Eight Areas of Electricity Innovation to Watch in 2017
It’s 2017 and we have a lot to look forward to in the electricity sector this year. While many of us take a moment to reflect on the accomplishments of 2016, there are just as many of us who are thinking about the challenges ahead.
For the past five years, Rocky Mountain Institute has been convening and supporting the Electricity Innovation Lab (eLab), a unique network of leaders and change agents from across the electricity industry representing a cross-section of the key stakeholders who are shaping the transformation of our electricity system. With utilities, regulators, distributed energy resource companies, energy consumers, advocates, and academic experts collaborating together, eLab really is a laboratory: a place to test new ideas and to explore new solutions.
eLab reached new heights in 2016 with our first-ever eLab Summit, which brought together 135 members to engage collaboratively on optimal approaches to continue the evolution of the electricity sector.
We surveyed those eLab members about their most exciting opportunities—and their critical challenges—in 2017. Eight key issues emerged.
1. Distributed Energy Resource (DER) Valuation and Rate Design
Things are starting to get interesting in this space. Nevada just reinstated net metering, Arizona and California are moving to time-of-use rates, New York is moving closer to a “value of DERs” tariff. And we still have 46 states to go! As of last count, 15 states were formally examining or resolved to examine the value of distributed generation.
Two underlying dynamics are spurring new attention on DER valuation. First is the accelerating adoption of new DERs. Electric vehicles (EVs), batteries, grid-interactive water heaters, and many other smart appliances are expanding the definition of “distributed energy resource” beyond just rooftop solar. As a result, policy makers are taking a more holistic, and generally technology-agnostic, approach to DER valuation. In the year ahead, we can expect more attention on smart home rates and electric vehicle rates, in particular.
The second thing that is changing the conversation, almost literally, is that all parties are dramatically increasing their understanding and recognition of the costs and benefits of DERs. With new resources, such as the recently published manual on DER rate design and compensation from the National Association of Regulated Utility Commissioners (NARUC), in 2017 we’re going to see forward motion on parties being able to deliberately segregate the way they calculate the value of DERs from the way they pay for them (e.g., net metering).
2. Electric Vehicles as a Grid Asset
While electric vehicles still represent a small fraction of vehicles on the road today, research has shown that it takes relatively few EVs on one distribution feeder to have a significant effect on the overall performance of the grid. As a result, stakeholders are looking for tools and programs to leverage EVs as a grid asset rather than a liability.
At the same time, with the recently released long-range Chevrolet Bolt, the soon-to-be released Tesla Model 3, and many more automakers debuting EVs with larger batteries and longer ranges, 2017 is going to be the year we see automakers, charging network operators, and others get serious about expanding DC fast charging and charging networks more broadly.
While these two dynamics may seem complementary on the surface, some serious complications still need resolution. To employ EVs as a grid asset, utilities require predictable charging patterns. This suggests charging at lower voltages for longer periods of time—Level 2 charging. Automakers and charging network operators seek convenience for EV drivers, which means charging at higher voltages whenever and wherever it’s most convenient—DC fast charging. How to best manage the impacts of charging on the grid, while creating a system that supports the broader adoption of electric vehicles, requires finding and creating solutions that work for both groups.
3. Alternative Capital Planning
As DER costs have declined to the record-low prices we see in the market today, utilities and regulators are exploring ways to use DERs to displace traditional infrastructure investments at a lower total system cost. Often referred to as a non-wires alternative (NWA), this concept is gaining momentum with the California Public Utility Commission’s decision directing investor-owned utilities in California to conduct at least one and up to four pilots using DERs to displace or defer traditional grid investments.
While innovators are moving swiftly to make portfolios of DERs plug-and-play for utilities and grid operators, there are still many questions about how to plan for this, how to contract and pay for these portfolios, and then how to operate and maintain them. These portfolios often require a mix of different DER technologies in order to provide the full suite of services that utilities and grid operators seek. We are beginning to see new alliances between DER providers in order to make these projects happen, and we anticipate efforts to co-create tools and solutions to address the planning, financing, and operational issues that NWAs present.
4. Utility Business Models in Vertically Integrated States
Using portfolios of DERs to replace traditional grid infrastructure presents a fundamental challenge to the traditional cost-of-service regulation model for vertically integrated utilities—particularly when the distributed resource alternatives are deployed by third parties and not by utilities, creating a direct conflict for the traditional utility revenue model. In states like Minnesota and Hawaii, regulators and other stakeholders are exploring changes to the traditional utility business model that can resolve this conflict.
