proposed to reduce carbon pollution from coal and gas-powered power plants. Framed within section 111 of the Clean Air Act, this initiative seeks to curtail the carbon footprint that our nation’s energy sector has long created, casting a long shadow over our country’s public health and environmental safety. Under the purview of this proposal, coal power plants and some gas plants—responsible for about a quarter of the nation’s carbon emissions–will need to scale back their output of carbon pollutants. This is significant because carbon pollution from the vast majority of power plants has essentially never been regulated by the federal government despite the large share of emissions from power plants.

The EPA proposal is not due to be final until next year, but this summer, the EPA held a public comment period on the proposed rules. Public comments filed during this period included resounding support for the regulations from across the Southeast region. SACE and Clean Energy Generation members made a difference by submitting over 850 comments to the EPA supporting the proposed rules and a greener future.

We’ve compiled some of the comments from the heart of the Southeast—a chorus of voices, each echoing the urgent call for stricter carbon regulations for power plants. Commenters represent communities spanning the region that bear the brunt of pollutants emitted by these power plants and grapple with the far-reaching consequences. These voices resonate not merely as comments in an official procedure, but as personal testimonies that paint a vivid picture of the pressing need to rein in emissions. These are just a few of the growing number of individuals who are willing to stand up and take collective action as the Clean Energy Generation, demanding policies that will protect our health, our communities, and our planet.

Here’s what they said they want:

“This is the right action to take for future generations. I worry about the mess we are leaving our grandchildren.” – Kathleen Gates, Florida. 

“Please support this EPA proposed plan to help our children and grandchildren deal with this obvious climate crisis.” – Jim Carillon, Fairview, NC.

“As a physician, a mother, and a grandmother, I feel we must stop carbon pollution as soon as possible! This [carbon rule] is critical for our citizens and planet’s health.” – Katherine Sutherland, Winter Haven, Florida. (Read why Kathie also joined the Clean Energy Generation here.) 

“Please help make the U.S. a leader in fighting climate change by finalizing the strongest version of the new rules limiting carbon dioxide emissions from power plants. We are running out of time. Half measures are not enough.” – Nancy Power, Rockingham, North Carolina.

“Meaningful regulation of carbon emissions is past due and critical for the survival of our species. Thank you, President Biden, for your leadership on this issue in the face of calculated misinformation.”  – Holly Schwartz, Florida.

“I support strong climate pollution controls on all power plants, whether new or old. I am a retired federal land manager and conservation planner who worked on climate change adaptation and mitigation policy for the southern US. I know how much easier and healthier life would be if the governmental authorities had stepped up to curb climate pollution instead of the people fighting to be safe and healthy. Please take this opportunity to continue to take our country in the right direction and help humanity and our planet. Thank you.” Mary Long, Tennessee.

“Meaningful action is needed to reduce power plant pollution, and EPA is best positioned to act. We have some of Tennessee’s worst fossil fuel plants, and converting to gas plants is not a good long-term solution. Regulation should encourage clean energy production and hold polluters accountable.” – Quentin Humberd, Cunningham, Tennessee.

“Please help transition the United States’ energy generation to renewables! Remove the roadblocks for solar and wind permitting, please! We must think about future generations.” – Frank Galloway, Florida.

“Clean electrical generation technology is mature and cost-competitive. Utilities can transition if Congress expedites permitting reform for wind, solar, and long-distance transmission.” Mark Gould, Charleston, South Carolina.

 “I live in an area where electric providers are trying to replace coal plants with fossil gas. While I welcome the shutdown of the coal plants, my community has many concerns about methane leaks, particularly groundwater contamination. I strongly feel that our communities will be better served and healthier if we stop ALL fossil fuel expansion and work toward a just transition to an electric grid powered by clean, renewable energy.” – Laura Rastl, Clarksville, Tennessee.

The support from residents across the Southeast echoes a shared aspiration for cleaner air, healthier communities, and a planet safeguarded for future generations. Their voices speak to the urgency of action and reflect a chorus of resilience and determination to champion the cause of a greener energy landscape.

Through the lens of these residents, we witness the profound impact power plant emissions have had and continue to have on our region’s communities, environment, and public health. These perspectives underscore the need for stricter regulations prioritizing the transition to clean energy, which will help us realize a future unburdened by the shackles of carbon pollution.

The EPA’s proposal serves as a sign of progress that shows a path toward a more sustainable energy future, but it’s far from over. While the public comment period is closed, some utilities across our region are pushing back against the proposed rules. We need to keep up the momentum and let the EPA and our utilities know that we are not letting up on our support for these crucial rules that will make our communities and our planet healthier.

SACE is working with individuals to write letters to editors supporting strong standards to cut carbon pollution. Want to help? Reach out to cary@cleanenergy.org to get started!

In addition, we urge EPA to work to ensure environmental justice is delivered through these rules and that the needs of frontline communities are met, considering the environmental impacts of the rules. Also, EPA should strengthen its proposal so that it covers more existing gas plants – as is, the proposed level of coverage would only address 30% of CO2 emissions from existing gas-fired power plants, leaving the vast majority essentially unregulated.

Impassioned comments from our neighbors, like those above, points out the responsibility to act that rests with government entities and policy makers – but we should never forget that responsibility also lies with every one of us who cares about the legacy we leave for the generations that follow to hold those in power accountable. By joining this collective voice, we can build momentum as the Clean Energy Generation to shape a cleaner, healthier, and more resilient world. Join us as we support their call for meaningful change, support EPA’s proposal, and work together to usher in an era where carbon emissions no longer threaten our health and safety. 

The post Southeast Residents Rally Behind Stricter Carbon Regulations for Power Plants appeared first on SACE | Southern Alliance for Clean Energy.

Drive through the major population centers across the Southeast United States today, and you’ll see an increasing number of both electric vehicles (EVs) on the roads and charging stations scattered in parking lots. You might see kids being picked up by an electric school bus, or riders hopping on an electric transit bus to get across the city. Drive through the region’s rural landscapes, and the number of EVs decreases, while massive EV and battery manufacturing sites rise out of fields and forests.

The Southeast’s EV market is complex and paradoxical. Our region has captured 40% of the nation’s EV assembly, EV parts, EV charging infrastructure, battery manufacturing, and battery recycling investments, and 35% of anticipated manufacturing jobs (totaling over 65,000). The Southeast has emerged as an EV and battery manufacturing powerhouse. And, though lagging behind national averages, light-duty passenger EV sales grew 50% over the past twelve months, and charging station deployment grew 66%.

