A version of this article appeared on Greentech Media on November 29, 2017.
By Mike O’Boyle
Resilience may be the most trending topic in today’s electricity sector. The Department of Energy’s (DOE) report on baseload retirements impacts and subsequent Notice of Proposed Rulemaking (NOPR) to subsidize baseload units for the resilience they allegedly provide the U.S. power system begged the question not only whether 90-days of fuel onsite improves resilience (two experts from America’s Power Plan say no) – but more fundamentally, what is resilience and how can it be measured?
Answers are conspicuously absent in DOE’s analyses and attempted rulemaking, but they’re not alone – FERC’s questions to stakeholders responding to the DOE NOPR include the following:
Despite the certainty expressed by DOE, stakeholder comments have confirmed the electricity system lacks an agreed-upon definition or metrics for resilience as a concept that is separate from reliability. Furthermore, it’s unclear that either requires action from FERC – the North American Electric Reliability Corporation (NERC) already ably regulates reliability and resilience of the bulk system. Still, bulk and distribution system regulators are receptive to calls for a more resilient grid in the face of more increasingly intense weather events, greater economic reliance on continuous electricity service, a more variable and distributed generation fleet, and greater threats of cyberattack and physical assaults.
In fact, resilience is increasingly a focus for state-level utility stakeholders, particularly in the context of grid modernization. At the 2017 NARUC Annual Meeting, three hours of subcommittee meetings discussed grid resilience, and a general session, ominously titled “Mother Nature, the Ultimate Disruptor,” addressed efforts to improve resilience across critical infrastructure including the grid. So taking stock of what we know, and what we don’t, about resilience is useful before approving large-scale investments or payments to enhance grid resilience that may exacerbate the problem.
How resilience differs from reliability
Reliability and resilience are intertwined and often conflated, making reliability a good place to start. The NERC, which has FERC-delegated authority under the Energy Policy Act of 2005 to create and enforce reliability standards for electric utilities and grid operators, defines reliability as a combination of sufficient resources to meet demand (adequacy) and the ability to withstand disturbances (security). To hold reliability authorities accountable, NERC monitors the ability of reliability coordinators to respond to generation or transmission outages. For example, NERC penalizes excessive deviations from system frequency and voltage, two leading indicators that system operators may have inadequate resources to respond quickly to unforeseen supply and demand imbalances.
A common, accepted measure of adequacy is the percentage of capacity in excess of projected or historical peak demand for that system, although precise adequacy standards differ between reliability regions, subject to NERC approval. Adequacy also includes essential reliability services like frequency and voltage support, and will increasingly require a focus on flexibility as more wind and solar come online.
Security is harder to measure, as it reflects a preparedness to endure uncertain external forces. Modeling and thought exercises help, but the impacts of low-probability, high-impact events remain difficult to predict until they occur. NERC is on the case, promulgating cyber security, emergency preparedness and operations, and physical security standards to ensure grid operators and utilities are prepared for attacks or blackouts.
The impacts of inadequate resources or security against anything from hurricanes to squirrels to cyberattacks can be measured in terms of outages.
potential security risk
Reliability is generally measured in terms of the system average duration and frequency of outages (SAIDI and SAIFI), with different permutations based on whether the system average or customer average is more important to the reliability regulator.
As a more expansive concept than reliability, resilience encompasses consequences to the electricity system and other critical infrastructure from high-impact external events whose likelihood was historically low, but is now increasing. Reliability metrics like SAIDI and SAIFI generally make exceptions for extreme weather events when measuring utility performance – whereas resilience is often articulated as a grid attribute that improves response to such events.
Source: National Academies of Sciences, Engineering, and Medicine, “Enhancing the Resilience of the Nation’s Electricity System,” (2017)
The DOE-supported Grid Modernization Laboratory Consortium (GMLC) explores the concept of reliability metrics for “critical customers” as resilience indicators. A resilient grid may go down for some time, but preserving or prioritizing restoration for critical customers like hospitals, water and sanitation systems, first responders, communications towers, and food storage is important.
Resilience is also additive to reliability around system recovery. Resilience recognizes that low-probability, high impact events will inevitably cause outages – the key is investing in infrastructure that reduces the duration, cost, and impact on critical services of outages. New technologies that increase system awareness and automation, particularly on the transmission and distribution system, allow for rapid islanding of downed circuits before failures cascade into other parts of the distribution system, rerouting to restore power while isolating reliability issues and hardening the grid to withstand new threats.
Despite new research into resilience, reliability regulators (particularly NERC) already perform most of the work needed to ensure the grid, particularly the bulk power system, is resilient. The ways in which resilience can be additive as a concept are few but important, and fall to specific applications like severe weather events, continued service for critical infrastructure, and improved recovery through grid awareness. Attempts to improve resilience through rulemaking that focuses on fuel security or resource adequacy miss the point – these elements of service have been improving steadily for years and can be procured in a technology-neutral way, with an able-bodied NERC at the helm.
