NewEnergyNews: TODAY’S STUDY: How To Use Markets To Grow Flexibility

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    Tuesday, November 07, 2017

    TODAY’S STUDY: How To Use Markets To Grow Flexibility

    A Roadmap For Finding Flexibility In Wholesale Markets; Best Practices for Market Design and Operations in a High Renewables Future

    Robbie Orvis and Sonia Aggarwal, October 2017 (Energy Innovation and America’s Power Plan)

    Executive Summary

    Competitive markets for electricity, or Regional Transmission Organizations (RTOs), are at an inflection point. When RTOs were first created during the 1990s, they designed operations and practices around the technical elements of the grid of that time. Grid operators dispatched large central station generators to follow inflexible load, with power flowing in one direction from these central generators out to customers. RTOs managed the scheduling and dispatch of these generators, ensuring they met relatively predictable demand. While this system and its concomitant rules, procedures, and definitions has worked well for the last 20 years, it is becoming increasingly strained as the grid continues to modernize quickly.

    A Rapidly Evolving Grid Presents New Challeneges And Opportunities

    Today’s grid is evolving in at least four ways due to new innovation and cost breakthroughs in technologies like wind, solar, batteries, and information technology (IT). First, RTOs have to plan for predictable variations in supply in new ways. While managing a predictable decrease in supply is nothing new for RTOs (think of a nuclear unit refueling, for example), RTOs now have to do this on a daily basis with an increasingly large pool of resources whose output is changing. For example, in a region with plentiful solar power, grid operators have to manage the decrease in output from solar in the evenings and ensure sufficient alternative resources are available to dispatch.

    Second, RTOs also have to manage the unpredictable variations in supply associated with higher penetrations of variable resources. As with managing predictable variations, managing unpredictable variations is not new to grid operators. RTOs have managed the grid around contingency events, such as the loss of a generator or transmission line, for decades. However, with growing levels of variable renewables, the sources and degrees of variability have increased. Some of this increase is offset, however, by the fact that historically, unpredictable variations were often the result of large generator failures. The unpredictable variation in output from renewables, on the other hand, tends be much more modular and not highly correlated across resource types, meaning the unpredictable variations will be smaller in magnitude and tend to balance each other out when compared to the historical paradigm of large generator failures.

    Third, grid operators must manage the bulk electricity system (i.e. the transmission system, the domain over which they have control) with increased output coming onto the grid from distributed energy resources (DERs), like rooftop solar. With little visibility into and no control over the types and amounts of resources on the distributed system, RTOs are facing new challenges in accurately forecasting net demand.

    Fourth, innovations in load resources are creating vast new opportunities for RTOs or load suppliers to harness the flexibility of load as a valuable resource. From advanced vehicle charging to electric water heaters that together can act as a giant battery, RTOs increasingly are able to dispatch load resources to balance supply and demand. While changes to the ongoing operations of wholesale markets are necessary, they will be insufficient to fully support the grid transformation. Changes to planning processes, including reliability and resource adequacy approaches – administered by RTOs, public utility commissions (PUCs) and states – will be necessary in competitive power market regions. These capacity and planning issues deserve careful consideration, but are outside the scope of this paper.

    Flexibility Is Key To Successfully Managing The Transition

    Successfully managing the evolving grid comes down to ensuring the grid is flexible enough to handle the characteristics of new resources and capitalize on their capabilities to the benefit of customers. Flexibility comes in many forms, but broadly, it means the ability to respond over various time frames – from seconds to seasons – to changes in supply, demand, and net load. The more flexible the power system, the easier it is for grid operators to manage the system around variable supply and demand. As the system becomes increasingly modular and renewables-based, ensuring sufficient grid flexibility is key to operating the grid reliably and minimizing costs.

    Fortunately, significant amounts of latent flexibility exist in the grid today, and proactive changes to existing market rules can allow RTOs to tap into this flexibility. RTOs must also consider how they can modify existing products and create new ones to harness latent flexibility in the grid today while creating an investment signal for new flexible resources.

    Fixing Market Rules to Unlock Flexibility of Existing Resources

    Simple changes to market rules could unlock a significant amount of flexibility for RTOs. In some instances, existing market rules, even when well intentioned, preclude certain resources from offering services even though they could provide value. In other instances, market rules designed to accommodate certain technologies or contract structures limit the ability of grid operators to tap those resources.

