Getting Comfortable with DER Level Merchant Risk: Part 1

Written by: Tom Michelman, Senior Director and Distributed Energy Resources (DER) Practice Lead
Publish Date: September 7, 2022
Estimated Reading Time: 10 minutes

So as not to bury the lede, SEA has conducted (and continues to conduct) a plethora of Distributed Energy Resources (DER) market research and analyses to underpin DER $/kWh forecasts that have been leveraged by its clients internally and externally (e.g., with debt and equity investors).

To the topic at hand this blog, “Getting Comfortable with DER Level Merchant Risk” is the title of and is written accompany both a “Showfloor Session” and a Poster to be presented at RE+ 2022 September 19-22, 2022 in Anaheim, CA by SEA Senior Director and DER Practice Lead, Tom Michelman.

Distributed Energy Resources Revenue & Risk – An Introduction

Gross DER project revenue in dollars is defined as:

$ = kWh production * $/kWh

Clearly the kWh production is as important as the $/kWh rate in garnering revenue, but the RE+ 2022 presentation only focuses on the $/kWh part of the equation.

Further this blog focuses on $/kWh gross rate variability; it leaves to another time discussion of factors that erode the gross $/kWh revenue to net $/kWh revenue realized by a project, including offering / managing offtaker savings, offtaker payment risk, community solar or offtaker management, electric distribution company (EDC) costs, etc. 

Thus, the presentation would be better entitled “Getting Comfortable with DER Level Merchant Gross Revenue Rate Risk”. 

With that introduction, the balance of this Part 1 blog

  • First describes what portion (components) of the gross $/kWh rates are variable and thus are facing “merchant risk”. 
  • Second describes the magnitude and variability of gross $/kWh rate components
  • Third provides examples of the drivers of the variability of gross $/kWh rate components
  • Finally, describes how market participants are embracing gross $/kWh revenue variability 

Components of DER Incentive Program $/kWh Rates

The table below displays for a sample of DER incentive programs what components receive a fixed $/kWh rate for the program life, and what components do not receive a fixed (i.e., variable) $/kWh rate. As can be seen, DER incentive programs vary widely in the composition of components that can be claimed by a participating project, and what components are provided at a fixed vs. variable $/kWh rate.

Acronym key: ADI = Administratively Determined Incentive; BTM = Behind-the-Meter; DBI = Declining Block Program; DRV = Demand Reduction Value; E = Environmental Value; FPPCAC = Fuel and Purchased Power Cost Adjustment Clause; LBMP = Locational Based Marginal Price a/k/a energy value; LSRV = Locational System Relief Value; NEB = Net Energy Billing; NM = Net Metering; RECs = Renewable Energy Certificates; SRECs = Solar Renewable Energy Certificates; VDER = Value of Distributed Energy Resources.

Magnitude and Variability of Gross $/kWh Rate Components

The degree one even cares about $/kWh rate variability is the degree to which a project relies on the component revenue stream for project revenue. Thus, all things being equal, the greater the magnitude of a variable component and the greater variability of that component, the more one cares to understand, manage, and hedge against the $/kWh volatility. 

Per the above table Central Maine Power (CMP) retail rates directly affect CMP NEB rates. Figure 1 below provides a great example of significant retail rate volatility.

Figure 1: CMP Rate SGS Total Wire & Standard Offer Service Rates

In Figure 1 the clustered bar shows 1.6 cents/kWh increase in total wire charges from July 2020 to August 2021, and then a total wire charge decrease of 0.6 cents/kWh in July 2022. It also shows the CMP Standard Offer Service rates (the other portion of CMP retail rates which flow directly to NEB rates) which also has varied widely in the last few years (e.g., 6.4 cents/kWh in 2021 to 11.8 cents/kWh in 2022).  Finally, the brown line provides the implied NEB kWh Credit rate value with its relative stability through August 2021 and the dramatic jump in value in 2022. The NEB Tariff Rate value variant is closely related but calculated differently.

From inspecting the graph, an obvious question is whether the price increase is a new normal or whether the retail rate price increases and thus NEB Credit Rate rates are transitory. 

If such wide rate variation doesn’t grab your attention, then you might as well stop reading the blog here.  Every Maine NEB market participant cares about such huge price swings as they impact how much and costly are project investment debt and equity, and how much projects can be sold and for. 

Now, of course, not all markets have such large annual swings as the Maine NEB market, but that’s the point. To appropriately get comfortable with a market, one should understand, at a minimum, how the rates have varied over time.  

