If I Weren't Doing This...

That’s the start of Luke Combs’s song “Doin’ This” from his 2022 album “Growin’ Up.” For Luke, “doin’ this” is making country music. Here’s his response:

For me, and I suspect for many others working in climate and clean energy, this resonates pretty deeply. We got into this industry because it intends to invent, test, and implement solutions to the world’s biggest, scariest problem – not because it would pay the best, give us the most time off, or even be the most interesting and fun on a day-to-day basis. We got into this to be part of the solution, because we couldn’t live with the thought of not doing something to fight the climate crisis.

All this to say that if someone asked me why I choose to work in climate, I’d probably ask them why I should even consider doing something else. It’s the world’s biggest, hairiest, scariest problem and I plan to help fix it [1]. That’s the whole story.

Which brings us back to the question: What would you do if you weren’t doing this?

Look, I would love to be mystery novelist or a sports announcer. I think I’d be pretty good at both. Mission aside, I might enjoy the actual day-to-day substance of either job more than what I do now. Born to be a wordcel, forced to be a shape rotator [2]. But until the day we definitively defeat climate change, I’m always going to be doing something professionally that contributes to bringing that day a little closer, even if that occasionally involves more math than creative instinct… Although it’s often said by financial modelers that more fiction has been written in Excel than in Word!

Anyway, adopting the Luke Combs view that I’d still be doing this, I’ll narrow the question a bit:

If you weren’t doing utility-scale solar and battery storage project acquisitions, what other areas would you be investing or building in under the broader climate, energy, and sustainability umbrella?

First off, I’d want to get involved with something that can make a solid economic case for itself without relying entirely on future policy changes. Building a business solely on hopes and dreams of one day getting a carbon price or a pollution regulation or an emissions disclosure law is not a good use of time, expertise, or capital, in my view.

This is a major reason that I chose to pursue renewables investing after business school. Yes, the tax credit phase-out is going to hurt the industry, but even unsubsidized utility-scale solar and storage still offer faster, cheaper, cleaner energy than non-renewable alternatives in many cases [3]. Take away the distortionary tax incentives, which are not actually that distortionary when you think of them as the only politically feasible alternative in the US political landscape to a carbon tax, and there is still a proven set of technologies providing a product that people are willing to pay for. And of course, if we ever do get that true economy-wide carbon tax that actually requires firms to pay for the social harm of their emissions, renewables will only look that much better relative to thermal generation.

By contrast, the world just doesn’t need two hundred (or even twenty) emissions accounting SaaS companies. Compliance with sustainability regulations like carbon taxes or emissions disclosure laws in the jurisdictions that have them is a cost center for corporates, not a revenue generation opportunity. This necessarily means that the customer’s willingness to pay is capped at their current cost of compliance. Doing their compliance work extra-right doesn't get your customers anything; doing it wrong hurts them a lot. When the best your emissions accounting software can offer is a little less work for corporate compliance teams and ever-so-slightly lower SG&A spend from reduced sustainability team headcount requirements, you’re not positioned to create or capture much value. Plus, in the current political environment of anti-ESG backlash and rollbacks to many jurisdictions’ carbon-pricing ambitions, the TAM is shrinking rapidly as fewer firms are subject to emissions-tracking mandates. Without widespread legislation that forces companies to do this, your customer base becomes the few firms that voluntarily track their emissions for now. These firms will drop this practice to cut costs when they have a bad earnings quarter in the future, and you will have no customers.

To be clear, there are plenty of climate-tech software plays that do make sense economically! A great example is what my friend and business school classmate Charlotte is building with her team at Fram Energy: Their software solution allows building owners to charge individual tenants for solar energy generated by the building’s rooftop, where previously no such billing solution existed [4]. Rooftop solar economics are going to take a hit in the near future as the tax credits phase out, but solar still makes a ton of sense for many multifamily residential and C&I buildings – assuming landlords can pass through the system costs to tenants as a substitute for their usual utility bill. The business works because it unlocks an economic incentive that makes installing solar the obvious choice for building owners. The result is decarbonization of buildings’ energy supply, but the selling point is the bottom line, not the environmental benefits.