Yet, the policy environment remains hostile in many states. For example, Alabama and Georgia have some of the nation’s highest EV road-use taxes; Alabama, Georgia, North Carolina, and South Carolina limit or ban EV manufacturers from selling or servicing their vehicles directly to consumers, including vehicles manufactured in those states; Georgia legislators imposed a new tax on the sale of electricity at EV charging stations; and Florida’s Governor vetoed a near-unanimous bipartisan bill that would have saved taxpayers money by prioritizing EVs for state and local government fleets.

In the  “Transportation Electrification in the Southeast” fourth annual report, the Southern Alliance for Clean Energy and Atlas Public Policy highlight the data behind these complex market dynamics to provide context, showcase trends, and spotlight actions accelerating or slowing down EV adoption.

Read the Report Watch the Webinar View State Pages

The Southeast has emerged as a leading hub for EV manufacturing and jobs, with anticipated jobs totaling 65,242. Georgia leads the nation in anticipated EV manufacturing jobs, and the Southeast is home to four of the top eight states in the country—Georgia, Tennessee, North Carolina, and South Carolina.

Source: “Transportation Electrification in the Southeast”; page 10; published September 2023.

Anticipated EV manufacturing jobs in the Southeast grew 56% over the past 12 months, as manufacturing investments grew 97%. This 12-month growth was driven by Hyundai in Georgia, which committed $4.3 billion in battery manufacturing investments in partnership with LG Energy Solutions, and Toyota in North Carolina, which expanded its committed battery manufacturing investments to $5.9 billion. With the federal Inflation Reduction Act (IRA) injecting billions of dollars into America’s clean energy economy, the Southeast is well-positioned for continued manufacturing and job growth.

One of the best ways to track EV market momentum across states is to look at the market share of light-duty passenger EVs. Market share is the percentage EVs make up of all new car sales. The trend lines for all Southeast states are upward, though at different trajectories, and at the same time every state in our region continues to lag behind the national average. Georgia, Florida, and North Carolina lead the region with market shares in Q2 above 7%, double where these states were two years ago. If that doubling every two years continues, those states would see over 50% EV market share by 2030.

This figure depicts EV sales as a percentage of new light-duty vehicle sales from 2019 to the end of June 2023. EV includes both BEV and PHEV sales. The jump in new EV sales in Tennessee in Q1 of 2023 is an outlier for unknown reasons. Source: “Transportation Electrification in the Southeast”; page 8; published September 2023.

Market share is influenced by demographics (including the concentration of early adopter consumers), supportive or undermining public policies, and the presence of electric utility programs such as charging station rebates and discounted electricity rates. Market share is also a self-fulfilling prophecy; the more EVs on the road and in neighbors’ driveways, the more consumers are exposed to the technology and likely to consider buying one. Plus, for EV charging station companies, where the EVs are is where the business opportunity lies, and therefore where infrastructure investments are made, further supporting EV ownership in those areas.

Looking at the raw new EV sales numbers, the Southeast continues to reach new highs. Cumulative new EV sales in the Southeast grew 50% from July 2022 to June 2023, from 312,316 vehicles to 469,602 vehicles. Though Telsa still dominates the market, an increasing percentage of new EV sales are coming from legacy automakers.

This figure depicts new light-duty EV sales over time in the Southeast through the end of June 2023. The EV share line depicts the share of EV sales compared to all new light-duty vehicle sales. Source: “Transportation Electrification in the Southeast”; page 9; published September 2023.

In the past 12 months, the Southeast saw continued progress in deploying EV chargers. Regional DC Fast Charger (DCFC) ports now total 4,401 after a 60% increase year over year, and the region now boasts 15,036 public Level 2 charging ports, a 69% increase year over year. Though all Southeast states lag behind average national charging station deployment numbers, Georgia, Florida, North Carolina, and South Carolina are all trending in line with the national growth curve.

This DCFC deployment momentum is vital as states prepare to release nearly $680 million in National EV Infrastructure (NEVI) Program funds to scale DCFC every 50 miles along the region’s primary travel corridors. NEVI comes out of the Bipartisan Infrastructure Bill (BIL) and represents the most significant public investment in EV charging ever made. Current momentum indicates increased readiness of EV infrastructure manufacturers and installers to meet the demand NEVI will stimulate.

This figure depicts the steep rise in cumulative DCFC ports per 1,000 people installed across states in the Southeast from 2010 through June 2023 when compared with the national average. The figure only accounts for stations still active today, by installation date. Stations that are no longer active are not displayed. Source: “Transportation Electrification in the Southeast”; page 15; published September 2023.

Utilities represent an essential source of funding for the EV transition through direct infrastructure deployment, charger rebates, charging-as-a-service programs, make-ready infrastructure investments, supportive EV electricity rates, and funding to support vehicles such as electric school buses. The investor-owned utilities in our region significantly trail their national peers in dollars per customer invested in supporting the EV transition: the national average is $75 invested in transportation electrification per customer, whereas the Southeastern utilities range from $41 to just $3 per customer. Our region, which makes up 18% of the nation’s population, represents just 7% of all approved utility investments nationally.

“Investment” refers to funding in transportation electrification from investor-owned utilities approved by state commissions. “Investment per Customer” refers to the total utility investment divided by the number of customers from all sectors. For the “U.S. Total” figure, the total investment is divided by the number of customers served by utilities that have announced investments in transportation electrification. Duke Energy customer data in North and South Carolina was drawn from a Duke Energy fact sheet as of April 1, 2023 (Duke Energy, 2023). Alabama Power is not included here as the company’s EV programs were not submitted to a public utility commission. Source: “Transportation Electrification in the Southeast”; page 15; published September 2023.

“Drilling down into equity, the Southeast has seen low levels of identified equity-focused investments in transportation electrification from investor-owned utilities. From July 1, 2022, through June 2023, around $6 million in the region was approved for underserved communities, or 10% of all approved investments within the past 12 months. For reference, over the same period, 54% of utility transportation electrification filings were classified as equity investments nationally.” 