Drivers of the Variability of Gross $/kWh Rates

Looking through the initial table, the variable rate components can be grouped into the following three categories:

  1. Wholesale rates
  2. Retail rates and retail rate derivatives (e.g., NM and NEB)
  3. Tradeable certificates (i.e., RECs and SRECs)

Wholesale rates are pass-through of wholesale market prices with all the inherent price volatility.  In the table above of example programs, the NY VDER market is one that best typifies unbuffered pass-throughs of wholesale market prices, where the compensation of energy and capacity components are based directly on the production weighted average wholesale NYISO energy and capacity prices. A main driver of NYISO energy volatility is natural gas prices, and a main driver of NYISO capacity prices is the supply of MW that can qualify for capacity accreditation. 

Most other DER programs that have revenue rate variability, pass that variability on as function and derivative of retail rates rather directly as wholesale rates. Thus, while the Maine NEB rates are a function of all retail kWh charges of a program participant, many programs only include some of the components of retail rates (e.g., energy, energy adjustments, and transmission for the ComEd Illinois Adjustable Block program, and all those components, plus RECs for New Mexico Community Solar program). 

Going one layer deeper, in many markets the generation portion of EDC retail rates are a function of the wholesale and energy capacity prices at the time of the default service (also known as basic service, standard offer service, last resort service, etc.) procurement. Like just about everything else in the DER world, how the default service procurement works and what is being procured varies by EDC and customer class. For many EDCs default service procurements are layered in such a way that a fraction of the generation is purchased at one time in order to buffer the ultimate price variability, with separate purchases for winter vs. summer products. 

Wire charges are generally comprised of separately calculated distribution, transmission, stranded costs (also known as transition), energy efficiency and miscellaneous charges, with many of these comprised of a base charge and various adjustors and adders. It is not unusual to see a half-dozen or even a dozen or so adjustors to a base distribution charge. 

Base wire charges that pass through to retail rates are generally a function of the cost of service (investment, and approved rate of return on investments), kWh over which those costs are spread, coincident peak demand, true-ups to adjust for difference of estimated costs incurred and revenue received compared to actual costs and revenues.

Figure 2, below, displays how each of the CMP wire charge components changed over the same time period of the above figure. While the variability of the wire charge components is not as dramatic as the variability of the Standard Offer Service rates in the graphic above, the same compelling questions regarding the future wire rates still apply (is it the new normal or transitory?), as 1.6 cent/kWh variation is still a significant swing in most market participants’ books. Specifically, what has driven the variability in CMP transmission, distribution, and stranded cost rates? In this case the primary drivers include increase in FERC approved ISO-NE regional network service costs and true-ups (transmission), investment and deferred costs (distribution), and a rate case Stipulation (stranded costs). 

Figure 2: CMP Rate SGS Wire Charges by Component

Understanding the drivers allows forecasters (e.g., SEA) to provide insights and justification to the likely direction and magnitude of future rate components that make up DER variable $/kWh rates.

Finally, some markets are structured so that the tradeable certificates (RECs, SRECs, CPECs, etc.) are part and parcel of the project variable revenue stream. The drivers for tradeable certificate prices are a function of supply, demand, market rules (e.g., price caps, price floors, banking options, etc.). Suffice it to say to appropriately forecast such markets requires market fundamentals analysis. For many of these tradeable certificate markets SEA provides best of class market fundamentals analysis via subscription services. They include:

Embracing Gross $/kWh Revenue Variability?

In preparation for the RE+ 2022 Showfloor Session, we have spoken to almost a dozen market participants specifically about how they are dealing with $/kWh revenue rate variability. The big picture take away is that it varies widely.

Some market participants love the market volatility. The deeper market research and analysis they conduct is their edge. Conversely the lack of revenue variability (e.g., feed-in-tariff) requires less analysis, attracts a more conservative set of market investors, (all things being equal) cheaper money, requiring lower returns.

Some market participants deal with $/kWh revenue rate variability by laying all or much of the rate risk (as much as the market can bear) on their offtakers by proffering fixed rate deals. Such a strategy leads to counter-party risk, but some market participants feel more comfortable managing counterparty risk versus variable $/kWh rate risk. 

Finally, a different strategy is to leave the variable $/kWh rate risk to others by selling a project or project portfolio before operation (e.g., at notice to proceed).

In Part 2 of the blog, I will provide more details of what we learned from market participant discussions.

If you would like to discuss $/kWh rate risk and/or the various analysis SEA can conduct for you do not hesitate to reach out ( or see more information here.

Hope to see you in Anaheim.

Part 1 of the blog is a detailed addendum to the poster with additional background and analysis that won’t fit on a poster of “Showfloor Session”.

Part 2 of the blog will present top level findings from the “Showfloor Session” (which will take place at Industry Trends Theater, Booth #1694, from 3:30-4:00pm on Tuesday September 20, 2022) and will be published after RE+ 2022.