    Require All Generators and Imports to Participate in Economic Dispatch

    In all wholesale electricity markets, some degree of self-scheduling occurs where power plant operators, for a range of reasons, choose to run their plants regardless of the price of electricity. Valid reasons sometimes exist for choosing to self-schedule. For example, a hydro plant may not be able to reduce its output if doing so means that it will overflow or violate environmental constraints.

    Though these instances exist, self-scheduling is often the product of contract terms or financial decisions rather than the presence of technical limitations on a resource. When self-scheduling makes up a significant share of the total amount of electricity available to market operators, it can introduce challenges to operating the grid flexibly. The challenge is in the fact that if power plants are price-takers, i.e. they will dispatch at any price, then they are not responsive to changes in market prices, which reflect the constraints of the electric grid at any given time.

    All generators participating in wholesale markets, including imports and renewables, should be required to participate in economic dispatch. Enforcing this requirement will increase the amount of flexibility available to grid operators by providing them with a wider resource base for balancing the grid. Similarly, during times of very high output of low or zero marginal cost resources, economic dispatch (provided negative prices are allowed) provides a way for grid operators to economically dispatch down specific plants. This doesn’t mean variable renewables ought to or need to be exposed to mark fluctuations; bilateral contracting should continue to be leaned on to mitigate market volatility.

    Preserve Negative Pricing in Energy Markets

    The ability to offer negative pricing in energy markets is an important component of efficient dispatch. Negative pricing allows grid operators to cost-effectively down dispatch resources with varying negative supply offers. It similarly bolsters the investment signal for storage, which can arbitrage the difference in electricity prices during different times of the day and help manage both over-generation as well as ramping. The evidence from negative pricing in today’s markets shows that the impact on average prices is nearly imperceptible (with a few exceptions).

    Increase Flexibility through Better Natural Gas and Electricity Market Coordination

    The limited coordination of natural gas and electricity markets limits the amount of flexibility a gas plant can provide in today’s markets. Historically, natural gas system operators required power plant operators to submit purchase orders for gas prior to RTOs posting day-ahead commitments for generators. In other words, power plants had to guess how much of their output would clear in the day ahead electricity market and purchase an equivalent amount of gas. Because intraday markets for gas are relatively illiquid, power plant operators had little chance to adjust the amount of gas they purchased in response to the amount of electricity they were committed to dispatch.

    FERC recently took aim at these issues with Order 809, which pushed back the day-ahead natural gas nomination deadline to later in the day. With the passage of Order 809, five of the seven RTOs – PJM, MISO, ISO-NE, NYISO, and ERCOT – now post their day-ahead electricity commitments before the natural gas nomination deadline. With the exception of NYISO, however, all of these RTOs provide only a 30-minute window for plant operators to receive their day-ahead commitments and submit purchase orders for gas, which is unlikely to provide generators with sufficient time to optimize their gas purchases. Worse, CAISO and SPP still post their day-ahead commitments after the nomination deadline for gas purchases. Only NYISO, which publishes its day-ahead commitments three hours prior to the gas nomination deadline, provides market participants with a reasonable amount of time to estimate and submit gas purchase orders.

    Other mismatches between gas and electric market timeframes contribute to inflexibility as well. For example, while day-ahead electricity markets operate hourly, natural gas markets only have four trading periods, and intraday trading is highly illiquid. The limited opportunity for purchase adjustments introduces challenges for gas plants, which may choose to generate electricity at a loss rather than pay the consequences of failing to accept purchased gas. A similar issue can arise with operational flow orders (OFOs) from natural gas utilities, which override previous transactions to maintain gas infrastructure safety. OFOs can significantly affect the availability of gas power plants, particularly during times of stress. Addressing these scheduling issues can improve the flexibility of gas plants.

    Minimize Restrictions on Resource Participation

    As new technologies hit the grid, RTOs have often reacted by imposing restrictions on the types of connections and services those technologies can offer. For example, DERs in PJM, including behind the meter battery storage, can only connect as a generation resource or as demand response (DR). Registering as a generation resource is expensive and time intensive, and can significantly drive up project costs. As a registered DR resource in PJM, resources are banned from ever injecting power beyond the meter, limiting the potential of these resources. Other regions have more arbitrary constraints, such as minimum load requirements. For example, ERCOT requires all demand response to have a minimum curtailable load of 100 kilowatts (kW), which can significantly restrict the number of resources that can participate (though is a significant improvement over the previous 1,000kW minimum).

    Addressing relatively arbitrary resource restrictions can tap into a significant amount of flexibility that is available today but going unused.

