Posted to Utility 2030 Collaborative in the Digital Utility Group
Vanessa Edmonds's picture
Executive Director & Advisor Utility 2030 Collaborative & Appos Advisors

Transformation strategist, speaker, and writer who pursues solutions to help utility leaders reinvent the customer experience. Honored to be leading people-centered utility transformation...

  • Member since 2014
  • 53 items added with 54,269 views
  • Aug 16, 2022

New innovations are coming at us faster than ever before. That means the time-to-market has shrunk considerably. Please share your thoughts on overly hyped innovations versus those utilities should actually be considering.

#themetaverse #voicebots #acceleratedartificialintelligenceautomation #machinelearning #optimizedtechnologistdelivery #evolvingimmersiveexperiences #NFTs #clouddataecosystems #foundationmodels #digitaltwinofthecustomer #internaltalentmarketplace #digitalhumans #superapps #web3 #decentralizedidentity or something else????

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Hi Vanessa:  If you want innovative, here are two concepts that utility companies around the world should be implementing now.

1. Rooftop Solar - Every roof that is not currently being used to produce energy in their service territory needs to be equipped with solar panels and/or urban wind turbine and a suitable battery system for the home/building at the utility's expense.  The utility should pay for the installation, install a proper meter, and charge the building owner for the electricity produced by the system just as they do now. 

2. Underground power lines - Every new electric line, both last mile and high voltage transmission, needs to be built underground. Those lines that pass through sensitive areas need to be placed underground as well.  Climate change will only create worse results in the next many years.  The utilities need to understand this and implement a comprehensive resiliency effort now.

Thanks for asking.  Hopefully they pay attention.

Jim Horstman's picture
Jim Horstman on Sep 26, 2022

Undergrounding is a good idea where it is practical. However, in mountainous environments the practicality is about zero especially for transmission which traverses steep mountains such as in California. Covered conductor is being used in the distribution space by SCE along with better monitoring and control to reduce the chances of ignition.

Where I live (Northern California) there is an overwhelming need to increase electric grid resiliency, in two ways. The first I covered in a post in July, which was an update of a post about a year ago (linked in the July post). This post is described and linked below:

PG&E Network Hardening – 2022 Update: PG&E released an annual update to their Wildfire Mitigation Plan earlier this year. This post will be an updated summary for that document and provide other information on PG&E’s efforts to harden their transmission and distribution networks, and thus reduce wildfire risk in their service territory.

The second issue became more immediate this week as we had a many-records-broken heat wave (both duration and peak temperatures). As I was describing this to one of my Energy Central, he suggested that I post a paper on this (I normally post two every week). I am seriously considering this, probably later this month. 

The good news is that CA-ISO, PG&E et al managed to avoid rolling black outs, although transformers were failing left and right resulting in many major outages.


Thank you for posting this topic. In order to be competitive and more customer facing, utilities will adopt more back-office efficiencies, such as artificial intelligence. New applications in the finance, customer service and billing, and in field mobile tools will lead to greater efficiencies, especially needed in light of labor shortages.

I would answer the question by posing the question to address current issues/problems/challenges

What innovations should/could utilities be considering for solving the current problems/challenges below?:

(utility = energy)

  • Emission (climate change)?
  • Excessive high demands during extreme weather patterns (heat wave / extreme cold fronts)
  • Power blackouts due to excessive demands
  • managing large amounts of DERs, especially if spread out over large geographical and remote areas
  • Managing energy transactions / trading between the main grid and microgrids, etc.,
  • Energy storage e.g., battery technology
  • Transport of Energy, e.g., hydrogen
  • Energy asset management, including DERs
  • Delivering value-added services / insights to end users, rather than just commodity (e.g., power).
  • Operation and management of community owned microgrids / DERs, etc.,


I'm sure there are more to add here.

We are moving from the academic to the practical application at a time when so many things are changing. Like all change management, there is a need to step back and for every part of the grid, in any global location, to ask, "To What End?" In essence, what are we trying to accomplish and then evaluate those innovations that can achieve that objective in the most cost-effective, successful way we can. I recently had the experience of being part of a presentation to upgrade the testing capabilities for substation assets but the manager it was presented to was not at all interested. Why? Change and the amount of work it would take for him to manage it. 

Later, the same presentation to more senior engineering leadership, there was an openness and grasp of what this innovative new solution could provide. Same company. Two different levels and therein lies one of the problems with innovation adoption. It must be committed top to bottom, neither and top down approach or expecting bottoms up. It all comes down to managing change more than the different innovations until there has been proven success. Many utility managers want  to be first to be second.