My broader point is that I don’t want to be investing or building in a space where highly supportive policy mechanisms are required to persist forever in order for firms to make money.

With all that in mind, what opportunities in climate and energy do I like outside of utility-scale renewables?

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[1] YMMV on what the actual biggest, hairiest problem is, and there are plenty of other good candidates, but this is my blog, so I get to tell you that I think it’s anthropogenic climate change.

[2] Click here if you have no idea what this means.

[3] At the cost of some amount of on-demand dispatchability, of course. Nuclear bros, we can fight in the LinkedIn comments about how important this actually is. The answer is, “it depends,” and it especially depends on how quickly we can develop and deploy longer-duration energy storage to bridge mismatched timing of renewables supply vs. grid demand. Read on for more on this…

[4] Disclosure: I am an advisor to Fram. A tagline I wrote for them made it onto a Times Square billboard recently, which was pretty cool! Fram Energy: You sell power, we get you paid.

In 2019, when I was doing climate policy work at CPI, I had the opportunity to work with SEforALL [5] on a framework for tracking global cooling investment flows. I must confess I don’t know whether the framework we devised and recommended was ever implemented, but working on that project did help me develop a greater appreciation for the massive scope of the challenge – and the opportunity – associated with meeting global cooling needs sustainably as demand continues to accelerate. A few key stats:

So, while everyone is freaking out about the energy needs of AI, remember that cooling is a much bigger driver of quality-of-life improvements in lower- and lower-middle-income countries: Affordable cooling solutions are a game-changer for economic productivity, educational attainment, nutrition, and health outcomes in places that are still in the early innings of the demographic transition. It’s critical to make sure these solutions are clean and efficient, because clean cooling is a climate twofer – it supports both mitigation (reducing GHG emissions by limiting energy use and by eliminating the use of harmful refrigerants that contribute to atmospheric warming when leaked as cooling units age) and adaptation (maintaining safety and quality of life as the world warms due to GHG emissions). Speaking from experience, it’s pretty rare to find that kind of combo deal in the world of climate investment. To keep the scope of this discussion reasonable, I’ll focus on space cooling, but similar opportunities to improve the price, performance, and efficiency of cooling services exist across food storage, medical facilities, transportation, data centers, and other applications.

Market(s): Space cooling is in demand pretty much everywhere, but especially in South and Southeast Asia, Sub-Saharan Africa, Latin America, and the Caribbean.

Why it’s exciting: Developing and deploying clean, affordable cooling solutions offers a huge opportunity to meet the growing energy and quality-of-life demands of the burgeoning global middle class. In addition to saving on operating costs relative to legacy cooling technologies, new cooling equipment that is more energy-efficient and uses less harmful refrigerants also helps limit GHG emissions and reduce strain on the grid so that the spike in global cooling demand doesn’t blow up the climate or the reliability and affordability of the power system.

Challenges to widespread deployment: Stuff that’s cheaper to operate after you buy it is usually more expensive to buy in the first place. Clean, efficient cooling equipment is no different. Properly aligning incentives and allocating risk to avoid resistance to higher upfront costs is critical (CaaS), as is quickly iterating and scaling production of innovative technological solutions to drive down those costs over time until mass adoption can be achieved simply by offering consumers and businesses a better product for cheaper (Gradient, Merino).

Final word: More people, higher incomes, hotter weather -> blowout cooling demand. Huge opportunity to develop and deploy better, cleaner solutions; huge risk to the climate and to daily quality of life in hot places if we don’t get it right.

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[5] The UN’s sustainable energy program.

[6] I.e. the cost of electricity used to run the unit plus any maintenance costs required for servicing/repairs.

[7] No, your dog is not a secret Einstein. Although some dogs are smart in other ways. Stay thirsty, my friends.

