How to find value in distributed energy resources.
Richard Fioravanti is v.p. of distributed energy resources at DNV GL (formerly DNV KEMA), and Nicholas Abi-Samra is senior v.p. of electricity T&D at DNV GL.
The technologies that make up the class of distributed energy resources (DERs) are beginning to proliferate on the grid. Market forces, technology advancements, communications, and controls are making distributed technologies more accessible, economically viable, and controllable assets. The resulting changes will make the grid more efficient and reliable, as well as provide end-users with the opportunity to make more proactive use of energy and to reduce the cost of services.
What challenges will those changes pose to current providers of electricity? Will the changes lead to new business models to deliver electricity? Understanding what changes will take place, and what opportunities they will create, is fundamental to the growth of the companies that operate the grid today.
As advanced technologies for the electricity grid approach commercialization and shifting market forces create new choices and opportunities, operators of our grid realize that the future grid will differ greatly from today's environment. That difference isn't simply an issue of the grid incorporating technologies to become smart. Rather, the adjustments are more fundamental - they concern how electricity is generated, where it's generated, how it moves, and how it's delivered.
The mono-directional flow of electricity from centralized generation assets to end-users is becoming multi-directional. The technologies affecting that flow are evolving rapidly. In particular, the technologies that make up the class of DERs are reaching levels of cost and ease-of-installation that soon will put them into the stage of mass deployment. Market forces, such as the introduction of low-cost shale gas, have made it easier to overcome economic hurdles, further accelerating the process.
Also, communications and controls are turning distributed technologies into easily accessible and controllable assets for the grid. Ultimately, these changes will make the grid more efficient and more reliable. They will open up opportunities for even more DER technology and services - for example, cost-effective microturbines and fuel cells, sophisticated data analytics, and customized demand response. End users will see a less expensive service.
For more than 15 years, utility executives, regulators, and other stakeholders have heard similar arguments about the imminent potential of DERs being deployed across the grid. Today, however, this scenario is beginning to be realized based on a number of factors that propel each of the categories of DER:
• Fossil-based DG: Comprised of microturbines, fuel cells, gas turbines, reciprocating engines, and combined heat and power (CHP) applications. Each of these devices is being propelled by the recent reductions in the cost of natural gas, though microturbines and fuel cells are still being held back by their higher operating cost.
• Renewable-based distributed generation (DG): Comprised of wind turbines, solar photovoltaic, and biogas-digester systems. Increased deployments are due, in part, to rapid decreases in installation costs and increases in government incentives. The amount of distributed storage installations has been doubling every two years, with even higher growth rates for residential PV. Cumulative U.S. DG PV is expected to more than double in the next 2.5 years.1
• Microgrids and electricity storage: Storage is advancing due to the capabilities and benefits the technology promises. A microgrid is an application that builds up, links, and optimizes combinations of individual DER devices and is advancing due to increased interest in grid resiliency and the potential to leverage resources for further cost savings. One only has to examine the activities in New York and other Atlantic coastal states around the Superstorm Sandy response to see the linkage.2
• Automation and load-shifting technologies: Demand response (DR) and advanced energy management are being driven by advancements in smart grid and communication, as well as the low-cost but effective nature of the solution.
Several major industry trends are driving the DER phenomenon. Low-cost natural gas is one example. With the introduction of abundant U.S. shale gas into the energy mix, the cost of natural gas in just five years has dropped to levels last seen in the early 1990s. The wellhead cost per thousand cubic feet has fallen from more than nearly $8 in mid-2008 to under $3 today.3 The effect of this development will be to lower the economic hurdle for DG projects and drive applications such as CHP.
The desire for greater resiliency also strengthens the case for DERs. After the effects of numerous historic storms, including Hurricane Katrina and Superstorm Sandy, the desire to create solutions that address grid resiliency are driving increased attention toward DERs.4 The adoption of technologies such as solar, storage, and applications such as microgrids likely will benefit from this market trend.
Another driver is renewable energy adoption. On the distribution system, renewables typically mean solar photovoltaics. According to the Solar Energy Industries Association, the price of PV dropped by 60 percent from 2011 to 2013.5 This price decline, combined with incentives (such as tax credits and net metering), rising retail electricity prices,6 and the desire of states to increase renewable penetration, appears to be propelling a rapid adoption of the technology at the residential and small commercial level.