Options range from performance-based regulation—where the utility’s business model of investing in the grid remains much the same, but the metrics by which it is assessed and rewarded changes—to creating entirely new revenue opportunities for utilities. The alternative revenue models that have been suggested are broad and varied, and include the utility acting as a service provider to deliver energy efficiency upgrades and other services to customers, the utility operating as a finance provider for alternative grid investments (e.g., DERs), and the utility serving as a market platform for DERs, also described as the distribution system operator.
5. Distribution System Operations and Markets
As vertically integrated utility markets are looking for cost-competitive mechanisms to invest in economic DER technologies, deregulated markets face an equally complex challenge in incorporating DERs into multiparty transactions. Transforming the grid into a system that is cleaner, smarter, and more flexible means capturing and creating value from resources at the distribution edge. While it will take more than clean DERs for our system to reach the 80- or 100-percent renewable energy targets that an increasing number of cities, states, and companies now aim for, building a system that can accommodate this level of renewable energy means building a complementary system that can seamlessly integrate the capabilities of DERs with utility-scale resources and wholesale markets.
Markets at the distribution-system level, often referred to as distribution system operators (DSOs), as opposed to the independent system operators (ISOs) that operate the wholesale markets, are increasingly being viewed as a necessary part of the grid of the future. While consensus about the need for DSOs is growing, many outstanding questions still need to be answered about who manages the DSO, where its boundaries should lie, and what kind of market transactions (e.g., real-time prices or day-ahead bidding, etc.) it should use to manage participating distributed energy devices. New York has already begun this scoping process through the Reforming the Energy Vision (REV) proceeding, and in 2017 we’ll see other states, ISOs, and individual utilities begin their own explorations into and possibly demonstration projects for DSOs.
6. DER Control Schemes: Coordination or Chaos?
As we look to create distribution-level markets, we encounter many questions about the control required between devices, system operators, and market operators. While a bevy of working groups such as the Smart Grid Interoperability Panel and the Gridwise Alliance have been working to bring standards and protocols to the DER controls realm, growing interest in DSOs and momentum to use DERs as alternatives to traditional capital investments are bringing new urgency to this topic.
Engineers and economists agree that control is necessary to manage the impact of DERs on the grid. They also agree that a certain amount of control and coordination is necessary to manage DERs in a market. But uncertainty exists about when and where the need for control arises for both system operations and market operations. Do these functions require separate devices, or can they be accomplished through the right combination of software and hardware? When these questions are layered with questions about what should be market-driven coordination, as opposed to an autonomous device response, or with a customer’s decision about how to use the device and when, things really start to get interesting.
7. Customer Engagement
While it’s easy to get excited about all this discussion about DSOs and non-wires alternatives, the stark reality is that customer participation in most traditional utility demand-side management (DSM) programs still remains in the single digits. Adoption of rooftop solar and EVs also remains in the single digits in most parts of the country. If we’re going to see DERs truly realize their potential to operate as a grid resource that utilities, system operators, and regulators plan for and rely on, then 2017 needs to be the year that we kick our customer engagement into high gear.
The next generation of customer engagement can start by thinking about “customers” and not “ratepayers,” experience as well as energy use, and value versus costs. We’re seeing new models emerge that leverage customer segmentation and consumer marketing analytics to drive DER adoption based on real customer needs; that increase customer trust by providing clear, easy-to-understand quote comparisons; and that cut through bureaucratic red tape to deliver a seamless customer experience.
8. DERs for Low- and Moderate-Income Customers
When thinking about the role customers can and will play in the grid of the future, it’s important that we remember our low- and moderate-income customers, those who often face the greatest risks with the fewest resources to adapt to a changing energy landscape. For years, regulators have ensured that energy costs do not become an undue financial burden to low- and moderate-income (LMI) customers by providing special credits, subsidies, or rates to these customers, as well as by ensuring that utility investments are fair, justifiable, and reasonable.
In 2017, with the decrease in the costs of DERs coupled with smartphone-enabled engagement pathways (including pay-by-phone, electronic billing, and pre-pay), utilities, regulators, and others are revisiting whether they can serve these customers better with DERs than with subsidies. Doing so would simultaneously reduce costs while also improving customer metrics, including a declining energy footprint.
These eight opportunities and challenges are center stage for RMI and eLab network members. In the weeks ahead, we’ll share with you their insights and their accomplishments on these issues, as well as the other solutions we’re working to co-create through eLab as we transform the U.S. electricity system.