This pick could be considered cheating, to the extent that you consider any form of energy storage as fitting in the “utility-scale renewables” bucket that I focus on at Cypress Creek. But it’s really not – it’s more of a renewables-enabling technology – and anyway, economically viable LDES has not yet been deployed at utility scale the way that 2- and 4-hour lithium-ion batteries have [8]. To get electrons on demand, you need to convert electrical current to a different form of energy that’s, let's say, "shelf-stable." For example, true batteries (in the electrochemical sense) literally charge when you send electrical current into them, with electrons flowing to the anode as electrical energy is converted to chemical energy. The main drawbacks to this technology as currently implemented in grid-scale lithium-ion batteries are:

1.     You only get so many charge-discharge cycles before stuff breaks down and gunk builds up on the battery terminals (can you tell I’m not an engineer?). This compromises roundtrip efficiency as electrons shuttle back and forth over and over between the anode and the cathode.

2.      Lithium-ion batteries are prone to thermal runaway, when the battery temperature gets uncontrollably high due to an internal short circuit or an overcharge, the risk of which is also increased by charge-discharge “chemical wear and tear” over time (see gunk buildup item above).

3.      Lithium-ion batteries are fairly expensive to produce because they contain cobalt, nickel, and copper, all of which are currently scarce relative to demand.

One way to get past this is to make an electrochemical battery from different materials. Sodium-ion batteries like what Peak Energy develops don’t need scarce, expensive metals like cobalt, nickel, and lithium, and are therefore expected to carry a substantially lower capital cost than lithium-ion once firms can stand up more robust sodium-ion supply chains and manufacturing capacity to enable exploit economies of scale. Shoutout to my friend and business school classmate Yutong, who's advancing Peak's efforts to achieve this. The cheaper your materials, the easier it is to build a really big battery relative to the size of your electrical connection, which means the battery has a long duration (the LD in LDES) – it can discharge at max output for a long time because, to use a fossil-fuel analogy, it’s like a car with a huge gas tank and a small, efficient engine.

Another way to do LDES is to drop the whole electrochemical thing altogether and instead store heat, which is what the folks at Antora Energy (including my good buddy Raghavendra!) are doing: You use electricity to superheat a big lump of something, then recapture that heat when you want to use it. This approach’s key advantage over chemical batteries is that the materials are cheaper: The graphite that Antora uses is cheap and abundant, even relative to the less-scarce metals used for sodium-ion batteries. Again, that means less spend per unit duration of battery, unlocking batteries that can discharge for double-digit hours vs. today’s 2-4-hour grid-scale lithium-ion batteries.

It’s also simpler to store energy in the form of heat (just build really good insulation around your big-ass superheated graphite block!) than to store it in the form of an electrically charged chemical solution (better keep all those ions contained!). The thermal battery comes with less capex, no moving parts, and generally better operational safety. The trade-off is that it’s really hard to efficiently convert heat back into electricity. One possible solution that Antora is exploring, which I saw when I visited their HQ in 2023: Thermophotovoltaics (TPV), which are like solar panels but use heat instead of light to make electricity. TPV is a technology that should work in theory but requires a lot of R&D to get right. The other answer, perhaps the obvious one: Just hook it up to a steam turbine, as with natural gas, coal, and nuclear power plants. Sure, now we have moving parts back in the equation, but steam turbines are still safer and more reliable than ion batteries because they are exciting electrons by using hot water to spin something around rather than by facilitating an electrochemical process.

Market(s): Industrial heat consumers (near-term, for thermal batteries only); wholesale electricity markets (long-term with policy/market design support).

Why it’s exciting: Cheap materials storing zero-marginal-cost electricity means we can meet more energy end users’ needs with clean electrons from solar and wind, bridging the gap between consumers who need energy on demand and renewable generation resources whose supply of energy varies with the weather and/or the time of day.

