Thread by @BSmithwood

NERD ALERT: Let’s talk about the Value of Distributed Energy Resources (VDER) tariff in NY. I’ll give a trigger warning that there are suggestions in this thread that there is a life beyond net metering for states serious enough to overhaul their distribution systems.

the inspiration for this thread was an order out of the @NYSDPS last week on VDER. The order made some significant changes to reflect the long run value of distributed energy resources and make the tariff FAR more financeable and more attractive for solar-plus-storage. (2 of ?)

the changes ALSO, and more importantly, are way better for the grid. VaDER is leaving the dark side. It is going to get to be the successor to net metering that is fair to solar customers and all ratepayers; we'll get there, folks (3 of ?)

Before I wonk out- you may want a primer or refresher. @NYSERDA's website on VDER is a great place to cut through all the regulatory filings and find some good primers they’ve put together. Props to @solar_dave and his team nyserda.ny.gov/All-Programs/P… (4 of ?)

As a plug, @NYSERDA also has a webinar TOMORROW on the VDER changes. nyserda-events.webex.com/mw3300/mywebex… (5 of ?)

Now, onto VDER.

Near term changes: One important one was a community credit that can help bring commercial customers into community solar & another was allowing for on-site NEM to be expanded to 750kW. These are changes that keep the market going. These changes are the things that pay my bills.

Indeed, while @Rev4NY has been DIRECTIONALLY right, it has not come without challenges. The market uncertainty effects have been a challenge. But to be fair, that is a function of MANY state solar markets and one which, hopefully, REV can get us beyond in the long term (7 of ?)

One criticism I have made of the REV process, as I did in this article, is that NY (unlike CA) jumped into a new tariff before doing the foundational distribution grid work. (8 of ?) utilitydive.com/news/unnecessa…

On the flip side, the state has forced stakeholders and the solar industry to think through a lot of hard questions about how solar meets grid needs and how they should be paid for that value. (9 of ?)

OK, so we talked about short run vales and some of the uncertainty created by REV, let's talk about the fundamental changes made that will matter for the long haul. (10 of ?)

LONG RUN importance: fundamental changes to the distribution value and the way generation capacity is paid for. In VDER’s value stack there are components for energy (day ahead LMPs), generation capacity (“ICAP”), distribution (DRV and LSRV) and Environmental (E) Value.(10 of ?)

DRV has embodied some of the problems I highlighted with a short run perspective on DER value I raised in my response 2 @JesseJenkins and @burgersb article last month. DRV was based on the utilities' distribution marginal costs (good), but only locked in for 3 yr increments (bad)

In effect, the DRV was intended to incentivize DERs to come and resolve needs for distribution capacity. But if those needs were met by DERs, and subsequently marginal costs fell, compensation for the DER that helped fix the problem diminished 3 years into their 20 yr + lives

DRV was akin to the utilities investing in a substation upgrade to meet load growth and after 3 yrs being told “hey, we no longer have a capacity constraint here because we have more capacity at this substation, so we’re going to remove this substation from the rate base”.

The solution in last week's order was to give DERs the same deal as the utilities. DRV is locked in for 10 years which is the same time span over which utilities depreciate assets in their ratebase. When DERs are on a level playing field good things happen!

by the way, I am giving up on the tweet count. just keep reading, damnit! : )

Another important change to DRV was the hours over which customers were credited for exporting (“injecting”) across the meter and into the distribution grid. Previously DRV was paid for performance in the 10 peak load hours of the year retrospectively.

At the end of the year it would be determined what the 10 peak load hours were in the year and, retrospectively, your system’s injections into the grid in those hours would be measured and compensated. That was how you were paid for distribution value.

Using my earlier substation analogy, DRV was similar to the utility being asked to build substation capacity to meet expected peak hours & subsequently being told “oh well, the actual peak loads this year were in these other hours so you don't recover that cost this year”.

the 10 peak load hours method for DRV was also flawed in its false precision. Each year there may be 10 hours that are way higher loads than the rest of the year, but that doesn't reflect the probabilistic nature of peak loads and good distribution system planning.

Peak loads can occur in a range of hours across the peak load months (afternoons and early PM in summer in NY). Particularly since operating NEAR peak strains dist. equip. & makes it age faster, incentivizing DERs to perform during a range of hours is better 4 the grid.

the new order establishes 240 peak load hours in summer afternoons (2 to 7PM). In addition to being better for the grid, it is WAY more financeable.

In the bad ol' DRV days, a project financier would have to assume that your system performed a certain amount during those 10 peak load hours. You’d also have to account for reasonable contingencies (e.g., being shut off because the distribution utility was doing work nearby).

Now DRV looks a lot more like a time of use rate. It is precise on grid value but also more predictable from a project financing and grid planning standpoint.

The DRV improvements are big. On gen capacity I wish my kin and I had made a push for a different methodology (cost of new entry, "CONE"). As CA decided 2 yrs ago, the value of DERs is their ability to avoid new power plants not their ability to avoid short run capacity needs.

SIDE THREAD: the argument against this is that California doesn't have a capacity market and therefore uses CONE because they don't have a capacity market. However, they have a backwards way of getting at the same thing- it is called resource adequacy.

SIDE THREAD (2 of 2): resource adequacy procurements are the same damn thing as a capacity market in this context. California is deeply scared by the energy crisis and there is all this funky stuff as a result but that is another thread for another night and more glasses of wine.