Further, as more renewables are deployed, whether at the generation or distribution levels, the issues of variability and system protection will raise demand for mitigation technologies, such as natural gas turbines and energy storage.
The same trends spur improvements in controls and communication. At the beginning of the last decade, DR program participants would wait for pagers to alert them and then take action to cut usage. Today, technology has made it easier to respond to market signals. Smart systems will make participation in DR programs effortless, which in turn will offer multiple scenarios for market participation and the creation of proactive customers.
Though there still might be hurdles around the deployment of advanced technologies, particularly at the edge of the grid, some consumers will not only want, but will also demand, more insight into pricing signals. Proactive customers seek the ability to react to what is happening outside their factory, store, or home - in addition to what is happening inside. The increasing ease for end users to adopt DERs will drive the industry to accommodate these new assets.
Whether vertically integrated or deregulated, utilities will feel the greatest effects from the changes on the grid. The farther power generation and delivery go to the edge of the grid, the further they move away from the domain of current providers and their traditional territorial limits. If trends hold, central generators essentially will provide less; the companies that manage the delivery of electricity will deliver less.7 These changes on the grid will most likely be disruptive for utilities, affecting the current utility business model. Federal and state regulations and policies will need to adapt as well, in order to address issues created by increased deployment of DERs.8 How utilities cope with change, remain competitive, and avoid burdening fewer and fewer customers with the costs of the larger system, will be the industry's single largest challenge over the next 10 years.
For grid operators, the deployment of advanced DER will provide benefits in the form of increased efficiency, performance, and ideally cost. Some of the distributed technologies, such as small wind and solar, have the same characteristics as their larger, generation-scale systems; their output is highly variable. Traditionally, grid operators haven't examined activity at the end-use, small distributed area of the grid. Generation below 25 MW often doesn't show up in current models. The aggregated amount is too small to have a major effect. As the number of DER devices increases, however, this might no longer be the case. Not only could the total megawatt load served at the edge of the grid become significant, but renewable DG would create more variability as well. Operators will need to use enhanced forecasting tools to account for that variability in both day-to-day operations and long-term planning. Understanding and being able to predict events accurately at the edge of the grid will be essential to grid operations and to providing service to the end user.
The promise of DERs is shifting generation and delivery into the hands of end users. This evolution has the potential to be highly empowering. But maintaining power generation and delivery operations isn't a trivial task. Though more options will become available to end users, not everyone will want to accept the risks and responsibility to maintain and operate DERs. Commercial and industrial customers might simply want to focus on their core areas of business or maintain a business-as-usual state. All end users will want to participate to leverage the potential price reductions, independence, and security, but they'll want those benefits to be easy to capture.
As generation and delivery push farther toward the grid's edge, the opportunities for companies that traditionally install DER devices will increase significantly. This isn't simply a matter of more DG system sales, it's also a shift in the industry paradigm. DG installations will evolve into microgrids. The performance of the devices will move beyond simple on-off commands to operating as systems fully integrated into real-time markets and changes in load requirements. Some of the technologies at the edge will be relatively unpredictable in terms of when and at what capacity they produce; and that increase in operational complexity could offer significant opportunities for device providers.
As these trends begin to have an effect on our traditional electricity delivery system, new opportunities to capture value will also be created. Stakeholders will need to examine those trends in order to ensure that they don't miss the opportunity, or worse, lose value because of the changes. It's important for each stakeholder group to position itself to capture such new opportunities in order to continue prospering as the grid evolves.
As technologies and larger or aggregated sources of power move away from the central utility, utilities and grid operators must have a clearer view of what's actually occurring at the edge of the grid. Such visibility isn't necessary for traditional DG, but the addition of variable sources such as wind and solar increases the need for it, from an operational and an economic standpoint.
A 2010 study of the California grid considered prediction and edge-of-the-grid control technologies under different scenarios of future DER adoption. The study showed that having that kind of operational visibility could lower production costs (for power generation to balance the system and provide ancillary services, among other things) by $391 million.9
Today, that visibility and ability to modulate and control DER in real-time can be attained by utilizing technologies successfully implemented in other industries or by adopting and leveraging the smart grid technologies that are already being deployed.