Business models: Behind-the-meter/co-located LDES can reduce C&I facilities’ demand charge exposure by reducing or eliminating net grid imports during high-demand (therefore high-priced) periods and can enhance resilience by unlocking day-plus islanding capabilities that dramatically reduce the damage done to both facility throughout and critical machines and equipment by sudden grid outages or voltage fluctuations. In order to expand beyond this onsite demand management and resilience use case and capture the technology’s full value in the form of grid-connected LDES, the wholesale power markets (ISOs and RTOs) will need to wrap their heads around the value that a shorter-term dispatchable capacity resource could bring to the grid (see the next section). Once such a short-term capacity or week-ahead energy product exists, LDES will be the natural choice to supply that product to the market at the lowest possible all-in cost.

Challenges to widespread deployment: Where’s the revenue mechanism? Wholesale power markets typically consist of two separate power markets: A short-term market for day-ahead and real-time energy, and a long-term market for capacity [9]. Let’s imagine a 72-hour LDES battery (chemical or otherwise) with 67% roundtrip efficiency: We’d need to charge it for three days in order to provide two days of discharge. Does this operational profile make economic sense in either of the existing power markets? Not really:

And yet, it’s apparent that LDES does offer something valuable to the grid: Flexibility and resilience. Let’s play this out: On Sunday, the ten-day forecast shows that from next Thursday through the following Monday, a slow-moving snowstorm will settle down in Texas and the Great Plains states, and stay there. Winds will be minimal and clouds will block the sun. ERCOT, the grid serving most of Texas’s electricity demand, gets almost a quarter of its electricity supply from wind and another 14% from solar, while SPP, which serves the western Great Plains, has barely any solar but leans heavily on wind (38%).

Without generation from variable renewables, these regions will pay much more for stopgap electricity generated by high-marginal-cost gas peaker plants – and may even be subject to blackouts if those peakers can’t perform in the cold, as occurred during Winter Storm Uri in 2021. But if these markets are forward-thinking and implement a rolling five- or ten-day-ahead energy market, LDES systems that are cheaper to build and operate than thermal units can respond to a longer-lead price signal and begin charging with cheap renewable electricity that’s available from now until the storm rolls in, knowing they’ve pre-sold that energy via the advance market at a premium to their charging cost while still providing a cheaper source of supply than natural gas could have. And, as of 2019, 5-day forecasts have become as accurate as 1-day forecasts were in 1980. With medium-term weather forecast quality continuing to improve, a market for energy on the scale of days to weeks in advance is now both achievable and a great idea. Such a market would incentivize deployment of LDES resources that could:

1.      Backstop a growing base of cheap, variable renewable generation against extended periods of low insolation and/or low wind speeds.

2.      Proactively charge in advance of extreme weather events to ensure grid resilience on a local basis in the event that regional generation or transmission resources go offline due to lightning strikes, flooding, downed power lines, frozen fuel supplies, or other weather-driven damage or obstruction.

3.      Enable long-term generation-shifting to ensure that the output of the lowest-cost generation resources can be matched with the periods of highest demand, even if these do not occur within a few hours or even days of each other.

Final word: Right now, you can have energy that’s cheap or energy that’s dispatchable, with few options to electrons that are both cheap and on-demand. LDES unlocks huge economic value and emissions reduction potential by taking already-cheap renewable energy and making it dispatchable. Big things ahead.

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[8] …Although Form (using iron-air batteries, another chemistry that's cheaper but less energy-dense than lithium-ion) does seem to be close to achieving fully commercialized utility-scale LDES deployment. Good for them!

[9] Here’s a brief refresher on the difference between capacity and energy, paraphrasing a previous blog:

Energy consumption is the area under the curve, in kilo/mega/giga/terawatt-hours, while load or capacity is instantaneous power draw, in kilo/mega/giga/terawatts. For example, a gigawatt is a rate of power consumption at any given point in time, and a terawatt-hour is a quantity of energy consumed, specifically the amount consumed when you power one gigawatt of load for one thousand hours.

