Last time I looked at the history of wave energy and what lessons we can draw from past cycles that could be relevant to today’s climatetech challenges.
This week I wanted to create the actual wave energy market map, in part to get a better sense of the variety of wave energy converters (WEC) that are being developed today and in part to better know and appreciate all of the companies that are working in such a difficult but rewarding space.
Though there have been hundreds of WEC designs proposed in the last few decades (130+ are included in The Liquid Grid’s database and 94 in Net Zero Insights' database), only a small fraction of those are still being developed today. I found 25 that are actively on the path towards commercialization (loosely defined to be: 1- not just a project by an academic institution and 2- having at least one announced milestone in the last year). Those 25 land in six different WEC categories that I could identify.
Included in this map:
A few observations on this set:
It's also worth noting that I made some purposeful exclusions in this landscape.
After looking at the breadth of ocean-based climate solutions last week and having a better understanding around the potential of the ocean, I thought it might be informative to look at wave energy more specifically.
Four things that are worth noting about the wave energy space:
These four characteristics of wave energy – the fact that the market is huge, the problem is hard, the technologies are diverse, and the history is long – make it an interesting case study for other hard tech climatetech spaces, especially those that are going through a similar Cambrian explosion of technology. There are lessons that we can take from looking at this area for not only the future of wave energy development but for the future of other climatetech sectors with a similar profile.
Here's what I observed:
Would love to hear if there are other lessons from those that lived and breathed this cycle or that have seen this play out in other sectors.
Look forward to diving into the wave energy market map next week. Stay tuned!
Most of what we talk about in climatetech happens on land – hydrogen production, power generation, carbon sequestration, grid optimization, industrial decarbonization, residential energy efficiency, etc. This is because the majority of technologies get deployed around people’s homes, in city environments, or industrial complexes, all of which largely occur on land.
But what about the ocean?
I became intrigued by the ocean after observing a renaissance of wave energy recently: the DOE announcement on funding for wave energy technologies and a smattering of news for wave energy companies like Atargis, CalWave, Eco Wave, and Mocean.
But wave energy is just one part of a larger suite of ocean-based climate solutions that have emerged over the last few years. The bigger category includes things like tidal energy, mining, regenerative aquaculture, carbon sequestration, low carbon shipping and maritime transport, hydrogen production, offshore solar, and of course, offshore wind.
All of these technologies are in varying stages of development, but most are early stage and require high amounts of capital going forward. Most also face a bevy of challenges being first-of-a-kind in the ocean: long permitting cycles and evolving regulatory requirements, limited testing sites, potential seawater corrosion or storm damage, lack of interconnections, power supply, and other infrastructure, difficult and expensive maintenance, and digital connectivity issues.
Many of these challenges can be tackled with funding, but ocean technologies consistently are deprioritized compared to land-based technologies. Even offshore wind, arguably the golden child for ocean-based technology deployment, is not growing fast enough. Net zero pathways like Princeton’s Net Zero America, BNEF’s Energy Outlook, and John Doerr’s Speed and Scale often build in limited to no allocation for marine solutions outside of offshore wind and ocean protection. Project Drawdown does include additional categories like ocean power, ocean shipping, and improved fisheries, but ranks them all fairly low on the potential impact scale (even offshore wind ranks 38 in a list of 84 ranked solutions, well below its renewables counterparts on land, which take the top 2).
IEA is the only one that seems to give the blue economy some credit. IEA’s ETP list includes 12 different types of overtly (some categories like CO2 storage lump offshore and land-based together) ocean tech and lists the large majority of them as “High” or “Very high” impact (though it’s worth noting that almost 40% of the list of 503 technologies is either “High” or “Very high” impact).
So to summarize, these are early stage technologies that face lots of challenges, require more funding, and are frequently ignored in net zero pathways. What’s the point in putting dollars to work in this area? Why in the world do we need to go through the trouble of funding these ocean-based climate solutions?
Technologies like regenerative / low carbon aquaculture or low carbon shipping are needed to decarbonize industries that we assume will persist in a net zero scenario. So that’s an easy answer.
But for technologies like offshore wind, offshore solar, wave energy, tidal energy, carbon sequestration, seawater and seabed mining, and hydrogen production, there are comparable land-based alternatives that one can argue obviate the need for more complex ocean solutions. A few thoughts on this category:
TLDR; ocean-based climate solutions present a valuable but underappreciated solution set to the world’s climate challenges. The ocean’s plentiful resources, proximity to demand centers, and high co-location potential present a compelling opportunity for both builders and investors in climatetech.
This week I had a grand plan to write about the economics of first commercial facility / FOAK commercial and why it makes complete sense to invest in these projects. But it was much more difficult to make the numbers work than anticipated. Even if a company gets over the FOAK hurdle, the lengthy time to exit coupled with the higher capital need results in returns for venture investors far from competitive to regular way venture investments.
There are paths to achieving competitive returns to regular VC – some existing ways include having philanthropic or government capital come in at FOAK stage, which can ‘lever’ up a project with non-dilutive financing, pursuing a licensing model, which, with the right partner, can allow a company to scale faster with less capital requirements, or recruiting an evergreen fund or fund-like operating entity that can provide flexible financing at multiple stages to accelerate the scale up.