    Creating and Modifying Products to Harness the Flexibility of Existing Resources and Incent New Flexible Resources

    RTOs must go beyond changing market rules to tap into existing flexibility and incent new flexible resources. To this end, RTOs should modify existing products to harness latent flexibility from existing resources as well as implement new products that create an investment signal for new flexible resources.

    Define Need for Flexibility Services and Allow All Resources to Offer their Capabilities

    Market products should focus on meeting the specific flexibility need and letting all resources compete to provide the needed service. Focusing on the service desired should lead to products that take advantage of the differential qualities of resources, providing additional flexibility at the lowest cost.

    For example, batteries, flywheels, and compressed air storage are able to change output much more quickly than traditional thermal generators, and can therefore provide frequency regulation more effectively, though they tend to be energy-limited. However, frequency regulation rules in many RTOs are designed to accommodate the slower thermal units, in some cases creating barriers for newer technologies.

    Market operators should modify existing products to ensure they are technology-neutral and focused on providing a service at the lowest cost. New products should be created under this rubric as well.

    Create Value for Flexibility

    Increasing shares of variable renewable resources require an increasing amount of flexibility. For example, as solar makes up a higher share of electricity generation in CAISO, grid operators need more ramping in the late afternoon as the sun sets and other units fill in for solar electricity. Flexibility varies widely across power plant types, but is not something market operators have typically considered when designing products or procuring new resources.

    The best way to create value for flexibility is to enhance pricing signals in energy markets. Examples include higher scarcity prices, which incent resources to produce during times of need, and reserve shortage adders, which better reflect the value of resources to the system as it approaches a shortage.

    Another way to create value is through specific products that pay for and obtain the type of flexibility needed by grid operators. For example, CAISO and MISO have created ramping products designed specifically to ensure adequate ramping capability and that units with greater ability to ramp are rewarded likewise.

    Pay for Uncompensated Reliability Services

    An evolving mix of resources on the grid will increase the value of certain resource characteristics while decreasing the value of others. For example, turbine-based generators (including steam and gas turbines) provide frequency response (different from frequency regulation) through inertia and governor response. Frequency response is a valuable element as it helps slow the rate of frequency change. Because turbine-based generators have been ubiquitous in the past, RTOs did not see a need to specifically procure frequency response or indeed to even pay for this service. However, the growth in inverter-based generators, specifically wind and solar, means that less frequency response is endogenously available today to system operators than in the past. Using now-standard power electronics, wind, solar, and battery resources can provide frequency response. However, an opportunity cost can exist for plants to provide this service, so a product should be defined and market mechanisms should be created to encourage provision of the service from whichever resources can do so at the lowest cost.

    As new resources enter the electricity mix and create value for new and different services, RTOs should create new products that expose the value of these services and allow encourage their provision at least cost. For example, requiring all technologies to provide frequency response will likely increase costs unnecessarily. Instead, RTOs should value this capability (and others, as they emerge) and create an incentive for new resources to provide this service as needed.

    Longer Term Structural Changes Will Be Needed

    The changes to market rules, operations, and products proposed here will help RTOs manage increasing shares of renewables in the near to medium term. Over the long term, however, more significant structural changes are likely required. For example, in a system with very high shares of renewables, it may become impossible to rely on the least-cost dispatch algorithms that RTOs currently use (for example, if you have sufficient zero marginal cost capacity to meet load, how do you decide who to dispatch?).

    The long-term solution is much more speculative than the rest of the ideas in this paper, but the market may look like an Evolved Energy-Mostly Market (essentially an extension of today’s energyonly markets with price caps removed) or more of a Product Portfolio (a market with many more welldefined products spanning many different timescales).

    Finding the long-term answer requires new thinking and research.

    Conclusion

    Today’s electricity markets are grappling with a rapidly evolving resource mix. New technologies coming online today are creating challenges and opportunities for RTOs. The existing set of market rules and products must adapt to accommodate new technologies and capitalize on their differences. At the same time, RTOs must modify existing products and create new ones to tap into the latent flexibility in the system today and create a strong investment signal for new flexible resources.

    Fortunately, many examples of progressive market changes are already occurring in the seven U.S. power markets. In the Mid-Atlantic and New York, PJM and NYISO are finding new ways to incorporate battery storage. And in MISO, grid operators now have an economic way to manage output from renewables. These are just a few of the innovative market changes that can help RTOs navigate the growing share of new technologies.

    7A clean, high renewables future is within sight. Grid managers need only look at the best practices of their colleagues around the country to understand how to manage the transition as it happens.

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