Here's a bit of irony: The key drivers of the investments that utilities are making in distribution system modernization stem from assets that utilities often don't own. In this case, we?re talking about distributed energy resources (DER) such as rooftop solar arrays, electric vehicle sand battery energy storage systems.
DER is by far the top application that utilities are planning to support in the next three to five years, according to industry responses to a survey for the 2019 Strategic Directions: Smart Utilities Report. Nearly three-quarters of respondents cited DER in general as shaping their distribution infrastructure in the coming years, while some 56 percent named electric vehicle (EV) charging. Nearly half named battery storage, both of which also are DER that someday could be controlled and dispatched to support the overall power system. That’s where we’re headed.
What's Going On
Planning is one of the biggest challenges that DER presents to utilities, which previously looked mostly at their own assets. So is it time to install new conductors? New transformers? What will be needed to support peak loads? Utilities also need to factor in the various resources and assets that customers want to pile onto the electric system.
Decentralization mandates a different kind of planning than what utilities have done in the past, and utilities likely will want to bring analytics into the process. With analytics, power providers will be able to look at the grid through multiple lenses, including what-if scenarios for DER growth, which assets to tap to achieve optimal economics, and where to place asset management devices like sensors, volt/VAR equipment and more. That’s in addition to what may be coming down the road in the future.
Most utilities already are studying how behind-the-meter resources impact the grid. Many also are looking at how the utility can use customer assets — like smart inverters — to aid in things such as volt/VAR management or whether the resource could come into play as some sort of additional capacity in an emergency.
Some utilities also are starting to question the optimal place for customers to add generation resources, particularly big ones like megawatt-scale storage or microgrids. One utility recently offered to subsidize a local university for putting in DER to take load off of a substation. The project would spare the utility expensive substation upgrades in the coming years.
Another utility used Black & Veatch analytics tools to map out how to achieve its goal of entirely renewable energy by 2045. Those analytics reveal how decentralization was likely to occur, when to green up different parts of the system, and where and when to replace fossil-fuel-based generation with wind or solar power. The game plan is expected to shave time off the utility’s original plan.
Along with delivering valuable data — consumption data and power-quality metrics — AMI facilitates grid-supportive initiatives like time-based rates and targeted load shedding that can deliver a non-wires means of deferring grid upgrades and investments. These are some of the reasons why survey respondents picked AMI as the top distribution automation solution planned at their utility. It was the choice of more than three-quarters of respondents. Fault location, isolation and service restoration (FLISR) technology came in as the second most-favored choice, earning a thumbs-up from two-thirds of respondents. Advanced distribution management systems were up there, too, with a nod from 62 percent of survey takers.
All of these upgrades bring in loads of data, but there is a big difference between receiving data and being able to use it. Utilities recognize this, likely explaining why integrating DER and asset management with analytics were also popular picks with survey respondents. Fifty-seven percent said these capabilities were planned for their organizations.
Both AMI and the sensors associated with a FLISR solution support the main drivers that utilities named for grid modernization efforts. One of those drivers was increased monitoring, control and automation capabilities, and it was a motivator for 84 percent of survey takers. Two other drivers — improved reliability and improved operational efficiency plus volt/VAR management — were selected by 82 percent or survey takers. AMI supports all of these drivers.
For instance, by analyzing blink counts, utilities can pinpoint feeders with excessive transient outages so that crews can investigate possible causes, such as vegetation or animal-intrusion issues. That helps reliability. Likewise, newer AMI meters can deliver power quality data, which means those equipped with this functionality can be strategically placed around the distribution system to serve as bellwethers to voltage sags and spikes and/or frequency excursions.
Analytics underpins use cases like these, and it can help with overall system operations. Not long ago, data from a newly built, 420-megawatt gross power plant feeding a large manufacturing site showed excessive vibration and heat coming from one of the generators. The data showed that this was not normal in comparison to other systems. After a couple weeks of monitoring the anomaly, the utility shut down the power generating equipment and detected bearing issues. The bearings had completely dried out. This discovery saved the company $1.7 million dollars, and now managers are rolling out this analytic approach throughout the organization. That’s a win on the reliability scoreboard.
Meanwhile, all these planned solutions — AMI, FLISR, advanced distribution management systems (ADMS) and asset management tools — deliver data that can help utilities accommodate the most important application they believe they’ll need to support. That application is DER, as noted in the above image.
From Here To There
Budget constraints were one of the biggest impediments survey respondents found to implementing smart infrastructure and solutions like FLISR, ADMS and AMI. Money issues were tied with competing priorities — each was cited by 62.5 percent of respondents — as top barriers to modernization, and regulatory hurdles earned a vote from 48.2 percent of respondents.
Both investment and prioritizing decisions can be aided with analytics. On the regulatory side, concerns are likely tied to the uncertainty of the utility model itself. Net metering has been a bone of contention for years, with some states — Hawaii and Indiana, for example — shutting down the policy for good. Still, the downward trend in solar and storage costs are making these options more attractive than ever, particularly in areas where power prices are high. That’s decreasing the rate base for utilities to maintain infrastructure.
One large municipal utility in California is trying to even things out by imposing a fixed charge for all customers so that less revenue must be made through sales volume. Others are still looking for solutions because even with departing load, utilities must pay for wires and substations.
Bottom line: We all know something must change. Nearly 50 percent of respondents said their future would be less regulated.
This uncertainty may be what is leading to expanded planning timelines. Years back, utilities focused on one-year rate cases. More recently, planning horizons have typically looked forward for around three years. Now, almost 70 percent of respondents are looking at four-to-seven-year planning horizons.
Along with emerging regulatory models, utility workers are grappling with new ways of working together. Grid automation and modernization are forcing the convergence between IT and operations technology (OT) in what has traditionally been a highly siloed work environment. Now, distribution system engineers, IT and communications experts, generation workers and operations folks work together.
A preponderance of utilities are embracing such cross-functional teams to get grid modernization done. More than half (56.3 percent) of respondents have the CIO, transmission, security, IT/communications and operations working together toward the smarter grid. Pull out the CIO’s involvement, and you still have more than 70 percent with a strong IT/OT team on the job.
One Midwest investor-owned utility started their modernization efforts by first creating a high-level vision of what they need to look like in the future as they become a digital utility. They plan to incorporate that vision on a day-to-day basis into decisions being made about infrastructure technology and more. To oversee this effort, the utility created an independent group that is evaluating everything underway and deciding on priorities.
This group includes IT, generation, transmission, distribution and even customer-facing people, all of whom are on this project exclusively to be the link between the utility’s vision, its daily operations and its forward-thinking technology decisions. This impressive approach is also a smart one because grid modernization will be pricey.
More than a quarter of the survey respondents are looking at spending between $100 million and $200 million over the next three years. Roughly one in five respondents expect to top the $200 million price tag.
That’s a considerable amount of money to spend – even more eyepopping when you consider that much of it will go toward accommodating DER that the utility won’t even own.