Southeast lawmakers have allocated very few state dollars to support transportation electrification outside incentive packages to entice businesses to locate and expand. However, states have accessed significant federal funding and leveraged VW Settlement funds to enable EV infrastructure deployment and electric school and transit bus purchases. Over the past 12 months, the region has accessed federal funds totaling $234 million for electric transit buses, $172 million for electric school buses, and $3 million in EV-related research and development grants, and awarded $169 million in VW Settlement funds. The total amount of federal transportation electrification funding allocated to date is $741 million, which could be dwarfed over the coming years if the region is successful at drawing down the massive amount of funding being made available through a growing list of BIL and Inflation Reduction Act (IRA) programs.

This table depicts public funding awarded or made available in the Southeast. In this summary, state funding includes VW Settlement funds dispersed by the state. Public funding excludes utility funding. Federal funding is reported separately and excludes loans. Source: “Transportation Electrification in the Southeast”; page 20; published September 2023.

Electric vehicle sales are on the rise, expanding significantly across the Southeast. The region continues to lead nationally in new battery production and EV manufacturing investments, with many new billion-dollar announcements throughout the Carolinas, Georgia, and Tennessee. Meanwhile, the first round of NEVI and Community Fueling Infrastructure (CFI) grant funding will inject hundreds of millions of dollars for EV charging infrastructure buildout in the Southeast. Other federal funding from BIL and IRA will continue to drive private sector investments in EV, battery, and supply chain manufacturing and jobs, provide vehicle tax credits to support consumer and fleet EV purchases, increase charging station deployments, and more.  But while the market and funding opportunities have expanded, supportive policies have yet to keep pace.

The speed at which electric car, truck, and bus adoption will grow in the Southeast and the equitable access to the benefits of the growth depends largely on how the work of policymakers at the state and local level complements and enhances investments from industry and the federal government. More action now will put Southeast residents and fleet operators in the driver’s seat on their way to improved public health, a cleaner environment, and a growing economy.

The Southern Alliance for Clean Energy’s Electrify the South program leverages research, advocacy, and outreach to accelerate the equitable transition to electric transportation across the Southeast. Visit ElectrifytheSouth.org to learn more and connect with us. 

The post Report Shows in the Southeast, Electric Vehicles are Economic Development Engines appeared first on SACE | Southern Alliance for Clean Energy.

On July 31, SACE’s Executive Director Dr. Stephen A. Smith appeared on the podcast “More Living with Jim Brogan” to discuss how a healthy environment allows all of us to live healthier, happier lives, and how investing in policies and tools that bolster clean energy and help us move away from polluting fossil fuels can help us get there. 

Each week, Brogan and his guests discuss news and issues like lifestyle, health, financial planning, and more. The topic of clean energy is connected to each of these issues and has recently come to dominate public conversation, and for good reason: the global renewable energy market valued just under $900 billion in 2020 and is expected to reach $2 trillion by 2030. 

Brogan and Dr. Smith discussed the driving force behind climate disruption, the pros and cons of solar energy, the trajectory of the electric vehicle market, and what incentives from utilities and the federal government are in place to help accelerate the clean energy transition – plus, how SACE’s mission encompasses all of this. 

Listen below for Dr. Smith’s quick recap on the driving force behind climate disruption.

Not only can we rely on the sun coming up in the east and setting in the west everyday, but the price point of solar installation has decreased significantly in recent years. That’s why we see solar catapulting in deployment across the world today. 

Dr. Smith discusses utility companies’ financial incentives to offset the price of installing solar, as well as technologies such as battery storage that can also save customers money. 

Dr. Stephen A. Smith, Executive Director of Southern Alliance for Clean Energy

Dr. Smith‘s personal story involves his own rooftop solar panels he installed on his family’s Knoxville, Tennessee home since 2009, the evolution of the relationship between his utility TVA and homeowners with solar panels, and the viability of solar as an investment for customers in the TVA region. 

“All the big money is tracking in the direction of electrification,” says Dr. Smith. 

Despite this, range anxiety – fear of the inability to find a charging station – remains a primary concern among potential EV buyers, but the deployment of charging stations is growing dramatically every year, and the ability to charge at your own home if you are able makes it that much easier. 

Another concern, especially amid this summer’s heat waves, is the pressure that home EV charging has on the region’s already stressed electricity grid. However, Dr. Smith says, think of the grid as having peaks and valleys: residential power usage ‘peaks’ at a certain time of day – say, when we’re doing laundry and cooking dinner around 5 p.m. – and then experiences demand ‘valleys’ at other times, like when we are asleep at night. By encouraging people to charge their EVs at valley times, like plugging in your car to charge while you sleep, we can allow the grid to run more efficiently. 

The Inflation Reduction Act (IRA), passed this time last year, is the most substantial federal investment in clean energy that many of us have been waiting on for a long time. Another federal initiative called the Bipartisan Infrastructure Law (BIL) also has the power to accelerate our transition to clean energy. While these national policies alone will not be enough to combat our dependence on nonrenewables, they propel us significantly down the path. They also allow us to bring technologies and manufacturing back to the United States, such as moving battery production here from countries like China, because manufacturers cannot receive the tax incentives from the IRA unless their production happens in the states. 

All of this means jobs returning to the states. As we transition to clean energy, a wealth of jobs is materializing especially in manufacturing. Here in the Southeast, we’re capturing a bulk of those as battery manufacturers, electric vehicle factories, and more decide to call the Southeast home. 

The Southeast consistently lags behind other regions and the nation as a whole on utility energy efficiency performance investments in renewable energy, and utilities like TVA are largely to blame, for prioritizing low rates on electricity instead of bolstering renewable energy. Despite TVA’s low ‘rates’, our electricity bills are high because of inordinately high consumption patterns here in Tennessee. 

An important next step is educating consumers and homeowners on ways to be efficient with their energy consumption and what programs are available to help them do that. Dr. Smith says that is where SACE steps in, alongside other members of today’s Clean Energy Generation working against climate disruption. Together, we have the power to encourage others to take advantage of the availability of the clean and renewable energy that exists all around us. 

There are many ways all of us can start taking action today as part of the Clean Energy Generation, whether it’s learning more about clean energy efforts in your town, taking steps to make your home more energy efficient, or getting out and talking to your community about what a clean energy future looks like for you. There’s no wrong way to get involved, and we all have what it takes to make a difference – especially when we join together as one Clean Energy Generation. 