On April 28, 2009 ISO New England delivered a presentation at the NIST Roadmap Summit that talked about the blurring of lines between transmission and distribution that would require greater collaboration between transmission and distribution grid operators. In 2022 the line between distribution and transmission is virtually vanished, thanks to FERC Order 2222. But the needs, which the 2009 presentation identified remains an open issue today "No coordinated control and no visibility into small supply resources being installed on the distribution network" and "More coordination is needed among controlling entities". Forecasting of both supply and demand is becoming much more challenging and this leads to grid operational challenges. More cooperation by grid operators within balancing areas and among balancing areas is becoming a critical success factor. My suggestion to utilities is to work on methods and procedures that are designed to enable greater interoperability of grid management with other grid operators.

Vanessa Edmonds's picture
Vanessa Edmonds on Aug 17, 2022

Thanks for this. I know that filling this need is something Future Grid is doing. They offer secondary network management solutions. They have almost 100% solution adoption in Australia and are running pilots in the U.S. Future Grid News (

There are many challenges utilities face today, but amongst the biggest are scaling to support large numbers of BTM DER assets.  SCADA and centralized direct control systems are inadequate to manage hundreds of thousands of individual assets.  IoT platform-based solutions make sense.  VPPs through aggregation and local edge control are obvious areas of focus with utility "coordination" rather than direct command and control.  If you're interested in this concept, there is a series of articles dedicated to that idea on Energy Central:

Vanessa Edmonds's picture
Vanessa Edmonds on Aug 17, 2022

Thanks for the link. Yes, this is big problem utilities need to solve, quickly.

it is hard to pick specific technology , so instead I will answer the question with a series of questions that the Utility should ask before considering the technology further:

1) For OT/IT solutions will the software scale to serve all of your customers on a reasonable hardware platform. Many start-up and even mature vendors build their software out of quick to assemble, inefficient coding languages (Java and Python are examples of this) those languages are great for HMI, proof of concept, etc. But they are horrible for high speed computing of the core computing loop. If you have a million customers and they each have solar and an EV, then in a market interval you may need to do 2 million (or more) evaluations. Can the software proposed do that?

2) Does it solve (actually solve) the issue or just reduce it? If it does not actually solve the issue, you will eventually have to go back and solve it, and it will likely be harder to solve then, because you already put a solution in place in the mind of senior management and the commission.

3) Is it directionally correct for the future needs? in the 1990's the industry put in AMI to solve billing issues, and talked about AMI solving a number of operational issues, but frankly history shows that those AMI meters did little to solve operational issues. As we start into a second generation of AMI meters, will the same basic technology actually solve those operational issues or do we need something fundamentally different?

4) Does it meet all of your requirements, or is it promising to meet them at a future date? That promise may never come true. 

5) What is the life expectancy? People tend to look at the hardware and assume in the field that it will last a typical utility lifetime for equipment (40+ years), when many of the newer technologies have to be replaced every 8-15 years. Is that replacement cost in your business case?

6) Does the real cost benefit ratio pencil? Without the soft benefits, and other non-economic benefits does the business case turn out positive. Don't forget installation, integration, O&M and other costs. Oh, and if it can't provide the benefit now, don't add those benefits to the business case. Now forecasting additional benefits because more customers buy EVs is fine if the technology can provide that solution today and will scale to those additional vehicles?

7) can I afford to maintain it and operate it without skipping recommended maintenance?

8) With the manufacturer still be in business in 40 years? Hard to know, but you don't want to deploy a residential system, and have the vendor go out of business 2 years after full deployment and you can't get spare parts. 

9) Can you go touch a real deployment, can you spend time without the vendor in the room with the people who operate and maintain it? Do they get an incentive on every follow on deployment? 

10) Is there something that you are already using that solves this problem today, in a reasonable manner?

11) Does the vendor have enough scale to implement this at 10 or 20 utilities at one time? This has become a huge issue with some very good solutions today. 

12) Is there a different way to solve the issue using conventional equipment? (e.g., too much load on a circuit can be solved many ways, one permanent solution is to do a voltage or amperage upgrade to the circuit and solve the problem for a potentially growing consumer load from EVs and building electrification)

13) What does it do for all of your stakeholders? Investors? Customers? Linemen and other field employees? Regulators? business customers? etc.?

Vanessa Edmonds's picture
Vanessa Edmonds on Aug 17, 2022

Thank you for these insights!

With the significant increase in utility scale storage (BESS) capacity utilities should stay current with software/AI innovations to integrate intermittent resources. There are 3 options: 3rd party optimization, optimization by storage developer/operators or developing those skills internally. The latter would also generate added value by growing the bench strength required for tomorrow’s grid with growing corporate generation and the mandates inherent in the IRA. 

Vanessa Edmonds's picture
Vanessa Edmonds on Aug 17, 2022

Thank you for sharing this!