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: I’ve heard that we need energy storage technology to be deployed at scale before the grid can handle more renewables…is that true?


A: No.  There are at least five options for managing the variability introduced by renewables like solar and wind, and while energy storage in the traditional sense is a very good option, is not at the top of the list today according to price or availability.


So what else is there that might be cheaper and more available?


First, demand response is a staggering resource whose potential we are only beginning to see.  Switches and radios could turn all the buildings in our nation into thermal batteries.  By simply pre-cooling or pre-heating, thermostats and hot water heaters can become amazing sources of grid flexibility.  Major companies like Honeywell, Johnson Controls, and Google’s Nest Labs are recognizing this opportunity and taking action.  But regulators and market operators can drive this market by simply beginning to properly value this resource.  See Aligning Power Markets to Deliver Value for specific recommendations on how.


Second, variability declines considerably when diverse resources are balanced over wider geographical areas.  For example, the wind blows at different times in California’s central valley as on Oregon’s coast.  Transmission should be used strategically to connect balancing areas with diverse resources.  And where balancing areas cannot be fully integrated, energy imbalance markets (described in a previous Q&A) can also go a long way to deliver flexibility.  Planning for and Investing in Wires has important suggestions for how to effectively connect balancing areas.


Third, given the profound changes underway in the electric sector, system optimization can make a tremendous impact.  In previous decades, grid operators looked at demand as an independent variable, and dispatched supply to meet it.  Now, supply is more variable and demand is more controllable.  Luckily, operational changes and smarter software can go a long way to co-optimize across supply and demand.  Activities like dispatching on shorter intervals, defining power market products clearly so that supply- and demand-side resources can bid in to deliver them, and automating grid operations can all help deliver an optimized system.


Fourth, new combined-cycle fast-ramping natural gas plants can also deliver flexibility.  America’s production of natural gas has been increasing in recent years, as have our estimated reserves, and many have described it as the bridge to a clean energy future.  But to effectively use gas as a bridge, integrated power systems can take advantage of gas’ ability to ramp production up and down quickly.  This is a major benefit that gas has over coal, nuclear, and renewables.  Taking advantage of new highly efficient turbines that can deliver flexibility is a smart way to use gas as part of a portfolio. Again, see Aligning Power Markets to Deliver Value to read more about how to structure power markets to ensure that supply-side resources like gas compete on equal footing with demand-side resources to provide flexibility to the system.


And fifth comes storage in the traditional sense—grid-scale batteries, pumped hydro facilities, etc.  Pumped hydro can be a great option in regions with the right terrains.  Still, careful consideration must be given to local environmental impacts of pumping and releasing water in fragile habitats.  According to the Department of Energy, the cost of battery storage has come down nearly 80 percent in the last five years, and policies like California’s storage target (1.3 gigawatts by 2020) are clearing the path for this important technology to march further down the cost curve.


Finally, variability introduced by renewables can be managed by building new flexible demand (chemicals production, for example) to take advantage of excess power during times of high renewable production. As an alternative, renewable power can be curtailed in cases where cheaper solutions are unworkable.


Researchers at the National Renewable Energy Laboratory popularized the concept of a flexibility supply curve to bring some order to the way we think about the resources that are available to manage variability.  The basic idea is that we should consider our options based on least-cost, rather than on the first ideas that might come to mind—such as natural gas plants or grid-scale battery storage—which may end up being more expensive than some of the other options.



The bottom line is that there are many options for managing the variability introduced by renewables, and there is no need to slow renewables deployment while we wait for battery storage costs to come down.

Q: I keep hearing about the reliability concerns associated with retiring old coal plants and replacing them with renewables, but I’m not an engineer so I’m not sure what to believe.  Can you help me navigate these concerns?

A: At the same time that renewables are becoming more cost competitive with conventional generation, low natural gas prices and new rules from the EPA are driving retirements of old coal plants.  There are important and legitimate reliability considerations associated with this kind of a fundamental shift in our generation mix.  The key to maintaining a reliable system is to gain a clear understanding of the underlying operational issues, and to put in place appropriate rules, power market products, and incentives to manage electricity assets in new and interesting ways that comport with the basic environmental standards society sets for the power system.

Before delving into specific reliability concerns, it helps to understand the context in which these concerns are often raised.  First, it is beneficial to owners of existing assets to extend their lifetime as long as possible in order to maximize earnings on assets with fixed up-front costs.  Second, the rules, regulations, and procedures for governing the grid were written in the context of last century’s grid.  Both of these things contribute to institutional inertia, and may even cause reliability concerns to be inflated.

