My formal involvement in DER integration work with Utility Wind Integration Group (now UVIG) dates to 2004. Many of the specifics have changed since then, but I would offer the same forecast in 2017 as in 2004; we are entering a new period of uncertainty, challenge and opportunity related to DER. In updating the U.S. Department of Energy (DOE) SunShot Initiative goals for 2030, the DOE recently noted that it’s 90% of the way toward meeting its 2020 cost goal of $0.06/kwhr for utility-scale solar. This progress has been achieved in about half of the time that was allotted back in 2011. On the technical side, IEEE Standard 1547 had just been approved in 2003. It regularized interconnections, but with important limits as DER could not participate in voltage regulation and had to trip at the first sign of trouble on the grid. With an amendment in 2014 and a full revision expected in 2017, IEEE Standard 1547 is now facilitating voltage regulation and ride-through. Grid integration studies are now much easier, with UWIG providing critical early funding to help develop the tools. Now a variety of tools and methods are available from EPRI and several software vendors. Many utilities, consultants and researchers now have experience with hosting capacity and impact studies.

These are all signs of a maturing DER industry, one that may be on the verge of a tipping point. We should probably start looking for business cases that don’t rely on incentives, and for integration methods that don’t rely on special mitigations. For example, smart inverter functions can provide a useful method of dealing with voltage problems at high DER penetration levels. However, we’ve become fascinated with all of the functions, modes and settings that can be defined, and then possibly modified with real-time dispatch. This has unnecessarily complicated practical application. What the inverter industry really needs is a control scheme that works with factory defaults, and without requiring high-performance communication systems. This could be accomplished with a single new adaptive control scheme, if the industry is open to the idea. If not, the best starting point would be the “dynamic reactive current” function with no deadband, supervised with volt-var and volt-watt functions to mitigate overvoltages (see how complicated that sounds?).

Moving toward the business side, how should the DER owner be paid for use of smart inverter functions? When mitigating voltage fluctuations with reactive power only, the smart inverter’s kva-hours will usually increase by a few percent. In other words, the cost of providing this ancillary function may be low, but its value to the grid could be significantly higher. Whenever the volt-watt function comes into play, the DER owner’s cost becomes much higher due to curtailment. The utility does have alternatives for voltage control, and those options ought to be evaluated on the same basis as smart inverter functions. The primary value of DER energy export also needs a more sophisticated treatment, as we should expect to see less use of net metering and other incentives going forward. Again, this is one sign of a maturing industry.

Transactive energy systems can provide the framework for managing DER on the basis of economic value, just like bulk generation, demand response, infrastructure, etc. If the term is new, start here http://www.gridwiseac.org/about/transactive_energy.aspx for more information. There have been a few pilot projects, with more on the way. For the DER owner, we could imagine a full implementation with local controls and bidding agent software, linked to a robust and transparent market clearing mechanism through the smart meter. Maybe it starts with a day-ahead market for DER ancillary functions, along with demand response as applicable. Focusing on just the DER, the utility could request bids for blocks of scheduled reactive power (like virtual capacitor/inductor banks), or for the smart inverter function to be turned on, just for the following day. This minimizes the communication requirement while providing some of the operational benefit.

It’s much less clear how to create a binding market mechanism for variable DER energy exports.  One of the projects we have underway at Pacific Northwest National Laboratory (PNNL), called the Transactive Energy Simulation Platform (TESP), aims to address this question and others like it. The TESP incorporates time-series electrical simulation of the distribution grid, which UWIG helped to pioneer starting in 2004, with agent-based market simulations and transactive energy valuations that were pioneered here at PNNL. It’s a very interesting project. More importantly, it should help us answer tough questions like what’s the capacity value of DER, what’s the value of storage, and what comes after net metering for DER? The industry will need those answers for DER to compete on a level playing field.

Thomas E. McDermott
Chief Engineer, Integration
Pacific Northwest National Laboratory