It’s been a confusing week for the U.S. energy industry.
Last Friday’s proposal from the Department of Energy, seeking to overturn decades of energy market policy to promote coal and nuclear power plant profitability under a 60-day emergency timeline that’s unjustified by the facts, has pulled together natural rivals like the Solar Energy Industries Association and the American Petroleum Institute in mutual opposition.
Nobody can tell what DOE’s filing is calling for precisely, but energy executives, former Federal Energy Regulatory Commission members and free-market think tanks are uniting in calling it a bad idea.
Amid all this mess and muddle, however, the everyday work of federal energy regulators and grid operators continues. When it comes to the grid edge, the most important work underway is centered on FERC’s November 2016 notice of proposed rulemaking on energy storage and distributed energy resource (DER) aggregation.
This order, which had been on hold until FERC was able to re-establish a quorum and take on its backlogged docket, has prompted grid operators to at least start laying the groundwork for integrating energy storage and DERs into their market operations.
But even in advance of this effort, grid operators are already recognizing the importance of distributed energy resources, from seeking more data on rooftop solar and other load-side disruptions, to opening initial markets for aggregated DERs like demand response or energy storage.
GTM Research grid edge analyst Elta Kolo’s quarterly installment on DER aggregation in U.S. wholesale markets, part of our Grid Edge Service, provides an interesting window into this world. The most recent report for the third quarter of 2017 came out this week, with data on the latest developments from large-scale demand response to just-announced DER aggregation pilots.
The big picture on big demand response
GTM Research found no significant changes to total demand response capacity in the U.S. from last year to this year.
This was largely driven by falling participation in the territory of Mid-Atlantic grid operator PJM, which is being served by less available demand response in both capacity and economic programs for its delivery year 2017/2018, which began on June 1.
Meanwhile, PJM’s new year-round capacity performance requirements led to a May auction that cleared only 7.8 gigawatts of demand response, down 2.5 gigawatts from the previous year’s auction.
While PJM has stuck to its guns on demanding year-round capabilities from its capacity resources, it is looking for ways to allow summer seasonal resources like air conditioning programs to play a part. In August, the PJM Markets Reliability Committee endorsed the creation of a new senior task force aimed at examining how summer-only demand response resources can participate in wholesale markets outside of the capacity market.
This big drop in the country’s largest demand response market overwhelmed increases in other regions, such as MISO’s 440-megawatt increase in available demand response capacity for its delivery year started June 1. MISO also deployed emergency demand response for the first time since 2007, dispatching nearly 740 megawatts of capacity.
California grid operator CAISO is grappling with an underperforming legacy demand-response market, while experiencing an increasingly challenging set of solar-driven supply surges and late afternoon demand spikes. In early May, CAISO dispatched nearly half of its available emergency demand response capacity, about 834 megawatts, for the first time in a decade.
Meanwhile, CAISO’s demand response auction mechanism (DRAM), the first in the country to open aggregations of DERs to participate as utility capacity credits and in its day-ahead energy markets, cleared 182 megawatts for delivery next year and 203 megawatts for 2019 in its latest auction. New participants including Sunrun, Tesla and EcoFactor won bids alongside long-time DRAM participants such as OhmConnect, Stem and Green Charge Networks.
New York's and California’s DERs for energy market efforts
CAISO is also the first grid operator to allow DERs to participate in its energy markets alongside generators, solar and wind farms, large-scale demand response and other existing players.
The program is in its first year of operations, but while several companies have applied to participate, none had done so as of mid-summer, CAISO said. That’s partly because most demand response, as well as big behind-the-meter battery startups like Stem and Advanced Microgrid Solutions, are already enrolled in CAISO’s proxy demand response (PDR) product, which is part of participating in DRAM.
CAISO’s current lack of DER market participants highlights how uncertain these new markets can be, which may help explain why New York state grid operator NYISO has created such limited objectives for its own just-released DER pilot program plans. Pending FERC approval of tariff revisions, NYISO expects to open applications for the program in the fourth quarter, and the first set of pilot projects are slated to be selected by mid-2018.
The program will create a new term, Distributed Energy Resource Coordination Entities (DCEs), to serve as the interface between DERs and NYISO.
A DCE can be a direct customer, a third-party aggregator or a distribution system platform (DSP) -- the REV term for the distribution grid management technology that utilities are supposed to create in the coming years.
DCE aggregations (DCEAs) can be newly formed groupings or aggregations already participating in the NYISO’s existing demand response programs. To participate in the pilot, they will have to be at least 100 kilowatts if demonstrating energy-only capability and 1 megawatt if demonstrating regulation or reserves, with no minimum requirements for individual resources that go into that total.
Maximum capacity by any single participant will be 50 megawatts statewide, or 10 megawatts at a single transmission node, with no more than five individual projects running at any one time.
But there’s no money to be made by playing a part. Participants are required to fully fund their own projects, and NYISO won’t compensate the pilot projects for energy injections, load reductions or ancillary services.
“Whoever will participate will do it to test out the market and develop relationships with utilities and the NYISO, but they wont be looking to make money through NYISO programs in the short term,” Kolo said of the new pilot program. “NYISO DER participation will become better defined once the utilities figure out their aggregation and DSP platform situations. Then, you'll have a more concrete framework that can lead to CAISO-like distributed energy resource provider (DERP) recognition and appropriate tariff revisions.”
Meanwhile, Texas grid operator ERCOT, which isn’t subject to FERC jurisdiction, has put a hold on its long-running proposal for integrating DERs into energy markets.
Even so, as of the first quarter of 2017, ERCOT estimates that there is 900 megawatts' worth of DER availability in areas with retail competitive markets and more than 200 megawatts of DERs on municipally owned and cooperative systems. Distributed generation under 1 megawatt represented an estimated 16 percent of this capacity, but these smaller-scale DERs are slowly on the rise in the region, with a 22 percent increase in capacity from the third quarter of 2016, mainly driven by solar.
Europe’s smart metering market on the rise
GTM Research associate Paulina Tarrant has been keeping close track of global markets for advanced metering infrastructure (AMI), with a particular eye on the long-delayed, but gigantic, opportunities in Europe. Back in May, GTM Research estimated that European utilities will will spend $18.7 billion to install 175 million AMI meters by 2021, equal to nearly 40 percent of global spend from 2017 to 2021.
In a research note released this week, Tarrant provided an update that highlights how, after years of delays and scaling back national rollout plans, things are starting to pick up.
For the first time since 2009/2010, full-scale rollouts represent more than 50 percent of the contracted deployments in 2017, indicating that Europe’s mid- and small-sized utilities are launching full-scale programs alongside phased roll-outs by major utilities such as Iberdrola, GDF Suez and Enedis.
Tarrant also sorted European countries in terms of whether their market opportunities are past, present, or yet to become clear.
Luxembourg, Italy, Finland, Denmark and Estonia have already exceeded EU Commission goals, making them less attractive targets.
The U.K., the Netherlands, Austria, France, Poland and Romania have large-scale smart meter rollout goals and current AMI penetration level lower than 55 percent, making them key drivers of investment through 2020, while the Czech Republic has contracted meters for about 60 percent of its customers. The remainder of European countries have seen poor cost-benefit analysis outcomes, have set conservative goals and have few meters contracted, but could provide opportunities after 2020.