Despite that context, reliability considerations are real and must be addressed carefully.  On the transmission grid, reliability issues can either be local (specific to a given load or generation “pocket”) or regional (“balancing-area wide” or “interconnection-wide”).  In all cases, preventative management must happen in accordance with rules coordinated between multiple institutions, with the North American Electric Reliability Corporation (NERC) in the lead.  We discussed planning for local reliability issues in last month’s Q&A, so we’ll focus on regional reliability here.

“Frequency response” is a major driver for regional reliability.  This refers to the way that a synchronous grid responds to a large event, such as a large nuclear unit suddenly tripping off.  When a large generator trips off, the frequency of the whole grid will drop suddenly.  To avoid a black-out, the drop in frequency must be stopped as quickly as possible and more power must be added to bring the frequency back up.  This generally happens in three steps: (1) the physical inertia of large spinning turbines inside conventional generators will help resist the sudden drop, (2) automated governor control (AGC) response on some of those same generators will kick in to provide more power as soon as a drop in frequency is detected by the machines, and (3) grid operators dispatch reserves.

Over the past two decades, the grid’s ability to respond to sudden trips has been deteriorating in America’s major interconnections.  This is principally due to a decreasing fraction of conventional generators on AGC (mostly for economic reasons) and the changing nature of electric loads (fewer synchronous motors whose power demand automatically falls with frequency).  In this deteriorating grid environment, questions have been raised about the prudence of retiring existing polluting plants that provide inertia and AGC, or of increasing the share of power provided by renewables since most of today’s renewable generators do not provide frequency response.  At the same time, increasing integration of regional grids can provide a counterbalance to frequency response deterioration.  For example, all of the inertia created by the rotating generators in the 39-state Eastern Interconnect helps to assure frequency throughout that area, illustrating one of the benefits of large, integrated, modern transmission grids.

It is important to deal with reliability issues like frequency response; grid operators cannot simply choose to just ignore NERC rules.  Luckily, many important methods have long been in place to maintain reliability—transmission planning processes (stemming from FERC orders 890 and 1000) and ancillary service markets equip grid operators well to handle these changes.  Moreover, we still have plenty of headroom to plan for the future by tweaking existing power market products or adding some new ones.  For example, a 2011 study by GE examined frequency response in the Western Interconnection, and the authors found that even at renewable penetrations up to 50 percent in CA, no credible conditions resulted in load shedding or other stability problems.  In a more recent study, researchers at NREL looked at how “synthetic inertia” and primary response from partially curtailed wind farms could help grid operators plan for large contingencies.  The study’s authors found that these two resources could substantially outperform conventional generation to provide frequency response.  The key is willingness to pay developers and operators of renewable resources for such grid services.

What does this mean for policy makers?  The upshot is that the grid can operate quite reliably even with retiring fossil plants, lots of renewables, or challenging operation conditions (light load conditions or reduced hydro resources during spring flows) so long as we plan ahead and compensate adequately for important grid services like frequency response, regulation (already required in FERC jurisdictions), ramping (developed in CAISO and underway in MISO), and short-term reserves.  Emerging technologies can also help. For example, widely-deployed synchrophasors could quickly alert grid operators at the first sign of frequency disturbance and fast-responding grid-scale energy storage can also help maintain frequency.  The better job we can do at creating rules and power market products that allow a maximum numbers of resources (like renewable generators, demand-side resources, wide area monitoring systems, fast-response storage, etc.) to participate in solving potential reliability issues, the cheaper it will be to maintain grid reliability. 



Thank you to Paul Denholm, Brian Parsons, John Jimison, Allison Clements, and Hal Harvey for their input on this piece. The authors are responsible for its final content.

Previous articleBeat autumn deadline to make most of cheaper business energy prices
Next articleArizona Utility Opposing Rooftop Solar Seeking to Provide Panels
Our nation’s electricity system is undergoing a rapid transformation. Market forces, driven by public demand for cleaner, more efficient energy, and technological innovation are redefining America’s power sector. These trends will change the electricity system and utility businesses at their core. But our century-old legal, economic, and regulatory structures are thwarting innovation. More than 150 top energy experts from academia, industry, and non-profits have joined America’s Power Plan, a project designed to tackle the tough questions and provide a vehicle for policymakers at the state and local levels to address these challenges and make informed decisions about the future of our nation's power system.

No posts to display