By Sonia Aggarwal, Eric Gimon, and the experts of America’s Power Plan
This is the next edition in a monthly series of short answers to some of the questions we’re hearing from public utilities commissions, market operators, utilities, legislators, and other energy decision-makers. Click here to see the answers from last month. Submit your question today by emailing APP [at] energyinnovation [dot] org.
Q: What are some of the main disruptors for the electric grid? Do you have any advice on how to best manage these or at least take a pro-active stance?
A: Rapid changes in natural gas prices, cyber-security concerns, electric vehicle growth, new information technology and big data management, smart thermostats, solar panels at Home Depot… the list goes on. Major changes are now happening fast in a sector accustomed to slow and steady movement. Each of these disruptors represents its own risks and opportunities, but one thing has become clear: the long-term success of utilities relies on engaging with disruptors early.
Planning for change begins with gathering the best available information. Gathering information can be a time-consuming process, and it can be difficult to gauge when you have sufficient information to take action. There is always more to learn, and you can always be blind-sided. Apart from obvious suggestions to cast a wide net for information and hold regular informational hearings, it is useful to look to third-party research organizations that aren’t linked to the status-quo (see the Regulatory Assistance Project, the Energy Future Coalition, the Advanced Energy Economy Institute, Rocky Mountain Institute, the U.S. national laboratories, and of course… America’s Power Plan, to name a few).
One thing to keep in mind is that you do not need to be a prophet; the key is not necessarily to anticipate trends but rather to be prepared to react to them. For example, the rapid drop in natural gas prices led to greater use of natural gas generators at the margin. Knowledge of this kind of consequence should prompt an integrated assessment about changing reliability requirements and the potential for cross-effects with other sectors of natural gas demand. Along these lines, the State-Provincial Steering Committee (SPSC) and the Western Interstate Energy Board recently conducted a study of regional interdependencies between gas and electricity.
Once new information is gathered, it should feed directly into a forward-looking planning process. The longer the planning window, the wider the variation should be in assumptions about new technologies and other disruptive trends, be they natural gas prices, adoption of electric vehicles or rates of growth in rooftop solar. Many of the current disruptors have the potential to fundamentally change the distribution system: smart grid sensors coupled to new data-crunching resources, distributed generation, distributed storage, automated demand response, smart appliances, electric vehicles, and more. In light of these trends, regulators, utilities, and other decision-makers should begin by conducting forward-looking studies of potential distribution level effects. Integrating new information about technology and trends into new kinds of analysis like this can help utilities identify parts of the system that may require upgrades in the future, allowing them to evaluate many possible solutions to emerging system needs. This coordinated approach is known as “Integrated Distribution Planning” (IDP), see IREC’s Integrated Distribution Planning: A Path to Sustaining Growth and APP’s Encouraging Generation on Both Sides of the Meter for more detail on these concepts.
The state of Hawaii is currently using an integrated planning approach to address rapid rooftop solar growth in a state with high energy costs. Meanwhile, the state of California recently passed legislation, AB 327, requiring California’s large investor-owned utilities to conduct IDP. IDP is a good approach for thinking through the potential impacts of disruptors at the distribution level, and is likely to become a trend across the country as technological changes persist and accelerate.
Q: We are putting together a regional energy plan with partners in our area. What perspectives can you offer about the impact of distributed energy resources (DERs) in our context?
A: A regional energy plan has the power to harmonize parties around environmental impacts, cost and reliability of supply, and jobs and the economy. Distributed energy resources (DERs) have implications for all three.
Distributed energy resources have the potential to deliver significant environmental benefits, especially if they are used to displace dirtier power supply. Energy efficiency and distributed generation like rooftop PV or combined heat-and-power (CHP) offset the need to burn more polluting fuels. Demand response programs, distributed storage, and flexible distributed generation can displace inefficient peaker plants and allow grid planners to make better use of regional transmission and distribution assets. Moreover, distributed energy resources can be deployed more broadly and evenly than centralized resources, helping to mitigate environmental justice concerns for communities in the shadow of big emitters.
Still, planners should be careful when considering policy to support distributed generation, as some distributed resources might be dirtier than the grid electricity they’re replacing. Concerns have been expressed, for example, over demand response programs inadvertently incentivizing the use of backup diesel generators that contribute to local air and noise pollution, not to mention increased greenhouse gas emissions. One way to mitigate these concerns might be to set performance standards for all new distributed resources.
This leads us to costs and reliability. Regional planners can start by working with grid planners to explore how the local area interacts with the broader transmission system, assessing whether the local transmission backbone is sufficient, as well as how to plan for optimal exchanges with other regions. If the region includes a load pocket, DERs can be an option for meeting local capacity needs, as an alternative to transmission build-out.
Using DERs for reliability may also deliver better resilience, as emerging resources like microgrids can provide islands of stability in challenging situations, rendering the region less dependent on vulnerable transmission. A smart regional plan can identify places where DERs might have the most value for the grid: where they can obviate the need for expensive upgrades or additional backup capacity. The co-benefit of this kind of planning is that it helps send clear signals to vendors, installers, developers and utilities about where best to spend their efforts; which can lead to lower overall costs.