But the path that is most murky (or at least was to me when I decided on this topic) is how to achieve competitive returns with a traditional institutional capital cycle.
After experimenting with a rough model, I found that one way you can achieve competitive returns is by creating a FOAK-focused fund and encouraging companies to early exit to this fund. The early exit helps early stage venture investors find liquidity sooner, increasing IRRs and the likelihood of a successful investment. For the FOAK-focused fund, acquiring the company before FOAK means having the ability to capture all future facility economics vs. competing for 2nd facility and beyond economics with very low cost of capital. The likely levered returns past first facility substantially reward the FOAK investor for taking the FOAK risk.
This FOAK fund is not unlike a private equity firm that aims to acquire a company and lever it up before exiting in a few years. The difference is that this FOAK fund would aim for infra-like returns (10 - 15%, or the higher end of infra) at the portfolio level and private equity-like returns (20 - 30%) at the individual investment level, building in some expected failure rate (in the example below, 2 out of 3 investments can fail and the portfolio will be fine) similar to a venture fund to go from the individual investment to portfolio level returns.
The FOAK fund is a novel concept because 1) infra investors are generally extremely risk averse and don’t think about their portfolio in failure terms, 2) private equity investors do balance their portfolio according to expected return but also don’t necessarily build in a failure rate and don’t aim for as modest of a portfolio return, and 3) venture investors do think about failure rate but don’t typically look for opportunities to optimize for cash flow or lever up an investment. A vehicle that combines elements of private equity, infrastructure, and venture capital can address the imperfect match of each one of these traditional vehicles with the FOAK problem.
I don’t think there is something out there in the market today that looks like this…the closest is Generate Capital and their strategy of acquiring, operating, and scaling sustainable infrastructure companies. But I haven’t seen an institutional investor that addresses the FOAK problem. Perhaps someone can correct me here!
Here’s how the returns stack up in this illustrative example:
A typical venture cycle runs 4 - 5 rounds of funding before a company exit. Because of the high failure rate of startups, VC investors target a homerun exit – $1B or more in less than 10 years. Putting in some reasonable assumptions for round sizes and valuations up until that point, we get that, for this individual investment, a Pre-Seed investor can expect a return of 76% IRR / 92x MOIC, a Seed investor can expect a 68% IRR / 39x MOIC, a Series A investor can expect a 69% IRR / 23x MOIC, a Series B investor can expect a 68% IRR / 10x MOIC, and a Series C investor can expect an 88% IRR / 6.7x MOIC.
If we assume these returns for the successful homerun investment, that means that, in order to achieve a minimum of 20% portfolio IRRs, a Pre-Seed investor can have 20 failures to one successful investment, a Seed investor can have 10 failures, a Series A investor can have 7 failures, a Series B investor can have 4 failures, and finally a Series C investor has the least amount of wiggle room with 3 failures.
Moving on to the hard tech example, we assume that the round sizes increase due to greater capital intensity, two more rounds of capital are added to fund additional development, and exit gets prolonged 3 years until the 12th year of the startup’s existence. In this case, the returns are lowered to 40% / 39x for a Pre-Seed, 32% / 16x for seed, 30% / 10x for Series A, 25% / 5.2x for Series B, and 26% / 3.9x for Series C. Series D and E investors get a 20 – 21% or 1.7 – 2.6x return. The failure tolerances are significantly decreased, with Pre-Seed investors only allowed 4 failures to maintain a 20% portfolio return, Seed investors 2 failures, Series A investors 1 failure, and all other later stage investors no failures (i.e. every investment must be a success, a tall order for this type of risk capital).
Now we come onto the early exit case. In this scenario, the company raises a few rounds of capital to develop the technology to the point where it’s ready for FOAK commercial. Then, the company exits early to a FOAK fund. The FOAK fund acquires the company at a lower discount rate than what the VC investors would normally target, therefore being able to pay more than what a VC would have valued the company. After the FOAK fund acquires the company, it helps the company get past FOAK and move onto being a levered fully functioning infrastructure owner-operator, after which it can be exited.
Exiting early allows the Pre-Seed investors to realize a 77% / 18x return, the Seed investors a 64% / 7.3x return, the Series A investors a 67% / 4.7x return, and the Series B investors a 76% / 2.3x return. Though the MOIC is lower, the IRRs compare since the capital is returned a lot sooner. Exiting early also allows for a lower failure threshold, since the liquidity event for these investors is no longer dependent on getting past FOAK. Thus the 6 failures for Pre-Seed, 3 for Seed, 2 for Series A, and 1 for Series B, while lower than in traditional VC, reflect an easier success case.
For the FOAK fund investor that invested with a premium valuation to a VC, they would still be able to realize an exit at nearly 30% IRR and 5.7x MOIC, a very healthy return for any private equity or infrastructure investment. Because this investor is taking FOAK risk, there is a chance that the investment fails in a binary fashion (vs. half-failing or generating a partial return), similar to a VC investment. In this case, with a 28% individual investment return, the FOAK fund investor can tolerate a reasonable 2 failures for every success case to achieve a “risky infra” return of 12%.