Join the Clean Energy Generation

Take Action With the Clean Energy Generation

Thank you to Jim Brogan for hosting SACE’s Executive Director Stephen A. Smith on his podcast “More Living with Jim Brogan,” which you can find here.  

#CleanEnergyGeneration

The post The Clean Energy Transition: SACE’s Executive Director Talks Opportunities and Challenges appeared first on SACE | Southern Alliance for Clean Energy.

The Department of Treasury just concluded a comment period on the credits, so there may be revisions. This blog post focuses on electric vehicle (EV) and charging infrastructure credits and will be updated as new information is released.

Key Takeaways:

The Inflation Reduction Act (IRA) includes several new and revised tax credits to support EV and charging infrastructure investments. Prior to passage of the IRA, many entities were ineligible for tax credits because they lack tax liability. Now, tax-exempt entities like local governments will be able to receive a direct, elective payment of tax credits for making qualifying investments. This new credit delivery mechanism is called “Elective Pay”(aka “Direct Pay”), and it will allow many local governments to speed up the deployment of EV fleets and charging infrastructure. New proposed rules from the U.S. Department of Treasury and Internal Revenue Service (IRS) clarify how the credits work, who is eligible to receive the credits, and how to access them.

Elective pay allows applicable entities (see below) that do not owe federal income tax to benefit from EV and charging infrastructure tax credits nonetheless. This works by treating the amount of the credit as an overpayment of taxes; resulting in a refund allowable for the amount of the credit. 

After a local government purchases an EV or installs a charging station, they would complete a pre-filing registration with the IRS through an online process. The IRS would then provide them with a registration number for each applicable credit. Later, the local government files an annual tax return with the IRS to elect payment for the value of the tax credit by providing the registration number. The IRS would then make a refund payment to the local government for the full value of the credit. 

Say, for example, a local government purchases an electric F150 for $50,000. They would complete the pre-filing registration, then file a tax return for the value of the tax credit ($7,500 for a vehicle under 14,000 pounds). The IRS would treat the $7,500 as an “overpayment of taxes” and refund the local government the $7,500, effectively making the purchase price of the vehicle $42,500. 

Under the proposed rules, applicable entities for elective pay would include:

However, entities that are eligible for elective pay may not use another new credit delivery mechanism called transferability. 

Consumers are generally familiar with the Clean Vehicle Credit for Individuals. The IRA has now expanded EV credits to include two additional credits: the Clean Vehicle Credit for Used Vehicles, and the Commercial Clean Vehicles Credit (§ 45W), or the CCVC. The new CCVC has some notable distinctions compared to the other credit mechanisms:

CCVC-eligible vehicles are not subject to critical mineral and battery component requirements, North American assembly requirements, MSRP or income limits. Instead, they must be made by a qualified manufacturer. Essentially, if a vehicle manufacturer is on the IRS list of qualified manufactures, the credit applies. For more information about qualifications, see here.  

The CVVC credit is worth up to: 

It equals the lesser of:

The Alternative Fuel Vehicle Refueling Property Credit (§ 30C), or AFVRC, is now available to tax-exempt entities that want to install EV charging equipment on their property using elective pay. The IRA increased the amount of the allowable credit for installing EV charging equipment. In prior versions of the credit, the maximum credit amount for an entire site was $30,000. The credit is now per charging unit with a maximum of $100,000. Of note, in order to qualify for the AFVRPC, charging equipment must be placed in service in a qualifying property. To qualify, a property must be within non-urban census tracts or low-income communities (the poverty rate is at least 20 percent, or the median family income does not exceed 80 percent of statewide median family income). This qualifier offers a mechanism to close the equity gap where private capital on charging infrastructure has not been readily spent, and is in line with the Justice40 Initiative that 40 percent of the overall benefits of certain Federal investments flow to communities that have been historically underfunded and overburdened by pollution. In order to receive the maximum credit, there are prevailing wage and apprenticeship requirements. See the IRS AFVRC page for other qualifications and details.  

To calculate the value of AFVRPC:

The tax credits for both vehicles and charging infrastructure may be combined with tax-exempt grants and forgivable loans because of a special rule. However, the total amount (stacked amount) of the tax credit plus the tax-exempt grant cannot exceed the cost of a vehicle or charging station. 

The information contained in this blog is subject to the proposed and temporary elective pay and transferability regulations. The author of this blog is not a tax professional. You should consult with a tax professional before making decisions regarding the contents of this blog.

The Southern Alliance for Clean Energy’s Electrify the South program leverages research, advocacy, and outreach to accelerate the equitable transition to electric transportation across the Southeast. Visit ElectrifytheSouth.org to learn more and connect with us. 

The post What Local Decision Makers Should Know about IRA Tax Credits for Electric Vehicles appeared first on SACE | Southern Alliance for Clean Energy.

At the end of June, the Southern Alliance for Clean Energy hosted our first Clean Energy Generation webinar. We talked about the myriad of actions, big and small, we can all take to help create a comfortable, healthy, and environmentally sustainable world, starting today. We all have a role to play in the Clean Energy Generation, no matter where we come from, how old we are, how much money we make, or what our abilities are. 

To create healthier communities where we can all thrive, we must recognize the urgency of the moment and take decisive action together now. It starts with baby steps – asking questions and joining together as neighbors, students, and friends to decide which specific climate-actions could benefit our communities.

SACE member and volunteer Rhudine Steele spoke during our webinar. A resident of Clayton County, Georgia, Rhudine is passionate about shining a light on communities like her own that are affected by climate pollution. Rhudine noticed that many of her fellow residents were unaware of the impacts of climate change on their community, so she sought to make a difference by simply spreading the word. 

Ever wonder how you can take action against the climate crisis, but have no idea where to start? Don’t worry, you’re not alone. Sometimes just sharing what you learn can ignite a fire in someone who will take the information and run with it – starting a chain reaction of climate action. Read on to learn about how Rhudine ran with what she learned and is encouraging others to do the same. 

How did you first get involved in thinking about climate change and the environment?

When I first got involved, I was attending a farmers’ market at the Jimmy Carter Center here in Atlanta, Georgia, and I saw an organization that had a table up talking about climate and environmental change. I stopped by to get some information, and it got me to think about my own community, which is made up of Black, Indigenous, People of Color and has a lot of children. I also started thinking: I am living in a food desert, as we have a lack of [access to] fresh vegetables and food. I thought about how many residents in my community, whether children or adults, are unaware of what climate change is all about. 

