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To DER or not to DER? That’s no longer a question for utilities

Venk Gopal's picture
Director, Consulting, CGI

Venk leads the emerging business initiatives to address the utility sector's transformational 4Ds - Decarbonization, Digitization, Decentralization and Democratization.  Venk focuses on...

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  • Feb 1, 2021
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The electric sector is in a time of unprecedented changes, with the new US administration accelerating the adoption of Distributed Energy Resources (DER).  The technological advancement combined with practical and affordable ability to generate and store energy in smaller units has created a disruptive effect on the energy market establishment, on the roles of utilities and regulators and on the nature of the distribution grid.

With all due respect to the Shakespearean soliloquy, this welcoming disruption poses both a challenge and an opportunity for distribution utilities, grid operators and regulators.  The journey and approach towards this transformation will be unique, with each utility company guided by varying legislative paths, its stakeholder alignments and its enterprise vision for the modernized grid.

Transformation of the market

Traditionally, the grid interconnect and wholesale energy market processes were closely coordinated among grid operators and the generation companies.

In the new paradigm the regulated utility network operator will be mandated to facilitate the interoperability between the grid operator and the new market entrant – the Aggregator or DER Provider.

The targeted market landscape is also completely transposed creating significant challenges. It must now support thousands of low cost, small capacity energy resources operating inside the utility distribution network. This is in stark contrast to the traditional model of a few dozen high capital, large capacity bulk energy resources that operate outside of distribution network, managed by transmission business units or similar entities.

Transformation of the utility network operator

The utility network operators face multiple challenges with regard to the visibility, tools, and resources (e.g. skilled staff and data insights) needed to manage a growing number of DERs. The transportation electrification trends and advanced battery storage technologies has enabled vehicles, homes, and businesses to serve as distributed energy resources (DER) in addition to consuming them. This marks the initial baby steps for the utility network operators as they metamorphose into a new role commonly referred to as “Distribution System Operator” (DSO). 

This new role extends further than responsibility for the DER interconnection and traditional network operation roles. In addition to these changes (some of which are outside of their control), they are required to implement new processes and systems to engage and interoperate with their customers who in turn are also transforming into two-way power moving prosumers. DER footprints typically include energy storage facilities, which when deployed at strategic locations within the grid, enable the utility companies to dynamically manage supply and demand while maximizing the value of grid resources. The utility companies will now be required to include these DERs into their distribution plan for regulatory submission and identify capital deferral opportunities.

Transformation of distribution planning

The new asset categories with DER classifications, in addition to being an energy resource, perform certain grid reliability and resilience functions such as frequency regulation, voltage support and backup power – all of which needs to be managed, tracked, accounted for and compensated.  The approach to distribution planning will now need to expand its traditionally inward focused grid objectives to adopt broad prosumer and societal objectives that include de-carbonization, flexible resources, dynamic power quality impacts and other DER dependent variables.

Typical distribution planning has six cyclical steps – load forecasting, system assessment, grid upgrade requirements, solution development, project construction, and system monitoring/control.

In the new integrated distribution planning, the DER related data is integrated at every step of the cyclical process.  The location of these DERs on the grid will be a combination of Behind-the-Meter (BTM) and Front-of-the-Meter (FTM), managed by new market players.  This will require integrating and/or extracting data beyond the utilities network operators, from prosumers, DER providers, aggregators and grid operators. In the very near future, the lack of digitized processes and/or data, may lead to large grid interconnection backlogs and the utility company may be subject to penalties.

Transformation of the regulatory model

Within the North American electric sector alone, several state legislative initiatives have set aggressive energy storage targets, while encouraging capital deferrals, de-carbonization, performance incentives and mandates. These initiatives have also enabled innovative business models (e.g.) Bring Your Own Device (BYOD), allowing residential customers to deploy their preferred battery storage and to connect to the grid.   

In September 2020, the US Federal Energy Regulatory Commission (FERC) issued Order No. 2222 that accelerates DERs such as rooftop solar and storage participating on a par with traditional generation plants in the regional organized wholesale energy markets. The new administration is expected to expedite and expand on the related policies as well.

With all these aggressive drivers, the US Energy Information Administration (EIA) is expecting more than 8 GW of renewables combined with storage projects to go online by the end of 2023.

Enabling and navigating all the above transformation

From CGI’s discussions and surveys with both North American and global utility companies in the recent months, we have consistently observed the need for the digital insights to effectively adapt these transformations at a pace aligning with the regulatory, customer engagement and shareholder goals

In the upcoming blogs I will be exploring several business use cases and capabilities required in the new modernized grid and utilities, including convergence with transformation in other sectors such as transportation electrification and telecommunication private LTE.

Discussions
Matt Chester's picture
Matt Chester on Feb 1, 2021

Typical distribution planning has six cyclical steps – load forecasting, system assessment, grid upgrade requirements, solution development, project construction, and system monitoring/control.

In the new integrated distribution planning, the DER related data is integrated at every step of the cyclical process.

That's a great point, Venk-- and I would imagine another reason why AI/ML will become even more critical on the grid

Venk Gopal's picture
Venk Gopal on Feb 2, 2021

You are spot on Matt. 

We see AI/ML playing a prominent role starting with the planning process.  For example in the states with the requirements for Integrated Resource Plan (IRP) from the regulated utilities, I envision the possibility of leveraging AI based models on scenarios towards their forecast and also need the machine data to input into their development and implementation plans. Some of the states are requiring the inclusion of new assets such as energy storage and renewables part of the IRP.  To achieve such capabilities, I expect  the IRP supporting modeling software suites with stochastic (probabilistic) methods to look for ways to integrate AI as well.

About a year ago we launched a ScaleAI initiative, where we are funding certain efforts to collaborate with Utility companies in developing certain distribution models for future asset planning. We are considering several use cases such as Vegetation Management, Energy Storage, Renewables deployment, power delivery model reconciliation, etc.

Matt Chester's picture
Matt Chester on Feb 2, 2021

Thanks for the follow up-- the vegetation management application is interesting because it's not where the mind first goes (where as actually modeling where/when/from what generation goes does). Is it a matter of using AI to predict where vegetation management will be most needed, or combining with sensors to identify potential trouble spots? 

Bob Meinetz's picture
Bob Meinetz on Feb 1, 2021

Let me explain a bit why the "new paradigm" of Distributed Energy Resources DERs, from a place in the U.S. where they're popping up all over (California), is a scam:

  1. So-called Community Choice Aggregators (CCAs) are not regulated by the state government. At all. The can tell you the're selling you a "100% Solar" plan, or a "200% Wind" plan, then sell you coal-fired power from Wyoming. And if they can, they will.
  2. Not only will they not tell you from where they buy your energy, but they're protected by state law from having to tell you. It is literally impossible to verify what you're getting in your power mix.
  3. Every customer to whom I've spoken, who has "defected" from their utility to a CCA, has complained the price of their electricity has risen.

By all appearances, CCAs are nothing but middlemen selling you the same electricity your neighbors are getting at a higher price (ask an electrical engineer, it's how the grid works). If they tell you it's a 50% Wind / 50% Solar Plan, and it helps you sleep at night, maybe it's worth the money. But for what it's worth, they're lying.

I'm hoping a CCA rep reads this and shows me documentation of how Customer A, with his 50% Solar / 50% Wind Plan, is being delivered what he's paying for. But I'm not, however, holding my breath.

Venk Gopal's picture
Thank Venk for the Post!
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