Investors, new or existing in climatetech, can create a functioning FOAK strategy that can make investing in FOAK a financially attractive proposition.
Founders in hard tech climatetech can look to early exits as a means of scaling and providing liquidity to early investors. Also early exits to risk-taking infra investors can be more lucrative than continuing with the venture cycle.
Service providers can consider encouraging and supporting the creation of these FOAK funds.
After discussing types of FOAK last week, this week I wanted to see if I could find a good estimate for the amount of FOAK funding we need.
One way to look at this is to try to pare down estimated infrastructure spend to what will be spent on FOAK technologies.
Most infra spend estimates land at ~$4 to $9 trillion / year. These numbers are never detailed enough to understand specific technologies they’re actually building in, but we can kind of glean from the breakouts an upper-end limit for what spend might be:
So all of the estimates roughly point to $1.5 - 2T / year being spent on technologies that have not yet scaled. Over the next 28 years, that’s $42 – 56T in total. Let’s just call it $50T as a midpoint.
To estimate how much we’d need for FOAK, we can just ballpark how much funding we can assign to deployed facilities (2nd facility and beyond) for every FOAK – or, assuming FOAK cost is around the commercial cost, basically how many deployed facilities for every FOAK facility. As one bookend, we can say that 1 out of every 100 facilities requires a FOAK. This is very high level but not crazy to assume. There are only 109 biodiesel plants in the US, 31 years after the first biodiesel plant in Kansas. There are only 18 renewable diesel plants (5 - 6 current renewable diesel plants with another 12 under construction), 12 years after the first renewable diesel plant in Louisiana. Using 1/100, that means we’d need to spend $500B for FOAK assets.
Another bookend would be looking at solar farms as a comp. There are 2,500 solar farms in the US, 39 years after the first solar farm in California. Let’s assume there’s 4 different types of PV (monocrystalline, polycrystalline, multijunction, and thin film) and that these 2,500 only needed 4 FOAKs (probably a very wrong assumption). If we assume 4 out of every 2,500 facilities requires a FOAK, we’d need $80B for FOAK assets.
So somewhere between $80B - $500B is probably the right number here…
To put this into context, PE funding in cleantech is at around $20 – 25B / year, while late stage VC funding is at ~$24B / year. If all of this funding was directed towards FOAK, we’d have enough…but part of this funding is used for digital technologies and for stages other than FOAK. If we assume that we have to put all of the FOAK in place by the halfway mark, we only really have $700B in place for potential FOAK funding. At the low end, 11% of our late stage – PE capital should be directed to FOAK. At the high end, 70% of that capital should be directed to FOAK.
I can tell you anecdotally that that true percentage of capital being directed to FOAK is nowhere near 11%, much less 70%.
If you’re not convinced by this top-down method of estimating potential FOAK spend, we can try to do a bottoms-up approach. We can assume that each startup that survives to FOAK needs FOAK funding…so we need an estimate the number of climatetech startups that are out there that will survive to FOAK.
Using Net Zero Insights’ database, I isolated 32 key areas that will likely need chunky FOAK funding, separated by the approximate types they’ll be in:
18,182 startups were identified as being in these categories. Let’s assume that 25% of the large plants, 10% of large assets, and 5% of large manufacturing faciltiies make it to FOAK. At $100mm per FOAK, that would mean we need $193B in funding for FOAK with just the startups that exist today. If we attempt to get more granular on individual category funding needs and assume the large plants need an average of $100mm, assets need $20mm, and manufacturing facilities need $50mm, we get $150B. At $150 – 193B of FOAK need, we’d need 21 - 28% of late stage VC + PE capital directed to FOAK, implying that one out of every 4 of these late stage deals need to be funding a FOAK.
I realize that a lot of this exercise is very hand-wavey…but it does at a high level illustrate an important need to direct more funding to FOAK facilities. We either need to be deliberately setting targets for the proportion of institutional deals that are FOAK OR we need to be bringing more capital in the door to help fund FOAK. In that latter case, the government, non-profits, and non-traditional capital sources like family offices and sovereign wealth funds will play an important role.
TLDR; FOAK funding will cost us billions, likely hundreds of billions, of dollars. We need more funding directed to it.
After last week’s look at commercial facilities that have been successfully funded, I wanted to better understand what projects in the future will need large first commercial facility (or large first-of-a-kind / FOAK for short) funding.
I went through the list of hard-tech climatetech technologies and think there's ultimately 3 types of startups that will need FOAK funding.
In order from most scale up risk to least scale up risk, assuming technology risk is equal:
These categories aren’t necessarily mutually exclusive. A company that builds an automated waste sorting facility may also need a manufacturing facility for robots (see AMP Robotics). A company that that installs large flared gas-to-datacenter systems may also want to manufacture its data centers (see Crusoe). (By the way, these two were not included in last week’s list because their FOAKs were <$50mm.) But most startups that are still commercializing their technologies are only contemplating FOAK in one of the three categories.