I took this information, and I stepped out into the community, where I first started working with the Captain Planet Foundation. I thought that was a great organization to start with because they begin with the school system and work with children on environmental projects that they can take out into their community. Talking to the children, they can be really in tune with climate change and the impact it is having on their future. 

Our county, Clayton County, became one of the first counties in Georgia that was awarded electric school buses by [a grant from ] the Environmental Protection Agency (EPA). We have 25 school buses in Clayton County from the EPA so far. They put out grants often, where there is nothing to pay back, so the EPA is willing to help this region. A lot of people in our community don’t know anything about that, so getting out and telling the students and the teachers about that – they were very, very surprised. 

Once the buses are delivered by Bluebird in 2024, we want to think about powering them with solar. We first have to get the community on board with electric school buses, and it will take even more effort to turn them on to solar power. So, we go one step at a time to get ideas out to the community. And they are excited, especially the children, about how to learn and get involved. It just takes getting the information out – the first step is to get people conscious of what environmental changes they can make.

Rhudine alongside fellow Citizens Climate Lobby (CCL) members at the CCL Conference in Washington, D.C. this summer. Rhudine is part of multiple organizations like SACE and CCL that are working to better communities across the Southeast.

What made you interested in getting involved with SACE and our Clean Energy Generation work?

I started looking specifically at the Southeastern United States, where we are very impacted by environmental challenges. 

An example is in my community, we are five or six miles south of the airport. A lot of people are unaware that before planes land, they have to drop a certain amount of jet fuel to land safely. Clayton County is in that flight path, so a lot of it is being dumped over our community and into our water, like the Flint River. The Flint River runs through our county and is connected to other rivers in the state like the Chattahoochee River and the South River, which runs all the way to the Gulf Coast of Mexico. So everything is intertwined, all of us in the state are impacted by this pollution in some way. 

We have to start here, in the Southeast. We start at the community level, then we take it to the state level, then we take it to the federal level. But the very first step is to take what you learn out into the community and get people conscious of what the environmental changes are happening in your area. That way everyone can begin with doing a little bit at a time. 

Rhudine and fellow Citizens Climate Lobby members alongside Senator Raphael Warnock’s staff at the CCL Conference in Washington, D.C. this summer.

What advice do you have for people who are concerned about the climate and environment but not sure how to start taking action?

Get out into the community, especially with other organizations. For example, our plan was, since Clayton County was awarded electric school buses, to do an event for the whole community that involved the children, the politicians, the teachers, and the parents. Just passing out flyers is fine, but then you’re wasting paper. Have a community event and get everybody involved. When people see the event, it will stick in their minds because they’re seeing it, versus just reading it. 

It always starts from the bottom and moves up. You start with the children, you move it up to the adults, then you move it up to the politicians. One day, those children will become voting-age, and their votes will count toward environmental projects. Without our children, the politicians would not be politicians. 

This is one reason I am involved: not only for my future, but also for the children’s future. No planet, no future. So we start in our communities. 

Like Rhudine, we can all get started by taking baby steps, whether it’s talking to an organization at your local farmers’ market, stopping to notice environmental changes in your community, or simply sparking up conversation with someone at the grocery store. There’s no wrong way to get involved, and we all have what it takes to make a difference – especially when we join together as one Clean Energy Generation. 

Join the Clean Energy Generation

Take Action With the Clean Energy Generation

#CEGMemberStories

The post Rhudine Steele Shows How Community Action Leads to Real Traction appeared first on SACE | Southern Alliance for Clean Energy.

As part of our Industry Expert Interview series, we had the pleasure of speaking with Jenny Kalanges, Vice President of Membership at 1% for the Planet. 1% For the Planet is a global organization whose members contribute at least one percent of their annual revenue to environmental causes to protect the planet. The aim of the certification is to offer accountability, prevent greenwashing, and "certify reputable giving."

As TikTok, Instagram, and other social media platforms grow and evolve, brands have new ways to engage with consumers. 

Yes, the “Instagram/TikTok made me buy it!” trend is real, and it’s certainly not just about ads, which many users have gotten great at ignoring. These days, it’s influencer nudging that often pushes customers to buy. Thanks to the widespread use of these platforms and massive followings, influencers are driving sales. Recent studies show social media users (that is, most people) trust influencer promotions more than celebrity ones. And nearly 50% of social media users say they’ve bought a product after seeing an influencer advertise it.

Climate change, if you haven’t heard, is real1.

As advertisers and brands, it falls on us to do what we can to tell the story of a realistic, more sustainable future. We have a duty to do so responsibly and in a way that not only resonates, but drives people to actually change. And yet, one major hurdle still stands in the way: the continued political polarization of the topic. 

Responsible advertising related to climate change must break through this polarization to reach a wide audience, make sustainability a priority for brands, and continue to shift public opinion.

As 2022 winds down, we’re joining countless others in a moment (or two) of reflection over a year fueled by forward thinking, positive momentum, and growth. 

In 2021, $284 billion was spent on advertising in the United States. That’s a staggering number, representing a lot of power.

The post How to Organize Eco-Friendly Outdoor Events appeared first on Earthava.

Whether you’re hosting your first event or your hundredth, there is always room for improvement. A great way to upgrade your event organization is to focus on sustainability. With attendee travel, waste, and resource use, events have a significant environmental impact. Learn how you can reduce the negative impact of your event by having it […]

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The post How to Bring Your Eco-Friendly Knowledge to Social Media appeared first on Earthava.

While social media may have started as a tool for communication and socializing, it has long since become so much more than that. Today, billions of people use social media across the globe for a range of reasons.  One of the most significant benefits that have come out of social media is that it enables […]

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Public agencies prevailed in 71% of CEQA cases analyzed.

By James L. Arnone, Daniel P. Brunton, Nikki Buffa, Marc T. Campopiano, Peter J. Gutierrez, John C. Heintz, Lauren E. Paull, Aron Potash, Lucas I. Quass, Natalie C. Rogers, Jennifer K. Roy, and Winston P. Stromberg

Latham & Watkins is pleased to present its fifth annual CEQA Case Report. Throughout 2021 Latham lawyers reviewed each of the 51 California Environmental Quality Act (CEQA) appellate cases, whether published or unpublished. Below is a compilation of the information distilled from that annual review and a discussion of the patterns that emerged.