Moreover, utilities likely will change their view of DERs. In the past, many utilities considered DG negatively - a disruptive, un-integrated set of technologies that will only lead to the grid being more expensive to non-DG consumers, less reliable, and less safe.10 In the future, the industry might seek ways to treat distributed technologies as assets. As part of that approach, as utilities consider changes to their business models, they might get creative about the concepts of location and ownership. For example, in California, the state's shareholder-owned electric utilities can sell power to customers from "system-side" DG; and several have programs for rooftop solar aggregation.11
Further, energy storage technologies can perform a number of roles across the grid. On the distribution portion, the devices can work on the utility or the customer side of the meter. Such assets can become ubiquitous components for utilities to improve reliability and incorporate renewables; the utility can consider energy storage at a customer facility as a grid asset as well.
Similarly, dynamic microgrids, which can support community loads during outages, might become the keystone for building more resiliency into the grid. In one scenario, a dynamic microgrid would behave like a typical microgrid system, supporting its own facilities. Then, during outages, such as extended storm events, the system could connect to a wider area and maintain critical loads in that area until the power is restored to the larger grid. Figure 1 displays dynamic microgrid concepts, where a microgrid is able to "wheel" power out to a feeder during outages at the transmission level.
A future that allows such an interactive control strategy will require many policy and regulatory changes. However, the technologies to implement such dynamic solutions are readily available. Grid operators look to automation as the first step toward the future grid, where they can tap into virtual power plants and energy management systems to help them operate the system efficiently. However, even though the technologies are available, it's yet another job to assemble them in a way not only to incorporate and integrate capabilities seamlessly, but also to ensure that the regulatory enablers (such as real-time pricing signals, verification capabilities, and compensation mechanisms) are available.
Facing Inevitable Change
DERs will change our energy delivery chain and will have myriad effects on all stakeholder groups. The potential of those effects should drive each group to action, not only to understand the changes, but also to find ways to incorporate them in order to maintain the financial health and growth of individual companies.
No entity has the potential to be affected more than the utility group. If we take a high-level examination of how DERs will change the energy delivery process, we can predict that grid operators will be able to operate more efficiently; that end users can reduce cost and improve backup capabilities; and that developers can profit through increased deployments.
For utilities, however, if no actions are taken, changes in the energy delivery process could erode current business models. DER trends should be a call to action for utilities to understand the speed and dynamics of those trends, how they will translate in a utility's specific region, and, more important, how to take advantage of the changes. Utilities in particular can focus on three primary areas.
First, they can assess DER visibility at the edge of the grid and the benefits it provides. Control and monitoring technologies like synchrophasors, predictive analytics, and advanced sensors will create greater visibility and not only improve grid response but also allow the utility to be proactive about DER effects on the system.
Second, they can consider how to incorporate storage, microgrids, and automation in a manner that benefits stakeholders - how to deploy, where to deploy, and what regulatory or policy changes must accompany such initiatives. There are many opportunities within each customer class to collaborate on DERs.
Finally, they can consider how to leverage the steps that have already been taken in creating future utility grids and incorporating DERs into those plans.
Change is inevitable for the electric industry and to those involved in the delivery chain. The real focus is on the utility. But it and all stakeholders can position themselves not only to respond to the challenges, but also to play a significant role in the energy delivery chain.
3. Source: Energy Information Administration.
4. Source: Energy Central.
5. Source: SEIA.
6. Source: Energy Information Administration.
7. From "Disruptive Challenges: Financial Implications and Strategic Responses to a Changing Retail Electric Business," by Peter Kind: "Bloomberg New Energy Finance (BNEF) projects that distributed solar capacity will grow rapidly as a result of the competitive dynamics highlighted. BNEF projects 22-percent compound annual growth in PV installations through 2020, resulting in 30 gigawatts (GW) of capacity overall (and approximately 4.5 GW coming from distributed PV). This would account for 10 percent of capacity in key markets coming from distributed resources and even a larger share of year-round energy generated."
8. In live polling during DNV GL's Annual Utility of the Future Leadership Forum, in Washington, DC, last June, the greatest portion of responding utility industry executives (51.4%) cited regulation as the highest priority to invigorate grid transformation. This response was much higher than the next-ranked priority, emerging technologies (22.9%).
10. Such issues were cited even as far back as 2007, in the Department of Energy study, "The Potential Benefits of Distributed Generation and Rate Related Issues that May Impede Expansion."