So what’s the point in knowing these categories? Understanding which category a startup lands in when planning out a FOAK commercial project can help identify a peer group with a similar scale up risk profile. Perhaps there are milestones and timelines that can be informative for early stage project planning, best practices that can be used between companies in each category, or benchmarks that can be used to help pitch the project risk profile to investors. Since the universe of FOAK commercial is so limited in climatetech, being able to creatively find a peer group to help tell the story is more important than in other industries.
There are also different recommendations I would make for capital raising in each category:
Those that need a plant:
Those that need a large installation:
Those that need a manufacturing facility:
Would love to hear:
If you're a startup - does this framework make sense to you? Or is there another category that's missing? If you're looking for FOAK funding or thinking about your FOAK plans in the future, I would love to connect.
If you're an investor - are there different or additional recommendations you would give for each of these categories?
If you're part of a corporate - are you or have you contemplated the types of partnerships described above?
The scaling problem in hard asset climatetech is well-known and well-documented…valleys of death, unfit capital, project development challenges, etc. etc. Technologies that require some kind of plant, facility, or large chunky infrastructure to be built struggle the most with scaling. Here's how the ease of funding curve looks across a company's maturity (thanks, Lanzatech):
Initial funding for these technologies, if in small dollars, is relatively plentiful. For R&D and prototyping, startups can access grant funding and traditional VC capital (as well as capital from family offices, corporate VCs, incubators & accelerators, and other entities that surround the VC ecosystem).
After the technology has been prototyped and shown to work at lab scale, engineering work can take it to the next level and show that it can be used in the real world. Engineering work can mean expanding the team to include more engineers and/or contracting third parties like EPCs or labs to perform feasibility studies. Larger VC dollars can fund engineering work, though the pool of VCs that can write a later stage check for a pre-commercial tech is more limited than at the earlier stage.
Pilots and first demonstration assets / facilities are where the capital stacks start to detract from the normal VC ecosystem. Funding for pilots and demo facilities can edge into really late stage VC to growth equity levels of capital. Activities like permitting, buying construction materials, hiring a construction agency, adding plant personnel, etc. are expensive. Since the goal of this stage is to make sure the technology works and to prove out the engineering work, the plants are smaller, limited in connectivity to commercial outflows like roads or the grid or customers, and operate only for a fraction of the time. I’ve found that most of the “mature” hard tech climatetech companies with big plants to build are at this stage. This is especially true for the battery industry. Several of the names that have gone public via SPAC over the last few years – Solid Power, Quantumscape, FREYR, SES – are still undergoing pilots.
After the technology has been validated at smaller scale in the real world, both the technology and business model need to be proven together in building the first commercial version of the asset or facility. As we reach the trough of the growth curve, this is the hardest step to get funding for but the one that derisks the company the most. Building a commercial plant requires the capital of a pilot or demo facility scaled up to the point where the economics make sense + capital for additional personnel to run the plant or asset full time + capital for processes or certifications to enable the product to be sold commercially + capital for logistical infrastructure like trucks, roads, pipes, or other conveyances + capital for contingencies, unplanned downtime, regular maintenance….the list goes on. This step attracts investors looking for cash flow, which means that the technology has to be derisked, the financial model has to be airtight, and there has to be a high degree of certainty that revenue will occur.
Post-first commercial, companies can access the much larger pool of capital: private equity, infrastructure capital, and project finance equity and debt. These capital pools don’t have enough climatetech opportunities at their desired maturity levels and check sizes. A startup that reaches this stage usually has enough leverage to get pretty advantageous economics.
I wanted to better understand how a startup can get past that first commercial trough – are there any learnings that we can glean from past projects? To do this, I set out to collect examples of large commercial facilities (requiring >$50mm in capital) that have been funded climatetech.
Unfortunately, they were very difficult to find. My ideal dataset would be 30+…but I could only find 10.
TLDR; funding for large first commercial facilities has limited precedence. As climatetech scales to need a greater number of large first commercial facilities, companies should look to the fuels space for learnings, corporate and tech-forward private / non-traditional equity for sources of capital, and acquisition of existing facilities as an alternative strategy.
Back to carbon footprinting! So after exploring carbon footprints around the world, how carbon footprints scale with wealth, and the general ecosystem of consumer sustainability software, I wanted to try out some of the consumer footprinting apps for myself.
First off, I had actually calculated my personal footprint using the same method from the previous posts. That served as a baseline for judging the accuracy of an app’s calculations. I’ve estimated my personal footprint to be ~28 tons (yikes!), with “splurge” categories being travel (flying about once a month), food (eating out), and discretionary purchases (this year has been a bit expensive because of moving but I also have an Amazon problem). For context, 28 is about twice the US median and in line with the average carbon footprint of someone in the upper middle class. It’s also 22x where the average person in developed nations should be by 2050. In other words, I’ve got my work cut out for me. And hopefully the apps can help!
I actually downloaded 21 apps to start off with. But six out of the 21 did not work for me for various reasons (CarbonTracker – couldn’t create an account, Earthly – couldn’t connect bank account, GreenFoot – clunky survey, SWRM – ungainly logging of individual actions, Offcents – not available in my region, Personal Carbon Footprint – was unable to load profile again after completing the survey). Another two out of the 21 were not included in the analysis to avoid an apples to orange comparison. Those two were Aerial, which tracks flight and rideshare emissions with email access, and Wren, which is a web app.