Through the generation capacity credit ("ICAP") DERs are getting paid NOT for the value of avoiding new power plants but instead the same cap. market rate given to already built fossil generators to keep them going ("cash for clunkers" as @tommatzzie has described it).

regardless, ICAP is better from a practical standpoint

is anyone still out there? I am going to keep going...

All of the above said, more is needed to be done to "fix" VDER. The underlying $ values that determine the DRV credits need to be examined through a more comprehensive review of the utilities’ marginal cost studies.

The underlying methodologies, as filed in the utilities’ distribution system plans (DSIPs) are all over the place and opaque on many key metrics such as the load growth assumptions.

The DSIPs and Marginal Cost of Service studies need 2 account for the state’s goals to electrify the economy 2 reduce emissions and include all investments DERs can avoid. This is some painful sh** that took CA several yrs and they still aren't done, so strap in.

New York also needs to figure out a value for avoiding transmission. As we’ve seen in CA, where @California_ISO cancelled over $2B in transmission lines because of DG solar and energy efficiency, avoiding transmission is super valuable. h/t to @TeamWetDog utilitydive.com/news/efficienc…

Right now New York only accounts for transmission by accounting for the congestion reflected in LMPs- i.e., if there is limited transmission to get power to where it is demanded, short term prices rise.

Gonna sound like a broken record here, but short run values do not reflect the ability of DERS to avoid putting new steal in the ground. They only reflect the costs you avoid on top of the already sunk investments in the near term.

Saying DERs are paid for transmission value through LMPs is like saying getting the extra cost of a cab fair in traffic is the value of highway capacity. Bear with me here..

Saying LMPs reflect transmission value is like saying that it would cost $30 to take a cab from Worcester to Boston if there was no traffic, but $50 with traffic, so the value of the highway is $20 for each cab on the road. However, that is not the cost of building the highway.

Lessons I take from this VDER order:

Lesson 1: Solar does well when it argues on grid benefit using economics and engineering. There is a tendency to fall back to what industry knows best which is what is required to get projects to pencil and be financed. Finaceability is the bottom line, not the policy arguement

Now that solar is beyond its toddler phase financeability is a weak, weak argument to make to win hearts and minds of regulators. Luckily, there are a lot of good arguments to make coming from a grid needs perspective; let’s fight from that high ground.

Lesson 2: Value has to be part of broader conversations about changes in the distribution utility. And I don’t mean rhetorical conversations; I am talking about integrated distribution system planning and performance based ratemaking.

Frankly most states are just not in a place to have a serious conversation about something beyond net metering because there isn’t a serious commitment to transparency and changes to the distribution utility.

A crazy recent example: In @GeorgiaPower's IRP the avoided costs in the utility’s cost benefit analysis are redacted (!) like they are part of some top secret report (in any other state I’ve ever looked this is public data)

In Illinois, where the state is expected to transition to value based compensation after hitting a 5% NEM cap, the utilities use embedded cost ratemaking and therefore lack marginal costs to work with.

Not only is it premature to move off of net metering in Illinois, the state doesn't have the basic ratemaking tools to do it.

And as @gabeaschan at UMN has pointed out, a lack of transparency on avoided costs has been an ongoing challenge in Minnesota and raises questions about the decline in value. In fairness to the PUC it seems like they are working on this. startribune.com/complicated-ec…

ah crap. Lesson 2 is before Lesson 1. Bear with me...

California is the closest to having a framework for distribution cost transparency with its Grid Needs Assessment. Washington DC is also working to get distribution investment data out of the black box that is distribution utility planning and rate cases.

As demonstrated in some of the crazy obfuscation last year, more scrutiny on distribution spending is very threatening to distribution utilities; this is an area worth fighting on. greentechmedia.com/articles/read/…

hello?

Lesson 3: value based tariffs can be sick-nasty solar-plus storage rates. I spent a 2 yrs working w/ rates folks way smarter than me trying to make TOU rates that are better for solar plus storage. We got there following standard rate design principles but it was hard to hold up.

Rates are, by their nature, meant to AVERAGE out costs and collect money— here is how much revenue is needed for the rate class and here is how rates are going to collect that cost; sending a price signal to customers is really a secondary objective.

Indeed, rates need to be revenue neutral (i.e., this rate will collect as much as another one in the class); if you create a super arbitrageable rate you are going to end up finding that rate on the chopping block in the next rate case

Value based tariffs, by contrast, reflect that value is way more concentrated. Rates effectively take the cost of all the distribution investments made to meet that peak and spreads it around the year. A value based tariff concentrates it into afternoons/evenings in the summer.

Of course, that leaves the prospect of basically getting wholesale revenues for much of the calendar year, but if you have load behind the meter you should have the right to offset it at retail rate. VDER is always at retail rate for anything that doesn't go beyond the meter.

Talking real dollars here— the National Grid credit for DRV is now 21c/ kWh and ICAP is about 9c/kWh (on top of everything else: LMPs etc.) for exports from 2 to 7PM late June- end of August. Put that in your pro forma and smoke it!

FInal Lesson: People love to hate on VDER, but that is a mistake. For all of REV's challenges it is the direction folks who care about distributed energy resources should be pushing.

Look at Connecticut's SB 9 and know that it is pretty easy for a presumably progressive state to throw up their hands on distributed resources when utilities offer something else on the climate menu.

Reforming the Energy Vision lives on and let's keep working on it!

...ok, I am really done now.

For the skeptics- DM me your hatemail. Also, I have shirts available.