Energy Infra PE case studies.

I have nothing I'm willing to share, but I work in M&A for a large energy developer and also have worked directly with a few large infra funds (one that you named). My bet is the case study will present you with a few energy assets to buy (solar, wind, battery, hydro, etc.) and ask you to make the case to buy one or not buy one. You'll probably be asked to model each out, draft a presentation to an investment committee, and maybe an LOI to the seller to acquire the asset.

If you're at all working with renewable assets, then I can provide some guidance on how to model.

1. Production from facility (MWh's per year) - you'll likely be provided a P50 yield (MWh p.a. / MW), which will let you calculate the total production of the facility per year. Depending on the offtake contract structure, you'll also need to apply some losses related to curtailment in the modelling, as well as losses from availability. These will likely be provided to you in the case study assumptions. Lastly, you'll need to make sure to degrade the capacity of the solar facility 0.5% per year, so if you have 100MW capacity in year 1, you will have 95.5MW capacity in year 2 to base your calculations.  Wind you will not degrade. Batteries degrade too but will likely be overbuilt and have an augmentation schedule, but let's stick with solar for now. Depending on the depth of the case study, you may also be provided a P90, P95, P99 production values, which may be important for debt sizing. The way to think about this is lenders will assume less production per year from the facility than equity assumes and gives less debt sizing credit.

2. Revenue - once you have your P50 production profile over the full useful life (35-40 years), you can apply a contract price ($/MWh) to the your production to get full revenue forecast over the PPA term. You also will need to incorporate any merchant revenue assumptions that they provide you. You may have been given a merchant curve to use for revenue estimating after your contract term expires. Or, even, you may have a partially bundled offtake contract where you're only selling the energy+RECs to an offtake during the contracted term and you can also earn other revenue separately from the contract (e.g. unbundled capacity market revenue). I'd be surprised if you were asked to assume a partially bundled contract, but it's important to understand this concept. One important note here is look at whether the merchant curve units are in real $/MWh or nominal $/MWh. If the former, then the pricing will be in today's dollars and you should escalate the merchant curve values with a long term inflation assumption (2%?).  Also, important to note here, depending on the offtake contract structure / market, you may be exposed to basis risk. Essentially, the price your project is selling at the node is not equal to the price the contract is settled at the hub, therefore there could be a few $'s/MWh in risk or benefit that the project is responsible for. The key language here to look for is confirming the PPA is "settled at the busbar", meaning there is no basis risk, versus "settled at the hub". I won't go too into the details here as basis risk can get complicated.

3. Operating expenses / EBITDA - after projecting your full revenue over the project's useful life, separated out by contracted revenue vs. merchant revenue, you will apply your opex assumptions to calculate EBITDA. Primary items to model here will be operations and maintenance, ground lease expense (unless project owns land), property taxes, and operating insurance. You'll likely be provided all of these in a $/kWyr format and also be provided assumptions on whether to escalate the expenses with inflation or don't escalate. From there, you can pretty easily subtract revenue by opex to determine EBITDA. EBITDA margins on renewables should look pretty high (70%+) given the low amount of ongoing expenses (i.e., fuel costs = sunshine/wind, which is obviously free)

4. CAPEX - if the project is still development stage and the infra fund is taking on construction risk / paying for the construction costs, you'll want to build up the construction costs / capex related to the project, which will include the costs of equipment (modules, turbines, etc.), balance of plant (other non-major equipment, EPC related costs), costs of interconnection (network upgrades, switchyard costs), land costs, AND any developer fees to acquire the project. Naturally, if your infra fund is acquiring an operational project with all capex spend already incurred, you can afford to pay A LOT more than you can pay for a development stage asset that hasn't been fully de-risked