The rest, 13 apps, all successfully calculated current emissions but with varying degrees of accuracy. 4 out of the 13 were within 10% of the 28 number, 2 landed at around a 15-20% error rate, 3 had a 35-50% error rate, and the remaining 4 exceeded a 50% error rate. Most apps used surveys as either the main form of gathering data for emissions or as an accompaniment to bank account data.
The features of all of them also varied. 8 apps sold carbon offsets, 7 apps allowed the user to log carbon actions, 11 apps offered the user climate education in some form, and 5 apps included social features like group formation and group competitions.
A summary of my comparison below:
Links to the apps (add me as a friend!):
After using all of these apps for a period of time, here’s what I observed:
TLDR; The personal carbon footprinting market is still small. There are things that can be improved in the apps around accuracy, usability, and features offered. But knowing and understanding my footprint number was a valuable exercise for me as a consumer.
On Tuesday, President Biden signed into effect the Inflation Reduction Act. In the last two weeks, I’ve looked at the climate-related credits and the methane emissions reduction fee in the bill. This week, I thought I might be returning back to the topic of carbon footprinting and away from the thrilling world of tax policy…but the question around the EV adoption was nagging me so much that I needed to look into it. So here we go.
For the most part the IRA is extremely positive, but as mentioned before, the EV credit is the one credit that seems regressive compared to the previous credit, limiting the credit with North American assembly, battery sourcing, buyer income, and MSRP requirements. Summary below:
Overall, some concerning effects about the new credit:
The bill cuts out 73% of previously-qualified EVs/PHEVs in 2022 and at least 65% of previously-qualified EVs/PHEVs starting Jan 1, 2023. The remaining EVs/PHEVs are (unsurprisingly) mostly American.
Out of the 80 EVs and PHEVs that we know are actively being produced for 2022 and 2023, 66 or 83% qualified for the credit (all or some portion of $7,500 depending on battery size and whether the manufacturer’s cap was met) under the old EV credit rules. The ones excluded previously were all of the GM and Tesla vehicles, which have already passed their 200,000-car manufacturer’s cap + the two fuel cell EVs in production – the Toyota Mirai and Hyundai Nexo – which weren’t included in the EV credit but had their own fuel cell vehicle credit that expired at the end of 2021.
Now, with the new clean vehicle credit:
Assuming the battery requirements are met, those 23 cars consist of:
That’s 18 American cars (5 GM cars + 5 Ford cars + 3 Stellantis / Chrysler cars + 3 Teslas + 2 Rivians) or 78% of the list.
For EV purists, here are the numbers with EVs only:
Out of 43 total cars, 31 or 72% qualified for the old credit (again, 12 had already met the manufacturer’s cap). With the NAM assembly requirement, only 8 cars have a credit through the end of 2022 (assuming VW produces this year’s ID.4s in its new Tennessee factory), a reduction of 74%. With the caps lifted and MSRP requirements added in, and assuming the battery requirements are met, 13 cars will qualify for the new credit starting 1/1/23, a reduction of 58%.
It's possible that more cars will qualify as they ramp up their US factories over time. But this will take at least a couple of years for factories to be built and/or for existing factories to be configured for EV/PHEV production.
The battery minerals requirement is actually achievable near-term, but it will likely push battery pricing and also bias EV battery producers to LFP cells.
For the EVs/PHEVs that do qualify for the credit with the MSRP and NAM assembly requirements, there is still the question of whether they also fulfill the critical minerals and components requirements to receive either half (with one requirement fulfilled) or full credit (with both requirements fulfilled).
The critical minerals requirement states that in 2023, 40% of the value of the battery’s critical minerals must be sourced from the US or countries with a free trade agreement with the US. The percentage goes up to 50% in 2024, 60% in 2025, 70% in 2026, and 80% for 2027 and beyond.
Though the list of critical minerals in the bill is long, only six are material to EV battery composition: lithium, cobalt, nickel, manganese, graphite, and aluminum. The requirement states that the percentage is based on “value” of the critical minerals, which will probably be further clarified by the IRS, but we’ll take to mean market price of each mineral for now. Taking the average composition of minerals in each cell type and multiplied by the market price of each mineral, we get the following matrix:
Different battery chemistries have different value mixes and supply chain challenges. For NMC811 and NCA+, the 40% requirement can be fulfilled by sourcing just nickel from the right countries. For NMC523 and NMC622, the 40% requirement can be filled with lithium + nickel or lithium + cobalt or nickel + aluminum. For LFP, lithium alone can fill the requirement. (This is all assuming for simplicity’s sake that each mineral will be sourced from one location. It’s probably more likely that each mineral will come from a bunch of different locations. The IRS has their work cut out for them to figure out the accounting around all of this.)
If we take a look at the production of each of these minerals by country, we can tell how challenging it might be to source these minerals from the US or the qualifying free trade countries. Lithium is by far the easiest mineral to source with 77% of production in countries with free trade with the US (Australia, 52%, and Chile, 25%). Next is manganese with 17% of its production in qualifying countries (Australia, 16%, and Mexico, 1%). Nickel has 11% (Australia, 6%, Canada, 5%, and the US, 1%). Aluminum has 10% (Canada, 5%, Australia, 2%, Bahrain, 2%, and the US, 1%). Cobalt has 8% (Australia, 3%, Canada, 3%, and Morocco, 1%). Finally, graphite has a measly 1% (Canada).
