All Forum Posts by: Yi C.

@Yi C. I don't know what would be different from CA but I'm sure there are a lot of differences. With buying land, you need to be very careful. Is the lot actually in Pueblo or is it just "near" Pueblo. There are a number of legacy subdivisions in the county around Pueblo that have unbuildable lots due to a number of issues. Know before you buy and don't assume anything. You should have someone local who specializes in land to represent you and it will likely costs you around 10% of the purchase price, if it's a relatively small purchase price. Utilities (water, sewer, and electric) are a big issue outside of the City proper. It can cost more than the price of the land for EACH of these items. Please be careful.

Hey! I’ve worked with a lot of out-of-state investors, and moving from California to a market like Pueblo, CO, or even here in Ohio (Columbus, Cleveland, etc.) definitely comes with some differences.

In California, you’re used to escrow companies handling the closing, but in Colorado and Ohio, it’s more common to use a title company or an attorney. Buyer commissions can also vary more with land, while 2.5–3% is typical in CA, land deals in CO or OH sometimes offer lower or flat fees, so always double-check.

Pueblo will likely require a survey if you plan to build, which isn’t always the case in California. The same goes for parts of Ohio, especially in more rural areas. Zoning in California is usually pretty strict, while Pueblo tends to be more flexible, but it’s still important to confirm details with the city or county. Ohio zoning is hyper-local too, so a quick call to the local office can save a lot of headaches.

One more thing to keep in mind is utilities. Lots in CA often have access nearby, but in Pueblo or smaller Ohio towns, you’ll want to confirm availability and costs for electric, sewer, and water.

@Yi C. I agree with the points in your post.

My Disclaimers:
1. I build and own my projects. Historically, I have not sought to acquire land with the intention of leasing the land to another developer/development company. I am not against the buy-to-lease method, for someone else to implement, but right now it's not what I do.

2. In my markets I am tactically focused only on <500 kW implementations. Strategically, I aim to fit into as many development exemptions as possible. The 'entitlements' part of most projects >=500 kW consumes most of the development timeline. I just don't have the patience to wait four years and spend 6-figures for environmental studies on a 1-MW, four-acre project. That's why no one builds 1-MW to 5-MW now. Projects have become really big or really small. 500 kW and under exemptions? Yes, please.

Projects, large and small, fail for a lot of reasons. Changing legislation, primarily at the state and local (county) level, I think, is one of the biggest reasons for cancellations in NC and VA. Many places are 100% NIMBY. Even some municipal electric companies don't want to work with small IPPs. Yes, I have first-hand experience with that (technically illegal) prejudice.
Lease problems sometimes result in project cancellations on larger projects. Technical issues with "impact studies" results and who pays for mitigating environmental issues is another.

On small projects, equipment upgrade costs for substations can be a showstopper. In Sampson County NC, SREMC handed me a $100,626 estimate for substation upgrades for a 500kW project. I put that project on the back burner since higher development costs and thin margins were already causing us concern.

@Jay Hinrichs pinged me so I am posting. Note that my experience is limited to NC, SC, VA jurisdictions, so keep that in mind when reading this or my other posts about solar.

Regarding "Solar farm land lease is generally very profitable," on the east coast at least, that is not necessarily true. There was a time, briefly (a few years), about a decade ago when some prime solar farm site owners signed favorable LTLs (Long Term Leases.)

Regarding "...about 50%+ of the option will not go through." The real numbers, per the U.S. Department of Energy under Contract No. DE-AC02-05CH11231, are not great: "Only ~20% of projects (14% of capacity) requesting interconnection from 2000-2018 reached commercial operations by the end of 2023. Completion rates are even lower for solar (14%) and battery (11%) projects."

Regarding Interconnection, keep in mind (same reference as the above link) "The typical project built in 2023 took nearly 5 years from the interconnection request to
commercial operations." Also, for ground-mount systems, most developers require 200-300+ contiguous acres, a relatively flat parcel, no wetlands or endangered species, and three phase power line access adjacent to the property. For distribution connected projects, the property needs to have close proximity (ideally adjacent) to a utility substation. Larger projects (e.g. 50MW+) generally interconnect with the transmission operator facilities, so you'll need transmission lines close by. For example, on Duke Energy's Warsaw site, collectively 87.5 MW, the developer built a new substation off Penny Branch Rd. since the generation facilities exceeded the existing distribution capacities. On Google Earth, use the two dates 4/2017 and 1/2018 to see the build-out. (Google Maps location)

I'm not sure what the "wholesale export rate" means. In general, developers will model revenue with SAM or an equivalent tool for non-dispatchable production. I am most familiar with fixed rate PPAs with rates that change by season (monthly summer, winter, shoulder) and time (hours on-peak, off-peak). The wholesale electric rates depend on location and time-of-day in 5-minute intervals. Wholesale rates generally average $0.02 to $0.05 per kWh.

Most west coast IPPs deploy solar with energy storage systems (ESS) to time-shift out of the low to negative margin day rates. The CAISO (California ISO) real time markets routinely go negative in summer from 10AM to 2PM (solar peak time), meaning the customers with non-dispatchable roof-top solar will be charged for putting solar onto the grid. During solar peak time, the CAISO market also routinely sees generation from renewables exceed the total grid load, which is quite incredible. See https://www.gridstatus.io/live for the real-time grid monitoring, status, and rates. 

 I guess you are doing a net land lease where the solar company is paying 100% of the property tax. I know from researching tax roles this year, that the appraiser's in Texas have valued the Solar panels farms very high and I don't know if there is litigation regarding the taxes, but there are several solar farms with unpaid taxes.

I think the one negative about buying land and doing a solar lease, is that it is no longer taxed as a Agriculture exempt, this is a major negative to the project.  I assume that you would have some sort of guarantee on the lease if there is a hail storm.  One option that might make more since is finding a bitcoin mining operation, because with Starlink, you can essentially set up an operation anywhere, so if you can buy $100/acre land in a sunny climate, Bitcoin Mining generates approximately $.085/kw in electric rate.  I'm not sure if that works for solar, but it opens up more possibilities.