DER Singularity – The Need to Think Distributed
- Posted on August 16, 2018
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Similar to Ray Kurtzweil’s computing “singularity” where the computing power of machines matches that of humans, the power and utility industry faces a similar future. Electric power has been delivered in the same way for more than 100 years – bulk power -> transmission -> distribution. With the introduction and rapid adoption of renewable energy and energy storage (a type of Distributed Energy Resource or DER), the traditional paradigm is transforming. In about the same timeline as Kurtzweil’s singularity (~2030), DERs will deliver much of the power needs for society. Although grid-scale DER systems may be viable solutions for bulk power and transmission, these changes will primarily affect the distribution networks as utilities add distributed generation (spinning mass, renewables, and energy storage) and end consumers add rooftop solar, energy storage, and energy management systems. In fact, if you listen to the car companies, many end consumers will soon have mobile energy storage DER systems in their garages, parking lots, and on the road.
The introduction and rapidly growing DER penetration onto electric power distribution networks has created complex issues for an industry that has operated from a centralized command and control philosophy for over 100 years. Utilities have little or no visibility of behind-the-meter DER assets. Centralized Distribution Management Systems (DMS) were designed for traditional grid assets, not highly distributed DER assets. In the meantime, the number of rooftop solar photovoltaic (PV) installations and energy storage devices is accelerating as prices drop, electricity prices increase, and societal awareness of global warming and pollution become a “call for action”. Aggregators of PV and energy storage are using this opportunity to create new business models that participate in the energy market and even sell power back to local utilities.
On the electricity demand side of the equation, utilities are incentivizing end user customers with lower energy bills by reducing loads during peak power conditions by curtailing or reducing energy consumption with controllable loads. This conundrum of increased penetration, demand response, and the difficulty in seeing and controlling DER assets has created new problems on distribution networks using yesterday’s technologies – unpredictable and uncontrollable energy supply (behind the meter), load shifting due to photovoltaic (PV) penetration, reduced energy consumption (and sales) from traditional bulk power plants, and the need for much different distributed energy management solutions that intelligently work with utility-owned and customer-owned DER assets, creating the ability to interoperate and contribute to grid stability instead of creating chaos and instability.
At the same time, we are also seeing an interesting movement in home automation. After many false starts and missed opportunities, companies like Amazon, Google, and Apple are embracing consumers’ new appetite for managing home entertainment, lighting, security, and HVAC systems. There were over 10M Amazon Alexa-enabled devices sold worldwide at Christmas in 2017. Soon home automation and DER management systems will converge with the ability to autonomously manage loads and dispatch power to the grid to balance local distribution and feeder networks. With new Alexa third party energy management apps – or a new device altogether – home energy management and connectivity to utility systems either individually or through third party aggregators will someday create an end-to-end energy ecosystem that leverages DERs no matter where they are or who owns them, reduces utility power generation and transmission costs, reduces the overall costs of electricity, and creates new business model opportunities for utilities, customers, and innovators.
The profound transformation from a centralized to decentralized electric power ecosystem requires brand new thinking and innovation. It is imperative to have a corporate vision and a roadmap that builds the utility’s DER management capabilities in an ambitious, practical approach. It requires a centralized “supervisory” capability that coordinates and manages (not controls) DER assets and a DER peer-to-peer low latency field message network to self-manage and intelligently react as a system to local conditions and events. DER integration will require a distributed hierarchical control system that allows a utility Distributed Energy Resource Management System (DERMS) to provide situational awareness and interoperate with utility-owned and non-utility-owned DERs in front of and behind the meter.
This is complicated stuff. And, it’s a speeding bullet train coming to utilities faster than you might think. In California, the Public Utility Commission regulators have the ambitious goal of achieving 50% of the state’s electricity through renewables by 2030 and 20 GW of renewable energy supply by 2020. The CPUC focused on interoperability technology with legislation like Rule 21 addressing smart inverters and developing a common set of capabilities and interconnection interfaces that help enable reliable grid operations. The AB-2868 legislation incentivizes the 3 major California Investor Owned Utilities (IOUs) to install feeder-level energy storage (10 MW+) that supports both market and reliability operations. And, the California Energy Commission recently passed a mandate that requires all new homes built after Jan 1, 2020 to include rooftop solar! This is huge and will have an enormous impact not only to the solar panel installation industry, but also provide new technical and financial challenges to utilities in managing and planning their distribution networks.[MS1]
Although anything is possible, it is unlikely this innovation will come solely from the traditional utility software vendors. It is more likely to be a mix, merging traditional vendor solutions and Internet of Things (IoT) vendor solutions, with the traditional vendors supporting the supervisory control needs (forecasting, measurement & verification, SCADA, OMS/DMS, GIS) within the utility back office and operations centers and the IoT vendors addressing DER peer-to-peer field communications, cloud, block chain, artificial intelligence, and deep learning capabilities which are obvious evolutions that will eventually be incorporated in this complex, highly distributed, non-homogenous system of systems.
DER integration into the utility’s business operations is the “eating an elephant” analogy. It’s a big animal and needs to be thoughtfully eaten one bite at a time. For each individual utility, the path is unique and depends on regulatory drivers, business models, customer mix and behavior, budget and cost recovery rules, legacy equipment and systems, technologies, geographic location, weather, topography, and grid topology. However, the standard software development lifecycle applies – design->develop->test->deploy->commission->decommission. The DER integration software development should be done iteratively one bite at a time, gradually introducing, testing, and deploying progressively more meaningful DER capabilities over time. Translated into a project portfolio, it looks something like the diagram below:
The point is that that DERs introduce a truly transformative opportunity for utility companies, but bring with them complex business and technical challenges that require a disciplined and systematic approach. To be successful, It requires executive leadership and vision, clear understanding of objectives throughout the organization, good roadmap planning, strong governance and oversight, and good communication. Although each utility’s end system may be unique, the challenges and problems are not. In these early days, utility companies should be looking externally and collaborating with one another – jointly developing requirements for common needs such as field messaging communications, integrating with home energy management and building energy management systems, hosting capacity calculations, interconnection processes and automation, measurement and verification systems, forecasting systems, and integrated planning systems. Utilities should also recognize that DER assets should not be treated as “one-offs” and will soon become standard assets that should be planned, procured, managed, and controlled alongside traditional utility assets, eventually using the same systems for DER assets that they use for today’s assets – but we aren’t there yet.
Even before “DER Singularity” becomes reality, utility companies cannot put their heads in the sand and wait for solutions to come along. Instead, they need to acknowledge that DERs and distributed operations are the new reality, and actively plan, collaborate, and properly prepare the organization with clear objectives and expectations. This is not an AMI program. It is a fundamentally different challenge for utilities which touches every single aspect of the business including customer engagement, market operations, distribution operations, IT back office systems, workforce training, and distribution planning. Several progressive utilities have already begun this process and there are joint activities like the IEEE P2030 program and the Open Field Message Bus (OpenFMB) that are addressing some of the larger gaps that exist. Still, there is no vendor solution that meets all of the different DER integration challenges and there are numerous problems that remain to be solved.
DER Singularity is approaching. The train has left the station and its picking up speed. Utility companies’ businesses will be impacted (negatively or positively) well before that. Have you developed a corporate strategy and roadmap for how you will incorporate DERs into your business? Are you preparing your organization to experience a fundamental transformation in how it manages the grid and engages with customers? If not, these are conversations that should be going on in every board room to start the process to understand the potential impact in your territory and begin planning accordingly.