First off, thank goodness for Australia. Without Australia’s lithium production and their free trade agreement with the US, most EVs would be screwed.
Second, if we combine this sourcing info with the minerals value matrix above, we can guess that most companies will be relying on lithium + nickel or lithium + nickel + aluminum sourcing to fulfill the requirement. 38% of lithium demand is for EVs at this point, so with 77% of production in the right places, there should be more than enough lithium supply now from the right countries to fill the requirement. The same can be said for nickel, though it’ll be more of a squeeze: nickel for EVs only compose 3% of the nickel market so vs. 11% of production, there should be enough supply for now (it’s probably enough of a shift for prices to go up though). Finally, aluminum is extremely abundant and presents little issue. Current aluminum demand for batteries represents <1% of aluminum production so vs. the 10% production number, manufacturers should have options.
The point is - theoretically, there’s enough production to source battery minerals from qualifying supply sources. Whether manufacturers are already doing that and if not, how long it takes for them to shift to the right supply sources, is a different question. Also, since most EV batteries are NMC, if shifting supply drives nickel pricing up, we may see overall EV pricing go up as well.
Finally, because of LFP batteries’ abundance of minerals concentrated in lithium and aluminum, it’s possible we see an accelerated shift to LFP by automakers to ease supply chain burdens and do more business with US-friendly countries. Tesla already uses LFP batteries in its Model 3 and Model Y base models and will probably qualify for this part of the credit as a result.
Graphite will be an issue for most EVs after 2024
A caveat to the above statement is that part of the battery minerals requirement is that no minerals or components will be sourced from a foreign entity of concern (China, Russia, Iran, or North Korea) in 2024+ (2025+ for minerals, 2024+ for components). For graphite, this is a big issue.
82% of graphite currently comes from a foreign entity of concern (79% from China, 3% from Russia, and 1% from North Korea). That’s vs. 33% of graphite that’s used for battery production. And because of graphite’s dominance in battery anodes, anode production is also concentrated in foreign entities of concern (mainly China with 85%), placing the components requirement in danger too.
If we don’t find another source of graphite, it’s possible that the majority of EVs will lose the credit either after 2024 because of the graphite sourcing or after 2023 because of anode sourcing.
The battery components requirement is trickier to get near-term
IRA requires that at least 50% of battery components to be manufactured or assembled in North America. This increases to 60% in 2024 – 2025, 70% in 2026, 80% in 2027, 90% in 2028, and 100% in 2029 and after.
65% of cathodes, 85% of anodes, and 76% of battery pack cells are manufactured in China, which does not bode well considering any included components from China after 2023 will disqualify cars from receiving the credit.
The percentage that the credit will be based on is also, similar to the minerals requirement, tied to the “value” of the components. It’s a bit more difficult to figure out what “value” means in this context and if the IRS will reach into individual supply agreements to figure out pricing for each component (hard to imagine that being practical). It seems like several sources (Novo, Visual Capitalist, University of Munster, Benchmark Minerals) point to the cathode being anywhere from 30 – 67% of the cost (depending on cathode pricing), the anode another 15%, the separator anywhere between 10 – 20%, and the electrolyte 5 – 10%. To get to the 50% requirement, manufacturing at least the cathode domestically seems necessary. Though there have been some announcements (Tesla, GM, Redwood, Lithium Werks) on large scale domestic cathode production, most facilities are in the earlier stages of development, which leaves at least 2 years of limited options for OEMs to qualify for this credit.
The flip side of this is depending on the interpretation of “manufactured or assembled,” it’s possible that all that matters is that the components are assembled in North America. If that’s the case, then there are existing options. Several OEMs already have cell production in the US (GM, Ford, Tesla), with many more battery cell factories on the way.
So in summary, for the 23 cars that will qualify for the credit after 1/1/23, I’m…
…which translates to the average credit being $3,750 until 2024, when most credits will turn to $0 because of foreign graphite/graphite anode production.
Hope I’m wrong and the IRS issues guidelines that totally turn over these interpretations, qualifying more cars.
A few more observations:
This credit favors existing automakers and handicaps emerging ones
The sucky thing about this credit is that it removes the credit for some automakers at the critical launch point vs. later on when the cars have had enough consumer traction to grow on their own.
The two fastest growing EVs this year behind the Tesla Model 3 and the Model Y are the Hyundai Ioniq5 and Kia EV6, both relatively new EVs that have launched in the last year or so and both no longer qualifying for the credit. With an average EV premium of ~$10k, the lack of credit will this price point out of the reach of many consumers that have been considering these cars. Personally, I myself have been looking for a good AWD EV and am struggling a bit to justify paying $51k for an AWD Kia EV6 vs. a $38k fully loaded AWD Kia Sportage (I don’t even get surround view or a sunroof in the former). That sentiment is echoed across many different forums that I follow (r/electricvehicles, r/KiaEV6, r/Ioniq5) and I suspect that this will reflect poorly in Q3 and Q4 sales numbers going forward.
