The Fractal Grid: Part II
Pricier Wires – The price signal chimera – Interconnection bottlenecks
In Cheaper Energy, Pricier Wires, Duncan highlights how delivery costs have become proportionally greater than the cost of generating power on many electricity bills throughout the US. This trend reflects the importance of optimizing consumption and generation at the grid edge in order to reduce the cost of delivering power, a service that Distributed Energy Resources (DERs) have the technical capabilities, yet limited financial incentives, to provide.
An advantage of DERs is that they can be programmed to provide a variety of beneficial services, comprising a full “value stack”, because they are located at or near final points of consumption. Subsequently, to reach their full potential, this value stack should offer a suite of complementary price signals so asset owners can smoothly arbitrage between revenues from different levels: wholesale markets, distribution system optimization, and community or on-site resilience. Even now, with many fractured and arcane program compensation structures throughout the stack, co-optimizing between multiple levels increases the likelihood of deployment; paying back the upfront cost of a resilience-focused asset with market revenues or obtaining marginal resiliency benefits from an asset primarily deployed for financial reasons can help a project pencil. The deployment rationale depends on the particulars of each asset, as load shifting devices like smart thermostats cannot provide on-site resilience and there isn’t as much of an economic or climate case for diesel generators. But overall, the ability to co-optimize between different value streams should enable DERs to meet the most pressing need at each temporal and geographical juncture on the grid, creating a virtuous cycle where local price signals stimulate DER adoption and alleviate the constraint until grid conditions evolve and form new price signals.
However, consumers considering adding a DER have limited mechanisms to access the full stack because the quality, unity, and form of the available price signals are complex and clunky. To reflect the full cost of generating and delivering power, as well as the value of modifying behavior to reduce these costs, any given DER receives a smorgasbord of static time of use rates, demand charges, and baseline methodologies depending on the particular utility, ISO, and program. Sometimes, price signals even contradict one another (case in point: co-optimizing time of use rates and baselines). Nowhere are price signals more static and ambiguous than those reflecting delivery costs from the distribution grid, which materialize as top-down, bespoke demand response programs for short-term constraints and vague delivery charges and NWA pilot projects for long-term constraints.
The key reason these price signals are of such poor quality is that operating the network in real time is entirely independent from interconnection analysis, which determines whether new sources of generation or load will violate the constraints of the equipment serving the site. The essence of NWAs is to circumvent the need for upgrading grid infrastructure in response to an interconnection request by maximizing the usage efficiency of existing poles and wires. This can be done by using the flexible consumption or generation offered by new or existing DERs to modulate power flow on distribution networks and avoid the constraint. Suboptimal usage and awareness of existing distribution infrastructure limits interconnection. If five homeowners on the same secondary circuit want solar but their shared transformer can only handle the maximum generation of three, two homeowners don’t get to interconnect their DER even if they’re drawn by the resiliency benefits or financial incentives. However, if one or more homeowners use batteries to modulate the generation of their solar + storage systems and avoid the constraint, it could make economic sense for all without requiring an upgrade.
Enabling these types of projects to proceed requires embedding the price signals for load shaping with the interconnection and distribution planning processes. This would enable my rooftop solar proposal to distribute mini-RFPs to the stakeholders on my local network to see who might be willing to add a DER in a strategic location or modulate their load for the right price. By the same token, a utility considering larger infrastructure upgrades could beam out RFPs to DER developers for coordinated deployment and operation of flexible devices. And some do.
However, current interconnection studies are primarily performed via physical site visits, emails, spreadsheets, and creaky, siloed power flow software. Some tools like hosting capacity maps alleviate the initial tediousness and have been folded into the interconnection process to a certain extent, but as many developers can attest, interconnection is a slow and painful technical process that takes several months to complete and often ends with an upgrade fee that breaks the project. Additionally, most of the few recognized NWA opportunities do not get implemented because the opaque cost-benefit analyses completed by utilities routinely deem decentralized solutions to be more expensive and less reliable. Even in New York’s Value of Distributed Energy Resources tariff, arguably the closest practical implementation we have to a theoretical ideal, the Locational System Relief Value (LSRV) is not available for all DERs and is completely at the discretion of the utility.
In Justin Gundlach’s seminal paper on the value stack, notice how distribution system capacity value is updated roughly every decade.
As electrification and deployment of distributed generation impose service upgrades, the current processes for distribution interconnection, planning, real time network management (via ADMS), and real time DER management (via DERMS) should fuse together to evolve past siloed, project-by-project analyses into a true dynamic system of constraint identification and alleviation through the cheapest possible means. But today, not only does locational value trickle into the value stack, but the fragmentation and opacity of these services stymies DER installation. When comparing the state of interconnection and NWA assessment to the exponential demand forecasts for EVs, solar, storage, heat pumps, and other DERs produced by every market research firm, DER growth seems more quixotic than inevitable.
To break this barrier, utilities need greater awareness of when, where, and how flexible energy devices can squeeze greater efficiency out of their infrastructure and ensure the trustworthy coordination of decentralized assets. This requires data.
Continued in Part III.
Also note that there are a large number of ways that non-network services can be procured...
1. Tariffs/rates that are dynamic and/or locational
2. Direct procurement (contracting)
3. Flexibility platforms for trading NWAs
Each approach has pros and cons. The future probably requires some rates/tariffs working in tandem with some sort of procurement platform.
FYI - the Australian Energy Regulator has implemented a similar concept to the NY VDER. It is called the Customer Export Curtailment Value (CECV). The CECV places a value of DER exports and requires the local networks to augment the grid when the cost of doing so is less than the overall benefit of more DER generation.
Ref: https://www.aer.gov.au/networks-pipelines/guidelines-schemes-models-reviews/customer-export-curtailment-value-methodology