In 2021, the California Courts of Appeal issued 51 opinions that substantially considered CEQA while the US District Court for the Northern District of California issued one opinion. Notably, 2021 saw an increased focus on CEQA wildfire analysis. In cases like Sierra Watch v. County of Placer, the Court of Appeal ruled that the County of Placer failed to adequately analyze wildfire risks by wrongly assuming first responders would provide traffic control in the event of an emergency. And in Newtown Preservation Society v. County of El Dorado, the Court upheld a mitigated negative declaration in the face of public concerns that a bridge reconstruction project would result in significant impacts on resident safety and emergency evacuation in case of a wildfire.

Also notable in 2021 was the rare occurrence of a Court of Appeal partially affirming the denial of an anti-SLAPP motion following a CEQA lawsuit. In Dunning v. Johnson, the Court found that a project developer had established a probability of demonstrating lack of probable cause for the underlying CEQA petition, as well as a probability of demonstrating that the petitioners pursued the CEQA litigation with malice.

Of the 51 appellate CEQA cases in 2021, 15 were published, six were partially published, and 30 were unpublished. A nearly equal number of cases focused on Environmental Impact Reports (19 cases) and Attorneys’ Fees, Justiciability, and Other Procedures (18 cases), which includes issues such as mootness, statutes of limitations, waiver, and res judicata. These two topics were the focus of 71% of all cases in 2021 — which is consistent with 2020, when these two topics were the focus of 70% of all cases. Also in 2021, 10 cases focused on Exemptions and Exceptions, two focused on Mitigated Negative Declarations, two focused on Supplemental Review, and one focused on Certified Regulatory Programs.

Unlike 2018, 2019, and 2020, there was not a single district where the public agency prevailed in all cases. However, the First District had the most favorable record for public agencies, which prevailed in 89% of all cases. As was the case in 2019, in the Fifth District, public agencies did not prevail in a single case.

Overall, public agencies prevailed in 38 of the 52 cases, or 71%, up slightly from 68% in 2020 and consistent with the 71% win rate in 2019. The public agency prevailed in 88% of Attorneys’ Fees, Justiciability, and Other Procedures cases and 79% of Exemptions and Exceptions cases.

See Latham’s webcast on the key CEQA cases and trends of 2021

Read the CEQA Case Report: 2021 Year in Review

The proposal would auction off almost 375,000 acres of the Outer Continental Shelf offshore California for wind energy development.

By Nikki Buffa, Janice M. Schneider, Nathaniel Glynn, and Brian McCall

On May 31, 2022, the Bureau of Ocean Energy Management (BOEM) published a Proposed Sale Notice (PSN) for a pair of renewable energy lease sales offshore California. The PSN — which is the third offshore wind auction under the Biden-Harris Administration — represents a major inflection point in the complex and sometimes contentious process to bring wind power to the Outer Continental Shelf (OCS) offshore California. The timing of the PSN also dovetails with the California Energy Commission’s May 2022 announcement of the nation’s most ambitious target for offshore wind development: the state is seeking to construct 3 gigawatts of offshore wind capacity by 2030, with the potential for 10 to 15 gigawatts by 2045.

The PSN kicks off a 60-day public comment period ending on August 1, 2022, providing the last opportunity for interested parties to shape the California lease sales. Prospective bidders who are not already qualified to take part in the lease sale must submit their materials during this comment period in order to qualify to participate. The lease sales are expected to be held later this year.

Latham & Watkins has published a Client Alert that discusses four key aspects of the proposed California lease sales that potential bidders will need to consider, including:

Read the Client Alert

CARB doubles down on LCFS Program and liquid transportation fuels.

By Joshua T. Bledsoe and Jennifer Garlock

On May 10, 2022, the California Air Resources Board (CARB) released its Draft 2022 Scoping Plan Update (Draft Scoping Plan) for public review and comment. Assembly Bill (AB) 32, the California Global Warming Solutions Act of 2006 (AB 32), requires CARB to develop and update every five years a scoping plan that describes the approach California will take to reduce greenhouse gas (GHG) emissions to achieve the goal of reducing emissions to 1990 levels by 2020. Senate Bill (SB) 32 subsequently strengthened the state’s GHG emissions reductions target to at least 40% below 1990 levels by 2030. Our first post in this series discusses CARB’s Proposed Scenario to achieve the state’s GHG targets, which adopts a carbon neutrality target for 2045. Our second post explores how the Cap-and-Trade Program features in the Draft Scoping Plan. In this third post, we examine how California’s Low Carbon Fuel Standard (LCFS) Program factors into the state’s GHG reduction goals and how the LCFS Program may be amended in the near future. The Draft Scoping Plan states that CARB will initiate a rulemaking on the LCFS to ensure it continues to support low-carbon fuels that will displace petroleum fuels.[1]

The California LCFS Program was adopted in 2009 as one of the key measures to reduce GHG emissions in California under AB 32. The program’s original target was to reduce the carbon intensity (CI) of transportation fuel used in California by 2020 at least 10% from a 2010 baseline. CI is a measure of the amount of carbon dioxide equivalent (CO2e) emitted per unit of energy provided by that fuel, taking into account the GHG emissions over the lifecycle of the fuel — including production, transportation to market, and consumption. The LCFS Program sets annual CI standards that decline over time. Transportation fuels sold in California that have a lower CI than the LCFS Program benchmark established by CARB generate LCFS Credits, where one credit represents one metric tonne of CO2e reduced. Transportation fuels sold in California with CIs higher than the benchmark generate deficits. A fuel supplier with deficits must generate or acquire an equivalent number of LCFS Credits on an annual basis, creating demand for low-CI fuels in California.

The LCFS Program was most recently, and most significantly, amended in 2018 in response to the 2017 Scoping Plan, which “made it clear that developing a more ambitious LCFS is a critical part of the state’s efforts to achieve the SB 32 goal.”[2] In alignment with California’s 2030 GHG target, the amendments strengthened and extended the CI benchmarks to a 20% reduction below the 2010 baseline by 2030 and in each year going forward. In addition to strengthening the CI targets, the 2018 amendments made the following major changes to the LCFS Program:

As of 2019, the transportation sector was the largest sector source of GHG emissions in the state, accounting for more than 50% of statewide GHG emissions.[3] The Draft Scoping Plan addresses three ways in which transportation emissions may be reduced: (1) new technology; (2) innovative fuels; and (3) a decrease in vehicle miles traveled. Transportation technology and fuels both implicate the LCFS Program.