The problem is exacerbated for startup companies. Rivian is set to barely qualify for the credits with their base models but their higher margin near-term deliveries will exceed the MSRP caps. Fisker and Polestar both don’t fulfill the NAM assembly requirement and won’t get the credit. For a startup OEM, slower sales in the beginning has an outsized negative impact on further growth, limiting their ability to generate cash flow to reinvest in further growth or raise more money from investors. An incumbent OEM has 1) the advantage of being able to eat some of the losses of a lackluster launch with their other product lines and 2) the advantage of an existing brand and consumer traction to support their EV growth.
With the new credit favoring existing automakers with the resources to pivot production, source more expensive materials, and/or have enough traction to not need the credit, the startup OEMs have higher hurdles ahead.
This credit also excludes a good portion of buyers likely to buy an EV
The bill imposes income limits of $150k / single and $300k / joint filers to qualify for the credit. While this is reasonable, it does mean that an estimated 42% of EV buyers are now excluded from qualifying for the credit.
A tax credit helps. 35 - 48% of Americans state that they’re much more likely to get an EV with a tax credit.
Again, like most of the requirements in this new credit, it’s hard to say how much the income limits will affect EV adoption…but 42% is a lot of people to exclude. And your average American seems reluctant to overpay for an EV unless it comes with a tax credit. We can only hope that more Americans will see the value of getting an EV despite the cost and/or OEMs will start lowering prices to appeal to the American buyer.
EV adoption in the US will probably slow down
A quick perusal of Reddit provides plenty of anecdotal evidence that consumers are rethinking EVs with the (lack of) new credit, but how much will this actually slow down EV adoption?
The good news is that most of the recent US transactions are from cars that will continue to have the credit going forward (or at least some credit, depending on the minerals and components requirements). 66% of 1H 2022 y/y growth in EV/PHEV sales were driven by 16 cars that will qualify for the new credit (mostly Tesla and some Jeep and Ford PHEVs).
That does leave 34% of growth without a credit though…and that 34% of growth represents 43 car models. This portion of the pie has also been growing much more quickly, boasting a CAGR of 119% vs. the credit-carrying group’s CAGR of 57% over the last 10 quarters.
Many estimates have EVs growing to ~30 – 50% of US new car sales by 2030. At the low end, that represents an additional 4 million car sales vs. 2021 numbers. If the credit-carrying category keeps up a 28% annual growth rate until 2030, we can theoretically reach this number without needing other models. And so far, that category has been posting CAGRs much higher, so maybe we’re ok.
But if we assume that the projections slow Tesla growth to a more mature growth rate, as EVAdoption has done, then we’ll more likely need 3.5 million cars from other OEMs by 2030. 2.5 - 2.8 million of those cars will likely be from non-credit carrying cars. If the lack of EV credit slows down adoption of these cars by 5% a year, we’ll be looking at closer to 25% of new car sales by 2030 instead of the currently projected 30%. If it slows down adoption by 10% a year, that’s 22% of new car sales by 2030.
So yes, this credit will probably have a negative impact on EV adoption. The numbers CAN be compensated by more aggressive growth assumptions for Tesla, GM, and the other automakers that do qualify for the credit, but that’s only if these automakers can deliver on production and sell more to consumers with lower incomes.
Basically - we’ve either crippled our adoption by a few percentage points OR placed a large portion of our bets on a few companies to help deliver on 2030 projections.
TLDR; the new EV credit, while likely to help boost domestic manufacturing and sales of US car brands, does so at the expense of EV adoption. It will make EVs more expensive for the consumer by limiting supply chain, handicapping competition, and removing the credit for a good chunk of EV buyers.
Last week I did a review of the new IRS climate credits in the Inflation Reduction Act (Sections 13101 through 13802). The other climate-related portions of the act (Sections 21001 - 23003, 30001 - 30002, 40001 - 40007, 50121 - 50303, 60101 - 60506, 70001 - 70002, 80004) cover appropriations to states and government agencies for various programs (home rebates, EV manufacturing, electric transmission, air pollution, etc.) with loose guidelines as to use of funds. For a more detailed list of what funds are assigned to what programs, check out the CTVC database.
I didn’t focus too much on these sections since how those funds will be deployed out of those agencies is still currently unclear. It’ll take time for these government agencies to figure out their rules for what projects / entities qualify for those funds. And then it’ll be an additional step to figure out how to enforce those rules in a practical way. Until then, the impact of these parts of the legislation are hard to judge.
That being said, Section 60113 is worth discussing.
Section 60113 is a methane tax on the oil and gas industry. It places a methane fee on oil and gas facilities that report >25,000 metric tons of CO2e / year. For whatever emissions exceeds the emissions threshold for that facility, the charge would be:
The emissions thresholds are as follows:
There’s also an exception built in to exclude facilities that that are already regulated by state-level methane emissions requirements, provided that those requirements would result in emissions reduction equal or greater to those that would be imposed by EPA’s proposed rule from last year.
