Trending Topics – Resilience in a clean energy future

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.

Trending Topics – Wholesale markets need reform, but flexibility, not resilience, is the key

A version of this article was posted on Greentech Media on October 31, 2017.

By Eric Gimon

U.S. electricity markets face scrutiny over revenue problems and reliability concerns as greater amounts of renewable energy and distributed resources come online, particularly after the Department of Energy’s (DOE) Notice of Proposed Rulemaking, but coal and nuclear subsidies to boost “resilience” miss the main challenge facing wholesale markets – the need for grid flexibility.

Flexibility, not fuel on-hand, is at the core of what it means for a grid to be reliable or resilient.  Where restructured wholesale markets rule and the “invisible hand” of the market is meant to provide secure and efficient real-time balancing of supply and demand, resource adequacy, and long-term cost recovery for system resources, markets and regulators have been particularly slow to evolve.  Markets, especially, are powerful tools for finding least-cost resources to meet physical grid needs, but tend to favor incumbent generation over variable resources and flexible demand- and supply-side resources against the near and long-term interests of consumers.

To reach a clean, resilient, affordable future, markets must evolve to value flexible resources – the key to reducing integration costs for variable resources.  Two recent reports from America’s Power Plan (APP) outline how markets can evolve in the short- and long-term to cost-effectively integrate ever higher amounts of variable renewable generation like wind and solar.

Flexibility is the coin of the realm

Utility-scale and distributed renewable energy resources are on a tear.  A recent Lawrence Berkeley National Lab report found utility-scale solar total installation costs have dropped 80 percent since 2010, and residential solar systems have fallen 60 percent over the same time.  DOE’s SunShot goal of $1/watt utility-scale solar has been met three years ahead of schedule, and new wind power is coming in below $20 per megawatt-hour (MWh), cheaper than running many coal plants.   But while economics and environmental goals drive increasing renewable generation, variable resources challenge our existing frameworks for grid management and investments.

One key resource need stands out for both the near-term and long-term evolution of our electricity grids and wholesale markets: flexibility.  Flexibility broadly means the grid’s ability to adjust generation dispatch, reconfigure transmission and distribution systems, and modulate demand to accommodate predictable and unpredictable balances between supply and demand.   Flexibility is an aggregate quality of networked grids, combining both the technical capabilities of all connected devices and the system’s ability to efficiently coordinate them.

Current trends have increased the need for flexibility and the opportunity to make more of it available to grid operators.  New variable generation like solar and wind are one of the biggest drivers of need for more flexibility, but aging infrastructure and inflexible power plants, outdated utility business models, and our society’s increasing dependence on reliable electric service also demand a more flexible grid.

Opportunities to unlock flexibility are everywhere: new and more flexible gas plants, storage deployed at all scales, power electronics to regulate wind and solar output as along with transmission and distribution assets, and a constellation of connected devices ready to consume electricity more intelligently.  Expanding the “balancing area” geography over which supply and demand is balanced helps too.

From NREL’s The Value of Energy Storage for Grid Applications

Restructured wholesale electricity markets, which dominate America’s electricity landscape but work best by avoiding specific technology mandates, need to find new and improved ways to surface the value of flexibility and allow current and future market participants to provide it at least cost.

Getting more flexibility today

A new research paper from APP experts Robbie Orvis and Sonia Aggarwal, “A Roadmap for Finding Flexibility in Wholesale Markets,” highlights best practices for market design and operations in a high-renewables future, focusing on ways policymakers can unlock more cheap flexibility.

The paper identifies main challenges to integrating renewables in wholesale markets: managing predictable and unpredictable variation on the bulk system, and doing the same with distributed renewables.  For utility-scale renewables, predictable variability means knowing when a wind front or windy season is coming, or when the sun is rising or setting, with associated net load ramps.  Unpredictable variability comes from sudden weather changes, like unexpected multi-day lulls.  For distributed renewable energy resources like rooftop solar or demand response, unpredictability is a function of exogenous factors like the weather, but also reflects how opaque the distribution system is to bulk system operators.  Distributed assets like PV, efficiency, or demand response can behave predictably, but grid operators need to have more data about where DERs are on the system, what kind of DERs they are, and how they are programmed.

