All Forum Posts by: Chris Martin

Like Chris, very sorry to hear about your condition. 

You should have a tax person explain to you how the stepped-up basis may help your beneficiary. Legally speaking, if you have agreed to an installment sale, I'm not sure if the stepped-up basis is applicable. I don't know your adjusted basis, so maybe the estate tax burden will not be that great. 

I suggest what Chris posted. 

Just use Google. Nathan's search method usually works, but I use what Google suggests: '<search item> site:www.biggerpockets.com' (without the single quotes on the Google search bar.) 

Google investment DSCR mortgage LLC or something similar to find national lenders. I've used LendingOne before as well as local commercial banks. And as Rory points out, subsequent loans require less overall time and effort once you have a track record. In my experience, most local commercial lenders will not offer 30-year loans like some of the national lenders. 

The experts can verify, but the deed must stay consistent for a 1031 exchange to be viable. I've only done two exchanges, so am no expert, but I don't think what you suggest would conform to 1031 guidelines. 

This BP topic, Total Available Market - 2, 3, and 4 units, describes the Raleigh market for property that meets Fannie Mae 1-4 Family underwriting. The data is 5 years old but hasn't changed significantly. The bottom line is there are not a lot of quads in the Raleigh area. 

@Yi C. 

Regarding #1, all my projects are ground mount. Yes, zoning is always an issue. Many counties have a solar ordinance that may make a project less attractive or potentially prohibitively expensive to implement.

Regarding #2, I've obtained SUPs (Special Use Permits) in two NC counties. The other developers I've seen in the quasi-judicial SUP hearings all used attorneys, even for 500kW projects. I opted to represent myself (as an independent landowner). Yes, these hearings are a pain. And, yes, you do get yelled at and may be required to bring in professionals to debunk the ridiculous claims some neighbors will make. I've had to hire Real Estate brokers and Professional Engineers (PEs) as "expert witnesses" for defending various false claims.

Regarding #3, the smaller your project, the less likely you'll see high impact study costs.
Common expenses would be utility mandated SCADA upgrades for system isolation, metering packages, engineering & testing, etc. I have not yet done a solar+ESS project yet. That is certainly where the world is headed. There are stable chemistries out there, and I'm not concerned much about ESS thermal runaway. I'd consider something like the CATL 1G Sodium Ion, 2-MWh, depending on the PPA. 

@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. 

Quote from @V.G Jason:

Solar will be a massive pain in the *** if you are doing this in the SE belt. I've looked into and it just doesn't make sense, and has a lot of hurdles. I recommend timber investing, have you looked into that?

Can you clarify what you mean by "it just doesn't make sense"? What aspect(s)?

My reservations about timber: make sure you maintain your parcel well, because a pristine stand will attract more bids. Stumpage prices, in NC at least, have been unimpressive for a decade. International Paper's cutbacks at the Riegelwood, NC pulp facility doesn't help. Seems like a lot of mills are closing on the east coast. That makes the miles-to-mill for my (84 acre) parcel in Hallsboro potentially unattractive. Through my forester, I've had zero bids to clearcut, treat, and replant. 

Quote from @Chris Martin:

@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 IPPs with non-dispatchable 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. 

@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.