Using current GHG reporting, the potential impact from this fee is 37 Mt CO2e, maybe less
The >25,000 metric tons of CO2e / year is the same threshold used by the EPA to determine eligibility for facility-level GHG reporting, so we actually have an idea of what emissions would be subject to this new tax.
In 2020, the 2,103 qualified oil and gas facilities that reported to GHGRP emitted a total of 0.3 Gt CO2e / year. Of that amount, 77% or 0.2 Gt CO2 are from CO2, and 23% or 0.07 Gt CO2e (which is equivalent to 2.6 Mt methane) are from methane. To put this in context, the total emissions in the US right now is 5.8 Gt CO2e, so the covered facilities represent ~5% of the total.
If we impose the methane fee on the facilities that exceeded their thresholds we can see that an estimated 63% of current facilities are currently not compliant. Those facilities represent ~1.5 Mt methane in excess, or the equivalent of 37 Mt CO2e. With the 2024 fee amount, that’s ~$1.3 billion in fees paid to the government.
The numbers are possibly smaller considering the regulatory exception that may allow some facilities to bypass this fee. Facilities in states like Colorado can follow state regulations instead if the emissions reduction would be greater or equal to those imposed by the currently proposed but not active EPA rule. It’s unclear how that emissions impact would compare to this fee.
The economic impact won’t cripple operators by any means but can be significant
A non-compliant facility on average would pay $1.9mm for 2024’s emissions measurement. That translates to $0.43 / mmbtu or 4.3% of estimated revenue using today’s prices. Though 4% of revenue is no small change, commodity swings can be much larger for oil and gas facilities. Cost structures often take this potential volatility into account and are sized appropriately to be able to handle them. So at today’s prices, the economic impact should be easy for most operators to handle (9 facilities actually would have the fee take up more than 50% of revenue, but those are large outliers).
That being said, commodities do shift quickly and if pricing drops down close to the breakeven, the extra punch from the methane fee could hurt a lot more (average of 12% at $40 oil and $2.50 gas). So hopefully that itself gives operators enough incentive to take emissions reduction seriously.
These thresholds are generally in line with what industry has already set for itself but will incentivize laggards to comply
OGCI, composed of many of the large oil and gas majors, already met its 0.20% methane intensity target in 2020 and is now setting up to have a target of well below 0.20% by 2025.
ONE Future, a natural gas consortium, has publicly stated its goals to be 0.28% / 0.08% / 0.111% / 0.225% for upstream / gathering / processing / transmission & storage. These are much higher than the methane fee thresholds, BUT in practice (or at least in what's reported), the consortia has already reduced its emissions to be well under their goal and the methane fee thresholds. In 2020, they reported 0.11% / 0.04% / 0.02% / 0.14% for upstream / gathering / processing / transmission & storage, which, save for a 0.03% difference in transmission, are in compliance with these new methane fee thresholds.
So for the operators that have already set goals and are working on their methane intensity numbers, this fee should have low to minimal impact on their efforts.
But looking at the wide distribution of methane intensities across operators, there are many that are egregiously off base. This fee would hopefully help push those laggards to keep up with the rest.
The fee doesn’t apply equally, hitting the smaller facilities harder than larger ones
A couple of interesting trends to observe: the non-compliant facilities tend to be smaller facilities, having an average of 48 Tbtu production, more than 4x lower than the compliant facilities (perhaps a factor of the methane intensity goals mentioned above). Offshore facilities also tend to be more non-compliant than onshore facilities. LNG, though with very few facilities in general, is much more compliant than its traditional gas counterparts.
GHGRP under-reporting is a real issue and could handicap the emissions impact
What was confusing to me was the discrepancy in methane emissions accounted for under GHGRP and the methane emissions estimated by EPA’s GHG Inventory (GHGI). According to GHGI, methane from natural gas and petroleum systems account for 0.2 Gt CO2e in 2020, almost three times higher than the 0.07 Gt CO2e that is reported in GHGRP. That’s out of a similar 0.3 Gt CO2e number of total emissions. In fact, for some reason, the proportion of methane emissions reported in GHGRP is switched from the proportion of methane emissions reported in GHGI. I double and triple checked these numbers but couldn’t figure out why these don’t reconcile.
But beyond what could just be a government database problem is the overarching issue with GHGRP emissions accounting. There are more and more studies that point to GHGRP under-reporting for all sorts of reasons - industry non-compliance, bad methodologies, and reporting thresholds that exclude the majority of emissions. That's an issue not only for determining the fees in a rule like this but also for eligibility for GHGRP in the first place. Though GHGRP does put in place some verification procedures and requires operators to document all emissions reporting, there are still plenty of ways an operator can bypass the system, deliberate or not. Once there’s a real monetary incentive to do so, I suspect that under-reporting may be even more prevalent.
The way to counter this is with technology. With better methane monitoring technology will come higher standards for reporting. That will in turn allow EPA to not only verify the emissions numbers more easily but also allow operators better manage their own footprints in real time.
TLDR; the methane fee is more of a gentle push vs. a kick in the butt. It likely won't have a big emissions impact, but it will play an important role of pushing industry laggards to catch up with industry leaders that are already setting similar methane intensity targets. Plus it generates an extra $1B for the government.