I’ll publish a short addendum post next week that provides a more detailed description of how the energy and capacity markets work in most US ISO/RTOs, so stay tuned if you’re interested in that whole shebang.

One thing I love about my current seat at Cypress Creek is that I get to go deep and build pattern recognition for what “good” looks like with respect to utility-scale renewables projects. However, deal flow and sentiment in the industry have historically been pretty tightly indexed to federal policy developments, and trying to maintain a fundamentals-driven investment philosophy is difficult when the ground under your feet is constantly shifting [10]. I knew that’s what I was signing up for when I joined CCR, and it’s been a great experience so far, learning from some of the smartest, most experienced renewables minds in the business – but at times I do envy folks at infra funds, whose broader investment mandates allow for diversification across multiple verticals.

A little level-setting here: For infrastructure PE, I consider a fund “middle-market” if it’s under $5B, with $5-10B being upper-middle-market and $10B+ being megafunds. This is for individual funds, not for total manager infra AUM, which will likely be 2-10x the individual fund size depending on how long the GP has been raising and deploying infra funds. And figure each infra fund makes perhaps six to ten discrete investments over an eight to twelve-year fund life before “exiting” those investments by selling them to another owner or taking them public via IPO. These funds are largely similar to standard private equity buyout funds, except that they seek to acquire assets (or platforms owning assets) with infrastructure characteristics. This means stable, contracted long-term cash flows generated by capital-intensive assets with high barriers to entry. A utility that operates as a regulated monopoly, with governmental fiat preventing competition from new entrants, is a great example of a typical infrastructure PE acquisition target. Other assets and firms in the infra PE sweet spot include independent power producers, toll roads, airports, passenger and freight railroads, parking lots and garages, and wastewater treatment plants.

However, all of these types of investments would likely fall under a “core” or “core-plus” investment mandate, which means relatively low risk coupled with lower target returns of around 8-13% (levered IRR). Core and core-plus infra funds usually, though not always, are larger than higher-upside “value-add” and “opportunistic” funds. This is because smaller funds can find more high-growth opportunities at their target check size, often rolling up multiple assets into a platform, investing in development-stage projects, or purchasing uncontracted assets and putting long-term offtake on them (therefore taking on execution, development, construction, and/or commercial risk), rather than buying stuff that’s already operating with long-term contracted revenue agreements. By contrast, there are only so many large, de-risked operating infrastructure assets out there that are big enough to be in the strike zone for the $10B+ megafunds, since infra funds tends to make around eight investments per fund, regardless of fund size (above I assumed six to ten; occasionally it will be more but very rarely fewer). Therefore, bigger funds must write bigger individual checks. This drives fiercee competition when big-ticket, low-risk assets do come onto the market, resulting in higher entry prices that suppress returns.

What this means practically is that middle-market infra tends to underwrite growth stories – a solar project developer whose first tranche of projects is 18 months from being ready to build but who needs capital now to fund interconnection deposits and equipment procurement; an EV charging station operator planning to go from 50 locations to 500 while tightening up the operational performance of its existing assets; a proven lithium-ion battery manufacturer seeking capital to expand its production facility and meet booming customer demand. These investments may look a bit more like non-infra growth or buyout private equity, perhaps possessing “infra-like” characteristics without having the locked-in cash flows of core or core-plus assets like, for example, a municipal landfill operator with a 50-year fixed-price tipping rate and predictable operations costs via long-term labor and equipment maintenance contracts.

Some firms doing interesting work in the energy transition corner of this space are NOVA, SER, Spring Lane, GDEV, Khasma, and Wollemi. Each takes a unique approach to middle-market infra and energy transition investments, not only in terms of their target firms and sectors, but also the financial structures they use to fund their portfolio companies’ growth while satisfying LPs’ desire for aligned incentives and downside protection. For example, the Spring Lane model is to invest in their portfolio companies’ first few assets at the project level, injecting expensive but necessary equity to help developers without a balance sheet scale the next X projects after the company pilots its first-of-a-kind asset, while also taking a minority stake in the portco’s corporate entity. This way, Spring Lane retains upside as the portco scales up deployment beyond those next X projects required for commercial proof and finds cheaper capital to finance additional future projects.