In terms of technology, the Draft Scoping Plan emphasizes that vehicles must transition to zero emission technology in order to decarbonize the transportation sector. Executive Order N-79-20 set a goal that 100% of in-state new passenger car and truck sales will be ZEV by 2035, which is reflected in the Draft Scoping Plan. That same Executive Order also sets a goal that 100% of medium-duty and heavy-duty trucks will be ZEV by 2045 where feasible, and by 2035 for drayage trucks. As shown in Figure 4-1, copied below from the Draft Scoping Plan, meeting the state’s goals for decarbonizing the transportation sector will require rapid, near-term increases in the percentage of new vehicle sales that are ZEV.

The Draft Scoping Plan notes that easy access to refueling infrastructure is required to achieve the level of ZEV adoption required to meet the state’s goals. While certain existing public funding mechanisms are available for the deployment of ZEV refueling infrastructure, “[p]rivate investment in reliable, affordable and ubiquitous refueling infrastructure must drive the transition as the business case for ZEVs continues to strengthen.” To that end, the “Strategies for Achieving Success” in the transportation technology category include an effort to align the LCFS Program with the Draft Scoping Plan, and:

Promote private investment in the transition to ZEV technology, undergirded by regulatory certainty, such as infrastructure credits in the Low Carbon Fuel Standard for hydrogen and electricity, and hydrogen station grants from the California Energy Commission’s Clean Transportation Program pursuant to Executive Order B-48-18. (emphasis added)[4]

In terms of transportation fuels, while electricity and hydrogen are currently the primary fuels for ZEVs, the Draft Scoping Plan acknowledges the need for low-carbon liquid fuels during the transition to ZEVs. This acknowledgement is pragmatic because gasoline- and diesel-powered vehicles are on the road today, and those sold before the aforementioned 100% ZEV mandates, will continue to operate as the California fleet turns over. Additionally, the Draft Scoping Plan notes that low-carbon liquid fuels can be used to reduce GHG emissions from sectors that cannot easily transition to ZEVs, such as aviation, locomotives, and marine applications. As shown in Figure 4-2, taken from the Draft Scoping Plan, the projected transportation fuel mixes in 2035 and 2045 indicate a substantial decrease in liquid petroleum fuels with increases in electricity, biofuels, and hydrogen.

The Draft Scoping Plan credits the LCFS Program for fostering a growing alternative fuel market in California, and states that the market signals from the LCFS Program are in part responsible for fuels like renewable diesel, sustainable aviation fuel, renewable gas, and electricity all gaining substantial market shares and displacing gasoline and diesel in vehicles.

The Draft Scoping Plan’s “Strategies for Achieving Success” in the category of transportation fuels includes initiating a public process to evaluate increasing the stringency and scope of the LCFS Program, which could include proposing accelerated CI targets between now and 2030; further declines in post-2030 CI targets (which are currently held constant at the 2030 levels) to align with the Final 2022 Scoping Plan; fully integrating current “opt-in” sectors into the LCFS Program (e.g., aviation fuels); and providing capacity crediting for hydrogen and electricity used for heavy-duty vehicle fueling.[5]

The success of the LCFS Program as a market-driven means to reduce the CI of transportation fuels relies heavily on the value of LCFS Credits. While in May 2021 LCFS Credits were trading for an average price of $190,[6] in the week of May 23-29, 2022, CARB reports an average Credit price of $105.03.[7] Credit prices have been steadily declining over the last two years due to a variety of factors, including new low-carbon fuel production facilities coming online and market expectations about future supplies of LCFS Credits from announced, but not yet built, facilities. It remains to be seen whether low-carbon fuel production facilities and ZEV infrastructure projects can secure project financing, be constructed, and remain profitable when LCFS Credit prices are falling. Given the Draft Scoping Plan’s acknowledgement of the LCFS Program’s role in encouraging and supporting the scaling up of alternative fuels, the upcoming LCFS rulemaking also may evaluate provisions to provide regulatory certainty and maintain LCFS Credit prices at a level that will continue to attract private investment.

Endnotes

[1] Draft Scoping Plan at 225.

[2] CARB, Staff Report: Initial Statement of Reasons for the Proposed Amendments to the Low Carbon Fuel Standard Regulation at EX-1 (Mar. 2018), available at: https://ww2.arb.ca.gov/sites/default/files/barcu/regact/2018/lcfs18/isor.pdf?_ga=2.163810422.838982876.1653944403-1700096536.1646153403.

[3] Draft Scoping Plan at 147.

[4] Id. at 150-51.

[5] Id. at 154.

[6] CARB, Monthly LCFS Credit Transfer Activity Report for May 2021 (June 8, 2021), available at: https://ww2.arb.ca.gov/sites/default/files/classic/fuels/lcfs/credit/May%202021%20-%20Monthly%20Credit%20Transfer%20Activity.pdf.

[7] CARB, Weekly LCFS Credit Transfer Activity Reports, available at: https://ww2.arb.ca.gov/resources/documents/weekly-lcfs-credit-transfer-activity-reports.

The Draft 2022 Scoping Plan Update takes an all-of-the-above approach to decarbonize California.

By Joshua T. Bledsoe and Brian McCall

On May 10, 2022, the California Air Resources Board (CARB) released its Draft 2022 Scoping Plan Update for public review and comment. Originally, the California Global Warming Solutions Act of 2006 required CARB to develop a scoping plan, to be updated every five years, that describes the approach California will take to reduce Greenhouse Gas (GHG) emissions to achieve the goal of reducing emissions to 1990 levels by 2020.

Subsequently, Senate Bill 32 strengthened the state’s GHG emissions reductions target to at least 40% below 1990 levels by 2030 and former Governor Jerry Brown’s Executive Order B-55-18 established a second statewide goal to achieve carbon neutrality as soon as possible, and no later than 2045. Recognizing the need to achieve GHG emissions reductions more quickly, in July 2021, Governor Gavin Newsom directed CARB to accelerate efforts to achieve the state’s climate stabilization and GHG reduction goals, including to “identify a pathway for achieving carbon neutrality a full decade earlier than the existing target of 2045.” The Draft Scoping Plan Update identifies CARB’s proposed path for how California can reach both its interim goal of reducing GHGs by at least 40% below 1990 levels by 2030, and its ultimate goal of carbon neutrality by 2045 along with pathways that would achieve carbon neutrality by 2035.