Regional planning can also help bring to light the potential cost impacts that rapidly deploying new technologies may cause for the owners of existing assets. An integrative approach to planning can help regulators and other stakeholders get ahead of potential issues and determine how best to cover an appropriate amount of the costs of stranded assets. This kind of orderly plan can focus on what assets will need to retire and which assets can be upgraded in view of future conditions, illuminating a clearer financial picture for owners of those assets, as well as easier negotiations with regulators.
While many tout the challenges that DERs present for existing institutions, they also represent a huge opportunity for local economic growth and high quality jobs. In order for DERs to replace existing or retiring resources, their costs must pencil out lower than alternatives, either directly or in combination with other benefits that important parties deem valuable. Typically, a large share of the costs of DERs go to local jobs in installing, operating and monitoring new equipment. At the same time, cost reductions are also more easily captured by local business and residences.
The challenge will be how exactly to create rate structures and avenues for third party participation that present win-win situations. A regional planning process is a great venue for thinking about aggregate economic benefits (there will always be some winners and losers) and for getting important parties together face-to-face with the aim of developing equitable rules of the road.
Finally, in addition to electricity, one of the advantages of regional energy planning is the ability to integrate transportation into the plan. Better transportation planning leads to happier citizens with more abundant and more pleasant transit options, while reducing vehicle-miles-traveled and improving trip efficiency. In addition to these transportation system considerations, it is crucial to think about how electric vehicles (and the infrastructure they require) will interplay with the grid. A smart regional plan will consider future electric vehicle growth scenarios, as well as spatial usage patterns that may create new demands on the electric grid, or create new opportunities for managing the electric grid intelligently. The regional planning frame offers excellent opportunities for creative interplays in managing all energy streams to the common benefit of all important parties in a region.
Q. If a utility wanted to work with its regulators to launch a new program for integrating direct load control, are there existing IT or manufacturing standards ready to support that model?
A. The Smart Grid Interoperability Panel (SGIP) is a helpful group established to support the efforts of the National Institute of Standards and Technology to develop standards for the smart grid. There are at least two standard IT requirements that follow SGIP’s Common Information Model to allow equipment, appliances and energy management systems to respond to dynamic pricing signals or direct utility control: the OpenADR 2.0b standard and the Smart Energy Profile (SEP) 2.0 standard (Zigbee-based).
The OpenADR standard enables automated demand response for commercial, industrial and residential customers; communicating over the internet. The SEP 2.0 standard is ideally suited for use within a home or building, aimed at residential or small commercial customers. The SEP 2.0 standard can communicate over AMI or via a broadband gateway.
Some regions have programs that grant utilities direct control over customers’ equipment or appliances like air-conditioners, but the trend is moving away from this approach in large part because customers dislike the loss of control. The exception may be in instances when direct control does not have an easily noticeable effect, such as with hot water tanks; customers may be more tolerant of utilities controlling that kind of equipment. Still, as an alternative to direct load control, standards like OpenADR 2.0 and SEP 2.0 enable grid operators to send price, reliability or dispatch signals over the Internet, enabling customers’ equipment to make an automated decision about how to respond based on customer preferences set up in advance. This set-up can mimic directly-controlled resources by exposing load to high prices for electricity during certain peak times or a high penalty for underperformance of a resource that has signed up to be part of a program. Often, this is done through third-party aggregators or energy managers, either in coordination with or under contract with the utility.
OpenADR is already delivering 250 megawatts of demand response in California. To compound this, new building codes (Title 24) are set to require that every new or retrofit thermostat, HVAC system, networked lighting controller and building automation system come ready for two-way, automated utility-to-customer energy management. Meanwhile Texas (with its retail choice structure) is taking a customer-oriented approach: Reliant and TXU are now offering their customers control of smart thermostats in their homes via their cell phones. The TXU program allows customers to set temperatures on an hour-by-hour basis for a typical week, watching in real-time how the changes affect their monthly bill. And as more and more two-way thermostats make their way into Texan homes, the potential for automated demand response grows.
Given all these developments, a convergence is happening between the demand-side perspective and the supply-side perspective. From the demand-side perspective, demand response looks like customers (either directly or via automated programs) responding to prices or incentives to shape the load in desirable ways. The demand-side aim is to develop useful behaviors ahead of time, and then dispatch supply-side resources to manage any remaining operational issues. From the supply-side, demand response is a dispatchable resource, which must deliver verifiable reductions at the right times (typically monitored against a baseline) or face penalties for non-compliance.
But these demand- and supply-side perspectives are now converging: real-time pricing and more targeted incentives drive behavior of load in aggregate, which can now respond dynamically to operational constraints, obviating the need for dispatchable resources in certain cases. Meanwhile, this aggregation of resources under voluntary pricing looks to grid operators much like a demand-side resource – it is full of unpredictable individual participants that, in aggregate, present a probabilistic reliability that can match or even beat the reliability of traditional resources like gas peakers.
Thank you to Sila Kilicotte for her input for this piece. The authors are responsible for its final content.