Market(s): The energy, transport, waste, and water industries, mostly in the US, Western Europe, and East Asia, although emerging markets infra funds also continue to become more common.

Why it’s exciting: Broadly, investors outperform when they have the skills, expertise, and conviction to better understand and underwrite certain risks than the rest of the market. For middle-market infra funds, this means building a team and an investment process that combines operational experience with financial sophistication, and values deep thinking about what makes a real asset business successful. I deeply enjoy the process of grappling with the risks and uncertainties associated with bringing renewable energy projects to fruition, and I’m also interested in applying that knowledge to a broader set of decarbonization infrastructure businesses facing similar challenges as they scale up to meet basic human needs more cost-effectively and sustainably. Of course, as an investor, you’re by definition always “buying” something when you deploy capital to an opportunity, but middle-market infra, more often than its upper-middle-market or megafund siblings, adds a meaningful “build” component into the “buy,” and that scratches an itch for me.

Business model(s): As a PE investor, you typically want to raise a dedicated fund with a 2-and-20 structure: 2% fee charged to limited partners on assets under management, and 20% carry (profit sharing) on all investment returns above a minimum threshold, usually an 8% IRR. Infra funds may charge lower management fees to LPs because their returns tend to be lower, and they tend to manage more money per head, than venture, growth equity, or standard buyout PE shops, but the structure historically has looked similar across these asset classes even if the numbers vary a bit.

However, we’re in a weird fundraising environment at the moment: It’s very difficult to raise a first-time infra fund right now, especially if you’re pursuing a non-obvious mandate that involves platform-building and/or taking positions in pre-COD assets. The alternatives are to raise a smaller 2-and-20 fund than you wanted and augment this with co-invest from your LPs when you want to make a larger investment than your dedicated fund size allows, or to operate as a “fundless sponsor,” raising capital from LPs on a fully deal-by-deal basis. Regardless, because MM infra means smaller deal sizes, the main way to make money in the sector is from carry, not from management fees, which means there’s a strong incentive to perform.

That incentive is weaker for megafunds, which can miss their carry returns hurdles and still print money for the GP because, well, 1.5% of fund AUM is a lot of money when fund AUM is $10 billion! The bigger your dedicated pool of capital, the more your incentives shift from “outperform to win” to “market perform and sit on a fee stream.” That might make some people rich, but it’s fundamentally uninteresting and also bad for LPs. All this to say that the intended incentive structure behind the 2-and-20 business model seems to be a better fit for MM infra PE than for larger funds.

Challenges to widespread deployment: N/A; MM infra PE is already a well-understood market segment and there’s nothing novel about GPs raising money from LPs to invest in assets or platforms. Unlike larger fund sizes, MM infra funds are typically the first institutional owners of the businesses they acquire, so it’s less likely that these funds need to raise a continuation vehicle or sell off a business for parts because it’s too big for another fund to buy – a problem that is increasingly affecting larger infra fund managers as they scramble to figure out who the next buyer is for massive platforms that they have already owned for six or seven years and now need to divest in order to return capital to their LPs. So while PE in general, including infra PE, is going through a bit of an exit squeeze, MM funds should be less affected by this than the big boys.

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[10] Last summer’s renewables tax credit rug-pull being the latest example of this.

[11] Disclosure: I have a position in Comstock Inc, the parent company of Comstock Metals. Any discussion of Comstock Inc, Comstock Metals, and their affiliates herein is not investment advice. Do your own research.

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That’s all for now, folks! May your spring weather be mild and your Q2 be prosperous.

Thanks for reading,
Coop