The following is a contributed article by Jeremey Klingel, Global Distributed Energy business line leader for Black & Veatch’s power business.
Keeping the lights on is more than a turn of phrase, it’s a necessity. But what exactly occurs behind the switch is somewhat less important to most, aside from the expectation that it is reliable.
That said, a quick scroll through any newsfeed will return a plethora of compelling events ranging from wildfires and hurricanes to global warming and economic instability, all of which continue to make a resilient and sustainable grid top of mind. The move to the digital grid is here.
According to Black & Veatch’s latest annual survey, the 2020 Strategic Directions: Smart Utilities Report, which polls electric, water and natural gas utilities, utilities are “all in” on grid modernization plans.
Two-thirds of respondents see improving reliability as the top driver of these efforts, and utilities are committing the funding for it. When asked how much capital they plan to invest in updating distribution systems over the next three years, one-third of survey respondents — an increase of 12% over last year’s number — said more than $200 million.
Two key factors account for that ambitious move: the maturation of grid modernization efforts, and a greater focus on grid resiliency. What was once a “nice to have” has become a “must” in today’s rapidly changing energy landscape.
Aligning spending with needs
When it comes to grid modernization, exactly where utilities want to spend money and where they have regulatory approval to do it are not necessarily in alignment.
Black & Veatch’s survey shows that utilities see budget constraints, competing priorities and regulatory hurdles as the chief barriers to modernization. This isn’t surprising, given that current regulatory models typically don’t provide utilities with a way to recapture all the fixed costs required for critical upgrades, which can mean having to decide between keeping the lights on today and preparing the grid for the challenges of tomorrow.
But this mindset is changing, and regulators are starting to recognize it’s simply not practical to expect utilities to act as the “provider of last resort” to all customers. It’s not feasible to expect utilities to maintain a massive expanse of aging infrastructure while simultaneously limiting their ability to generate returns on their assets, particularly as self-generation continues to impact revenue.
Regulators want utilities to be forward-thinking and creative in today’s increasingly dynamic market, all while offering shareholders a return on investment (ROI). Resiliency may offer the opportunity they need.
Increasing vulnerability, changing regulations
When it comes to resiliency, climate change and the resulting fluctuations in weather events are changing the game for utilities.
In 2018, six U.S. states broke wildfire records and California saw its deadliest and most destructive wildfire season ever recorded. Meanwhile, the 2019 Atlantic hurricane season marked the fourth consecutive year of above-average storms, with a record 18 named storms. Flooding across the nation impacted 14 million people, with 200 million deemed “at risk.”
Through it all, the grid took big hits, and regulators are noticing.
In June 2019, Florida Governor Ron DeSantis signed Senate Bill 796 to facilitate strengthening utility infrastructure to improve resilience against weather events. As directed by SB 796, the Florida Public Service Commission (PSC) proposed new rules that would change how resiliency projects are financed, paving the way for utilities to fast-track large-scale resiliency projects such as undergrounding power lines to make them more resilient to hurricanes.
The new rules would allow utilities to separate resiliency services from traditional ratemaking, enabling them to fund these efforts through a separate cost recovery mechanism. The rules would also remove the requirement that utilities must include resiliency activities and storm-hardening in their filings. It wouldn’t mean utilities are prohibited from including resiliency in their standard rate cases, it just removes the burden of doing so.
Utilities would be allowed to implement a monthly storm hardening fee, a surcharge that will be passed on to ratepayers. But utilities shouldn’t underestimate their ability to educate their customers about the tangible benefits of storm hardening — Florida home and business owners, for example, will experience firsthand the benefit of underground power lines when the next hurricane hits and the lights stay on.
With this new approach, Florida’s proposed rules pave the way for utilities to develop an alternative stream of revenue by offering “resiliency as a service” (RaaS). RaaS can take several forms, from the traditional — such as paying to move a distribution network from above-head to underground — to the advanced, including covering the cost of integrating advanced metering infrastructure and distribution automation.
Utilities are well-positioned to see some type of return or value-add by not only securing the grid but by also selling resiliency to their largest customers.
Targeted grid management
One of the most promising aspects of RaaS is the ability to control and manage the grid with razor-sharp precision. This capability would offer utilities incredible benefit, particularly as they continue to investigate the advantages promised by distribution automation and self-healing grids.
An example: during the worst of the California wildfire season in October 2019, Pacific Gas and Electric Company shut off service to nearly 800,000 customers, causing massive disruption. The move was a precautionary one, designed to prevent the spread of additional fires.
But had the utility been able to invest and install current Distribution automation assets and technology, it is likely a smaller, more surgical, targeted number of customers could have been taken offline, and perhaps for a shorter duration with the integration of additional back-up generation options.
To get there, utilities must invest in the hardware, software and system upgrades that will enable them to operate in a more localized manner. Not only would this strengthen the utility’s response to natural disasters, but it would also help lower costs while bolstering reliability and resilience, all while making a catastrophic situation more manageable.
A new take on cybersecurity
Utility systems are becoming more connected amidst a sweeping wave of digitization. Although increased connectivity offers unprecedented upsides, it has a dark side in that it introduces new entry points and, by extension, increased vulnerability. As networks become more distributed, they become increasingly susceptible to hacking and cyberattacks.
To address this, utilities must rethink how they approach cybersecurity and consider increasing defenses beyond what is required by current North American Electric Reliability Corporation (NERC) critical infrastructure protection (CIP) mandates. From a RaaS perspective, this could mean extending cybersecurity protections across the entire supply chain, which would redirect focus towards those who are doing business with utilities.
This will require a shift in thinking, given that today’s cybersecurity efforts tend to focus on outside threats when, in reality, the biggest threats are internal, with malicious actors exploiting vulnerabilities to hack from within.
Consider the 2014 case in which Target experienced a massive data breach in which hackers exploited a vulnerability in how one of their HVAC contractors accessed the retail giant’s internal network, allowing them to steal more than 40 million customers’ debit and credit card information.
An open market delivers opportunity
As the industry continues its conversation on delivering tomorrow’s grid, most of the talk swirls around the platforms and technologies that will help bring this to fruition. But the real work begins when the dialogue shifts to the distributed energy marketplace and what this new landscape might look like, knowing this is where utilities truly can step up and participate in the orchestration.
Regulators have limited which assets utilities can own and control. When California was first looking at battery storage, for instance, some early assembly bills questioned whether the state’s investor-owned utilities should be allowed to own these assets, even though they would be responsible for operating and maintaining them.
This approach gives utilities little incentive to take on the added liability and operating costs, without providing them with options to spread out the costs and possibly even generate ROI.
This isn’t to say utilities should have a monopoly on these assets; they should not be the only ones to own the backup generation, battery energy storage, microgrids and renewable, distributed, non-wires alternatives. Instead, utilities should be allowed to add value by pulling these different assets together and securing them through RaaS.
To get to that point, policies regulating the energy market must evolve and an open market must be created. This new market will bring additional assets to the table, but the asset type doesn’t matter.
The orchestration that goes into pulling it all together — developing this new market and getting to where a functioning next-generation grid becomes reality — is where we’ll truly find the grid of the future.
Original source: Utility Dive