In developing the Draft Scoping Plan Update, CARB evaluated four scenarios to identify the most viable path to achieve the state’s 2030 interim GHG reduction and 2035/2045 GHG neutrality targets:

Ultimately, CARB staff chose Scenario 3 (Proposed Scenario) as the one that “best achieves the balance of cost-effectiveness, health benefits, and technological feasibility” in meeting the state’s goals.[1] To reach the 2030 and 2045 goals, the Proposed Scenario envisions an all-of-the-above approach that promotes electrifying everything that can feasibly be electrified while also foreseeing a substantial role for clean fuels like green hydrogen and CCS for those emissions that cannot be easily avoided.

Figure 2-1, copied below from the Draft Scoping Plan Update, shows the GHG emissions reductions associated with the Proposed Scenario compared to the “Reference” or business-as-usual scenario. As shown in Figure 2-1, even in 2045, the Proposed Scenario envisions almost 100 million metric tons of carbon dioxide equivalent (MMTCO2e) that would need to be removed and sequestered to meet the state’s carbon neutrality goal, with CARB noting that “[t]he modeling clearly shows, there is no path to carbon neutrality without carbon removal and sequestration.”[2] Governor Newsom, citing the Draft Scoping Plan Update’s reliance on CCS, included $100 million in new monies for carbon removal projects in his updated budget proposal.

To achieve the necessary GHG emissions reductions, the Proposed Scenario outlines what CARB believes will be necessary across various sectors including transportation, buildings, manufacturing, and electricity. Regarding transportation, the Proposed Scenario envisions the rapid deployment of zero emission vehicles across all vehicle categories. As shown in Figure 4-2, copied below from the Draft Scoping Plan Update, the transportation fuel mix in 2045 under the Proposed Scenario sees a substantial decrease in liquid petroleum fuels with increases in electricity, biofuels, and hydrogen. The Draft Scoping Plan Update predicts the importance of the Low Carbon Fuel Standard (LCFS) in incentivizing private investment to achieve these goals and calls for a public process focused on increasing the stringency and scope of the LCFS.

Under the Proposed Scenario, buildings in the state will almost completely decarbonize by 2045, with the use of fossil natural gas decreasing to a fraction of what is used today. The Proposed Scenario also relies heavily on energy efficiency to achieve reductions in building emissions, as demonstrated by the overall reduction in energy demand from buildings, shown in Figure 4-8 copied below from the Draft Scoping Plan Update.

CARB recognizes the importance of California’s industrial sector to the state’s economy and workforce but also recognizes the difficulty in decarbonizing some industrial activities such as steel forging, glass manufacturing, and industries with calcination processes, such as manufacturing lime and cement that cannot be easily electrified because of the high heat required. For these activities, the Proposed Scenario envisions a fuel switch to hydrogen, biomethane (aka renewable natural gas, or RNG), or other low-carbon fuels, with a specific strategy to “develop infrastructure for CCS and hydrogen production to reduce GHG emissions where cost-effective and technologically feasible non-combustion alternatives are not available.”[3]

CARB calls decarbonizing the electricity sector a “crucial pillar” of the Draft Scoping Plan Update. If California does not decarbonize its electricity sector, the electrification across all other sectors will fail to achieve the necessary GHG reductions to meet the state’s goals. Figure 4-5, copied below from the Draft Scoping Plan Update, shows not only the required transition to renewable resources but also the required growth in overall electricity resources by 2045.

The Draft Scoping Plan Update reflects an ambitious path forward for California that identifies opportunities and roles for many technologies and strategies to reduce GHG emissions. To support CARB’s consideration of the Scoping Plan Update, a Draft Environmental Analysis (EA) pursuant to the California Environmental Quality Act was also prepared. CARB will accept public comments on the Draft Scoping Plan Update and the Draft EA until June 24, 2022, and conduct a public hearing on the Draft Scoping Plan Update on June 23, 2022, which may continue until June 24, 2022.

Latham & Watkins is tracking this process and will release additional blog posts on the Scoping Plan Update’s discussion of the LCFS Program, the state’s Cap-and-Trade Program, and climate adaptation.

Endnotes

[1] Draft Scoping Plan Update, p. iv.

[2] Id., p. 65

[3] Id., p. 168

The president’s executive order aims to use the US government’s procurement power to achieve “carbon pollution-free electricity” by 2030 and net zero emissions by 2050.

By Jennifer Roy and Julie Miles

On December 8, 2021, President Biden issued an Executive Order on Catalyzing Clean Energy Industries and Jobs Through Federal Sustainability (EO), which aims to set the federal government — the largest purchaser in the country with an annual purchasing power of $650 billion — on a path to net zero emissions by 2050. The EO establishes the following policies as part of a whole-of-government strategy.

Consistent with other recent executive orders from the Biden Administration, the EO places a strong focus on environmental justice as well as a “just transition” toward cleaner energy. The EO also identifies growing domestic industry, creating well-paying union jobs, and improving public health as key policies of the government’s energy transition.

Despite the apparent expansive sweep of the EO, it contains exemptions for (1) certain activities, personnel, and facilities “in the interest of national security,” and (2) vehicles and equipment used in combat support, military operations, or training. The EO also includes a process for agency heads to request exemptions for any other reason.

While the EO establishes targets and goals, many of the implementing details are to be developed by federal agencies:

A number of the EO’s policies dovetail with components of the recent Infrastructure Investment and Jobs Act, including promoting a nationwide transition to electric vehicles, upgrading and increasing resiliency of the country’s power and transportation infrastructure, expanding clean energy generation and storage, and transitioning to a zero emissions future. This overlap further emphasizes the importance of these issues to the Biden Administration and indicates that climate and sustainability will continue to remain a focal point in executive policy.

Endnote

[1] The EO defines “principal agencies” as the Departments of State, the Treasury, Defense (including the Army Corps of Engineers), Justice, the Interior, Agriculture, Commerce, Labor, Health and Human Services, Housing and Urban Development, Transportation, Energy, Education, Veterans Affairs, and Homeland Security; the Small Business Administration, the Social Security Administration, the National Aeronautics and Space Administration, the Office of Personnel Management, the General Services Administration, and the National Archives and Records Administration.