The Emerging Relationship between Distributed Energy Resources and the Transmission System.
Allison Clements | NRDC
Part 1 of this series can be found here.
To ensure reliable and affordable service to America’s homes and businesses, regional transmission system operators try to predict how much electricity customers will need by as much as a decade into the future. The goal is to ensure there is a sufficient supply of energy to meet predicted demand and enough transmission infrastructure to deliver that supply. In recent years, the rapid increase in consumers reducing their energy waste via energy efficiency and installation of rooftop solar panels generating power locally is having a significant impact on these regional load forecasting process—but not all of the system operators and load forecasting processes they follow are adequately reflecting this DER rise (some regions, like the Northeast, California and the Mid-Atlantic, have already started to make progress in this area). A huge opportunity exists to capture DERs in regional load forecasting across the country and lower overall demand—and, as a result, enhance DERs’ value stream, buffer customers’ wallets and support the fight against climate change.
The Mid-Atlantic grid operator PJM, for example, recently lowered its regional load forecast by thousands of megawatts (MWs) after modifying its forecasting methodology to account for customers’ energy efficiency in the 13-state region. Our calculations, based on an estimate by the research firm UBS, show that the new forecast—which is more than 5,000 megawatts lower in 2019 than before the modifications (the rough equivalent of 7-10 mid-sized coal plants)—could reduce the cost of ensuring future electricity supply in the region by more than $2 billion.* Lower future electricity supply costs (known as “capacity costs”) will ultimately flow through to customers’ electricity bills because the predominant customers in PJM’s wholesale capacity auctions—utilities—pass these costs (and savings) onto their customers. Capacity savings are on top of the utility bill savings customers already realize by reducing their electricity use through efficiency (the cheapest supply resource by a significant margin), and the indirect savings that follow because lower consumption avoids the need for new grid infrastructure investment.
What is regional load forecasting?
Based on their predicted energy demand forecast, regions attempt to understand how much transmission infrastructure (and related wholesale energy generation) will be required as far as 10 years into the future. Regional load forecasts look so far ahead because it takes several years to develop and construct new transmission lines if they will be needed to maintain a reliable system.
In the regions of the country with interconnected electric grids operated by regional transmission organizations known as Regional Transmission Operators (RTOs) or Independent System Operators (ISOs), the RTOs and ISOs engage in load forecasting on behalf of all the utilities in their region. Some regions take a top-down approach, in which the RTO or ISO leads the forecasting process. In other regions, the RTO or ISO simply combines the separate load forecasts of each of its member utilities. Thanks to a 2011 Federal Energy Regulatory Commission (FERC) rule known as Order 1000, neighboring utilities in regions without RTOs or ISOs also engage in regional load forecasting, generally using the simpler combining approach. Whatever method is used, the point is to predict how much energy the homes, businesses and industries in the region will use, year over year, for the next decade.
Importantly, regional forecasting is separate from the forecasting done by retail utilities that sell power for use in our homes and businesses. Within each region, there are utilities that engage in their own load forecasting, which often serve as inputs into regional transmission-system load forecasting. While regional load forecasting is conducted by entities subject to FERC jurisdiction, the retail load forecasting process is conducted as part of state-jurisdictional planning processes.
In addition to responsibility for ensuring sufficient transmission lines, substation capacity and other transmission infrastructure to meet future demand reliably, some RTO and ISO regions – rather than the states in their regions – have responsibility for ensuring enough power generation exists to meet predicted demand in the one-to-three years-ahead timeframe. These RTO and ISO regions employ wholesale capacity markets or utilize resource adequacy constructs, designed to pay power plants and customers that commit to provide power one month to three years into the future (customers also can “supply” power in these markets through demand response by being willing reduce their electricity use at specific times for compensation).
How do DERs come into play?
Historically, regional load forecasting did not capture the impact of energy efficiency. Perhaps energy efficiency programs were smaller in size and relatively less important in the context of consistently increasing customer demand over time. Forecasting also did not contemplate rooftop solar or other DERs, which did not exist in large enough sums to influence predicted demand. In the last several years, significant increases in the amount of energy efficiency and rooftop solar employed on or planned for retail utilities’ distribution systems have changed the equation. It is increasingly important that regional load forecasts recognize the contribution of DERs.
In the cases regional load forecasting processes have started to capture demand reductions from DERs, good things happen. My colleague has noted that according to the U.S. Department of Energy, PJM spent over $28,000 on transmission investments to handle each megawatt of peak demand in 2013, so each megawatt that gets knocked off the load forecast thanks to energy efficiency and rooftop solar is important. In New England, the regional grid operator’s 2012 incorporation of future energy efficiency savings into its load forecast enabled the region to indefinitely defer $416 million in planned transmission upgrades determined no longer necessary.
Reductions in regional load forecasts also equate to lower predicted energy supply needs in the one-to-three year time frame, which means that fewer marginal power plants (which are often the dirtiest, pollution wise) need to stay online. In New England, for example, the regional grid operator ISO-NE predicted that photovoltaic solar generation will reduce regional resource needs by 370 megawatts for the 2019-2020 delivery year, which, based on the ISO’s 2019-2020 auction clearing price, will save customers at least an estimated $31 million in avoided costs in one year. Given ISO-NE’s prediction that PV solar capacity will more than double in the next decade, the potential for savings is significant. Think about the opportunity in regions of the country that are actually hot and sunny most of the year!
What changes are necessary to ensure regional load forecasting captures DERs?
As the early evidence shows, the already exceptional value of energy efficiency in our homes and businesses can be increased if transmission regions capture usage of energy efficiency – and rooftop or other local solar generation – in their regional load forecasting. As rooftop solar and other DERs continue to grow, capturing their existence promises additional savings. To be successful,
1. Annual regional load forecasts should quantify the anticipated impacts of existing and planned DERs on future demand and wholesale system needs. Although energy efficiency is likely the DER with the most immediate potential to impact forecasts, rooftop solar and other DERs will become increasingly important with time.
2. Regions should conduct annual assessments of their load forecast methodologies and results, including accuracy checks.
3. Regional load forecasting processes, including inputs and methodology determinations, should be improved to meet the standards for transparency and opportunities for stakeholder input that FERC requires for transmission planning processes more generally.
Energy efficiency already saves customers money by reducing electricity bills. So why not attain even more savings by ensuring that not only our states, but also our FERC-governed transmission regions, account for energy efficiency and rooftop solar in their regional load forecasting? As a result, regions can retire old coal plants and defer or avoid some new, transmission investments, which should prove an exciting cost savings opportunity for the transmission system regions and FERC.
* In a modeling analysis of PJM’s draft revised forecast, UBS estimated that a 5,000 MW reduction in the forecast would reduce PJM’s Base Residual Capacity Auction clearing price by approximately $40/MW-day in 2018. The $2 billion figure is calculated by multiplying the clearing price savings by the total number of megawatts that PJM would have to procure. See UBS, US Electric Utilities & IPPs: Taking a Load Off at PJM (July 17, 2015), available at https://neo.ubs.com/shared/d1mxmGJkdDpRG/.
Continue to Part 3
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