Flexibility is the key ingredient to manage each of these challenges, empowering wholesale markets with the ability to automatically adapt to variations in net-load in cost-efficient and reliable ways.  Best practices from across U.S. wholesale markets illuminate the near-term path forward:

  • Fix market rules to unlock flexibility of existing resources

In one example, system operators can create a net generation product for distributed resources that enables aggregators to participate via fleets, making the size threshold as small as possible.  NYISO’s Behind-the-Meter net generation resource allows behind the meter storage to participate in wholesale electricity markets, including being dispatched beyond the meter.

  • Create and modify products to harness the flexibility of existing resources and incent new flexible resources

Higher scarcity pricing and reserve adders are one of many ways to do this.  ERCOT’s high scarcity price and Operating Reserve Demand Curve adder creates additional value for flexible units during times of system stress.  Where necessary, system operators can create new products for flexibility or products that reward flexible resources, even if just for a limited number of years.  Finally, system operators can pay for reliability services that are of increasing importance but are currently uncompensated, like frequency response.

A clean, high renewables future is within sight. Policy-makers need only look at the best practices of their colleagues around the country to understand how to manage the transition as it happens.

Paying for flexibility and other resources in the future

Over the long term, however, more significant structural changes are likely required to integrate low-cost renewables and manage the major resource base transition animating wholesale markets.  Wholesale markets will need to reach a stable end-state where they can successfully manage real-time dispatch, resource adequacy (especially flexibility) and long-term cost recovery for clean resources.

A second APP research paper, “On Market Designs for a Future with a High Penetration of Variable Renewable Generation,” offers two possible paths for wholesale electricity markets to manage three key challenges in a high renewables future:

  • How will the market pay for the long-term provision of electricity when marginal costs are zero much of the time?
  • How do grid operators make operational decisions of which zero-cost assets to dispatch in times of surplus?
  • What will be the roles of distributed resources, especially the controllable ones? What price signals will they follow and how will they be dispatched?

The first path is an evolved version of today’s markets which becomes increasingly dependent on flexibility from storage and demand-side’s ability to shift consumption for its viability.  The second path splits the market into a long-term “firm” market which covers most consumer needs and a “residual market” which operates much like todays’ spot markets but trades in both withdrawals and injections of electricity against the “firm” market deliveries.

These paths address the challenges above in diverse ways but they also overlap by leaning on long-term contracting, a natural way to align with the investment needs of capital-heavy fuel-light assets.  They also both avoid capacity remuneration mechanisms commonly seen today – in other words, capacity markets.

In addition, the two general paths above for the evolution of wholesale market design in a future with a high penetration of variable renewable energy and distributed resources reveal several important themes:

  • Alignment: Markets must be aligned with physical and financial realities of the underlying for viable market design.
  • Optimization: Markets need the tools to optimize both near-term dispatch and long-term investment in grid assets.
  • Risk Management: Markets must be able to toad value by managing risk by shifting risk from one set of parties to another (customers to generators) and by reducing risk through pooling (lowering costs as well).  Any future market design needs to provide this function.


The transition from today’s legacy grid into a low-cost, low-carbon engine for our future economy is an especially pronounced challenge for restructured wholesale electricity markets because they function through a combination of direct regulatory interventions and dynamic market forces.  The two new APP research papers focus on the start and finish of this transition.  They identify changes needed to provide the opportunity for and manage meaningful increments in renewable generation today and provide a vision for how the future grid might function, consistent with engineering and financial realities.

But another important part of overcoming this challenge includes managing a timely transition to a cleaner grid where many fossil-fueled assets will need to retire before the end of their useful life, and where the grid may sometimes be long or short on some of the resources it needs.  Lessons from today and a vision for future help us on the path, but much work remains to be done.