5. Tax Credits / Depreciation - depending on if the project is renewable or not, there may be significant tax credits associated with your project. Without going into all the complexities here, you essentially will need to determine the amount of tax credit creation from the project in either the form of investment tax credits (ITC) or production tax credit (PTC). If ITC, then you need to understand the full build cost (from part 4), assume a certain % is ITC-eligible (90% is good placeholder), then assume its ITC % on the ITC-eligible costs basis. The base ITC % is 30%, but the project may be eligible for a 10% increase based on 1. if it's located in an "Energy Community" or 2. if its equipment is "Domestic Content" or capex is domestically sourced. For near term operating projects, Domestic Content is unlikely as U.S. manufacturers do not have full capabilities yet to ensure domestically sourced materials. Likely, the case study will just provide you with an ITC % to assume, but you should be familiar of these concepts as they are very material to the valuation if you can qualify for an energy community. If the project assumes Production Tax Credit, then you will need to assume it generates a certain $/MWh production tax credit over the first 10 years of project life. Today, the rate is ~$26/MWh, but you should assume it escalates with CPI. The 10% increase based on Domestic Content or Energy Communities will also apply for a PTC deal (i.e., the project will generate ~$26/MWh x 110% or 120% if it qualifies for one or both adders).

Once you've determined the total tax credits generated from the project in either PTC or ITC form, you can also assume some depreciation expense to monetize. Without going into different depreciation schedules, you'll likely assume the same % of ITC-eligible costs (90%) is also 5yr MACRS eligible, so you take 90% of the total capex estimate calculated in part 4 and apply the 5yr MACRS schedule (can be found online), and then just assume the rest is depreciated straight-line over a certain number of years. Once you've calculated a depreciation expense, you can subtract it from your EBITDA (found in part 3) to determine taxable income. These projects are heavily depreciated in an accelerated manner via 5yr MACRS, so there is theoretically a large tax benefit from them, although certain entities may not be able to take 5yr MACRS. Apply a tax rate to your taxable income / (loss) to determine your taxable benefit (first few years while depreciation is high) and taxable loss (after depreciation wears off) 

*Important you can now calculate an unlevered IRR by taking 1. EBITDA plus 2. tax credits 3. tax benefit / (loss). This IRR is theoretical as it assumes the tax credits / taxable losses from depreciation can immediately be monetized, which isn't the case in reality*

This write-up is starting to become a bit more than I envisioned, so I won't continue discussing the full financing modelling to get to full levered returns. However, I will provide a few concepts that you should understand. The tax credits / depreciation created in part 5 will be monetized via a Tax Equity investor (large bank generally) that can immediately monetize the tax benefits of the project unlike the Sponsor/Developer. With U.S. partnership laws, you can allocate different %'s of the cashflow/EBITDA (part 3) from the taxable income / loss (part 5) to each partnership member (Tax Equity investor and Sponsor). So, you'll allocate virtually 99% of the taxable income to Tax Equity for a period, so they can monetize the tax benefits, while allocating the majority of cashflow to the sponsor (80%). Once you have Tax Equity's benefits aggregated (99% of tax benefits + ~20% cashflow), you can size their upfront investment assuming a certain IRR %.

On the debt side, most energy projects are back-levered, meaning Tax Equity doesn't want a lender above them in the project cap structure, so a sponsor will separately raise debt financing away from the ProjectCo. In this case, a lender will size their investment based on the cashflows available to the Sponsor after Tax Equity distributions have been paid (i.e., Sponsor's 80% of project EBITDA). You should be familiar with the basics of project finance debt sizing, which sizes debt based on a certain DSCR. In other words, a lender may assume a 1.3x coverage ratio on P90 generation during the contracted term vs. the Sponsor's expectation of cashflow (P50 generation during contracted period plus merchant cashflows after). I won't go into the nuances here, but I think it's just important to understand that the lender expectation for cashflow will generally be limited to the contracted cashflows at an assumed coverage ratio and based on worse generation (P90 vs. P50).

Hope this all helps, and let me know any follow up questions. I genuinely enjoy talking about this stuff. Would be interesting to hear from other in the energy infra space who are less focused on renewables.