Resilience through the energy transition
Economic forces and policy priorities are driving a transition to a cleaner, more variable power mix. Meanwhile customers are becoming more participatory. Each of these transitions affects resilience in positive and negative ways.
We know that damage to the distribution system caused the vast majority of outages over the last five years. Conceptually, the availability of fuel to power plants could also be a cause, but data show it is a very unlikely cause of outages – only 0.0007% of outages were caused by fuel security issues.
Still, the transition away from fuel-based power to higher shares of renewable energy may affect bulk power system reliability and resilience in both positive and negative ways.
For human-caused events such as cyber or physical attacks, renewable energy removes significant fuel supply risk. Coal relies heavily on rail for delivery, which is subject to physical attacks, since roughly 40 percent of U.S. coal comes out of Wyoming’s Powder River Basin, nearly all via the 103-mile Joint Line rail corridor. Nuclear plant destruction during operations could be potentially catastrophic. The natural gas delivery system is vulnerable to cyber and physical attacks, though some delivery will continue if one line is disrupted. Converting to renewables avoids these fuel security issues; however, cost-effective integration of a high share of utility-scale renewables depends on increasing transmission system capacity to deliver energy where it is needed and balance out geographic variability. Taking down one or two lines could disrupt the system’s ability to balance, either on a regional or interconnection-wide basis, hampering reliability until threats were addressed.
Natural events, particularly weather-related events, must also be considered. Hydroelectric generation is drought vulnerable for periods of months, while cloud cover from intense storms and hurricanes threaten solar availability for days. Extreme winds may force curtailment of a portion of the wind for short periods of time. As we saw during the 2014 Polar Vortex, coal piles on-hand can freeze, and co-dependence on natural gas for heating and generation during extreme cold can threaten resource availability. Prolonged heat waves can leave nuclear unusable if cooling water is too hot.
With respect to outage recovery, combining inverter-based storage and generation may be more effective than baseload at performing a black start, since spinning masses would not need to be synchronized, though we lack practical examples of restarting with very low spinning mass. As Amory Lovins recently wrote, nuclear plant performance restarting after the 2003 Northeast Blackout was abysmal – it took weeks to get them back online to full capacity.
The other element of transition is distribution system resilience as grids increasingly rely on distributed, small-scale devices to provide services that complement centralized, utility-scale generation and contribute to a smarter, more connected, and more automated distribution system. Connected devices are helpful in identifying and isolating threats on the grid while preventing cascading failures and improving restoration, but may open up the system to more widespread cyberattacks. Local generation can add resilience to natural events – the Borrego Springs microgrid pilot in SDG&E’s territory allows a remote community to disconnect from the larger grid and maintain critical services during wildfire and high wind seasons which threaten a critical transmission line from generation closer to load centers the coast.
Lessons for policymakers
Resilience centers on withstanding and recovering from high-impact events. Policymakers can largely trust the existing reliability apparatus to cover resilience related to the bulk power grid. In particular, NERC already provides standards for cyber security, and NERC’s Essential Reliability Services Working Group is working to quantify the services needed to maintain and improve reliability and resilience.
Still, NERC covers only the bulk electricity system. Restoring the distribution grid requires and implicates other infrastructure, like gasoline delivery and roads for delivery trucks, while critical service providers also rely on electricity service. Disaster preparedness is something utilities and their regulators take seriously – but creating a cross-agency planning process could help improve and align agencies responding to threats.
Instead of duplicating NERC’s efforts, state policymakers can focus on grid modernization to deliver a resilient and flexible last mile of customer delivery. Knowing what they’re paying for is crucial to adopting cost-effective resilience assessments that balance cost and disaster preparedness. To ensure cost-effective resilience, policymakers should develop resilience metrics for the distribution system tied to measurable outcomes, starting from Resilience Analysis Process work already performed by Sandia National Labs (SNL). SNL’s seven-step process develops and routinely updates resilience metrics in light of new modeling and actual system disruptions.
Source: Sandia National Labs
“Getting the most out of grid modernization” is a five step framework from America’s Power Plan to help policymakers turn metrics into action and hold utilities accountable for delivering resilience and other customer value.
All of this takes place in the context of a dramatic energy transition with more connected distributed devices and variable fuel-free generators. When assessing the cost and reliability of future high-renewables systems, resilience attributes and metrics can begin figuring into the mix if they go beyond reliability once they’re developed. Where benefits are identified, they should be incorporated into plans, and where gaps are found, utilities and other market makers should identify technology-neutral system attributes such as flexibility to shore up resilience.