Navigant Research Blog

All’s Quiet on the DR Front, but a Storm Is Brewing

— October 7, 2015

Another ho-hum summer for demand response (DR) has concluded as September comes to a close. The last two summers have been light in regards to the need to activate DR resources for most of North America. The East Coast had a second consecutive relatively mild season, with no true heat waves until September. Even Texas, which saw record heat this summer, did not require a large amount of DR to support its grid through peaks. The lone exception is drought-stricken California, which needs all the help it can get to meet its energy and water needs.

This reality lies in stark contrast to the summers of 2012 and 2013, when the weather was hot, new peak load records were hit, and DR was utilized multiple times in markets across the United States. The past couple of years have gained notoriety for needing DR in the winter due to the polar vortex of 2014 and for ever constraining natural gas pipelines as the amount of gas-fired generation grows. It appears that the expansion of energy efficiency programs and solar photovoltaic installations have permanently lowered peak load growth in many regions, diminishing the need for peak support but potentially raising new needs to firm up new load shapes.

This lull just may be the calm before the upcoming storm, however. There was no lack of activity in the court system regarding DR this summer as the actual DR resources sat idly by. One small issue that surprisingly arose was the U.S. Environmental Protection Agency’s (EPA) Reciprocating Internal Combustion Engine National Emission Standards for Hazardous Air Pollutants (known as RICE NESHAP). In 2013, the EPA issued a rule that allowed backup diesel generators to participate in emergency DR programs for up to 100 hours per year. Some states and generator groups appealed this ruling (for different reasons), and in May 2015, the U.S. Court of Appeals threw out the EPA’s rule and told the agency to go back to the drawing board. The EPA has been granted a stay, so its existing rule can remain in place until it comes up with a new one, but the situation has created uncertainty for the 20% or so of DR that utilizes diesel generation.

However, the real fireworks will come on October 14, when the U.S. Supreme Court hears arguments on the case regarding the Federal Energy Regulatory Commission’s (FERC) Order 745 on DR compensation. The two issues at stake are whether DR should get compensated the same as generators in the wholesale energy markets, and, more significantly, whether DR should be allowed to participate in wholesale markets at all. FERC, EnerNOC, and a plethora of state agencies and other DR providers will line up on one side of the aisle, while generators and hardcore economists line up on the other. This could be the heaviest hitting we see until Super Bowl 50 next year.

It’s not too often that someone covering something as esoteric as DR gets to go to the Supreme Court, so I can’t pass up the chance. I will be reporting and live tweeting from the hearing (@BfeldmanEnergy) as much as is allowed and access provides. It promises to be the most riveting courtroom drama since Tom Brady’s hearing against the NFL in the Deflategate saga. I promise not to draw any unflattering courtroom sketches of FERC chairman Norman Bay or anyone else involved.


PJM Capacity Auction Livens Up the Dog Days of Summer

— August 24, 2015

A lot of people normally take vacations and start to think about the back-to-school rush in August, but nothing productive gets done. The same cannot be said for 2015, as PJM’s capacity auction, normally held in May, was moved to August this year due to regulatory proceedings. This change has kept people checking their messages from the beach to make sure they don’t miss any important news while working on the perfect tan.

PJM’s 2018-19 Base Residual Auction (BRA) for its Reliability Pricing Model (RPM) capacity market was held last week and it released results late last Friday. This was the first auction to include the new Capacity Performance (CP) requirements, which increase risk to suppliers but also potentially increase revenue. The auction prices for CP fell within expected ranges, elevated over the last auction. Importantly, PJM only procured 80% of its supply need with CP, with the other 20% coming from Base Capacity (BC) resources, which have lower performance requirements and lower risk. The main analyst sentiment going into the auction was that BC would clear at a much lower price than CP due to the risk premium. This did not turn out to be the case, however, as CP only cleared 7%–9% higher in most zones.

What does all this mean for demand response (DR), which was seen as a wild card in the auction outcome? All signs point to a positive prognosis—well above most expectations—with 11,000 MW clearing, about 100 MW more than the year prior. This increase is probably due to the higher prices rather than any DR industry trends. Over 90% of DR cleared in the BC product. Had the BC price ended up much lower, as was widely expected, it would have been interesting to see how much DR would have stayed in the market.

One big question was how much DR would clear in the CP product given the higher risk of penalties. The answer was about 1,500 MW, less than 10% of total DR. There are many ways to interpret this result. First, it rebuffs the notion that little to no DR would take the CP plunge. So some level of DR is here to stay once PJM starts procuring 100% CP in a couple of years. On the other hand, a very small percentage of DR cleared in CP, so it does not look like a mass-market opportunity. However, a third perspective is that because the CP premium over BC was so small, most DR suppliers chose BC for the lower risk; had the premium been much larger, perhaps more DR would have jumped to CP. A lot of those details are hidden in the bidding strategies of the suppliers and are not made public unless willingly volunteered. EnerNOC normally releases a statement soon after the auction announcing its results, but probably not that level of detail.

PJM has stolen the headlines once again, but I’m sure there will be time to discuss other energy developments once I put my surfboard away and school commences. In the meantime, you can read about EnerNOC and other DR providers in Navigant’s recently published Demand Response Leaderboard Report.


Big Data Meets Demand Response

— August 4, 2015

Historically, demand response (DR) did not rely on real-time, accurate data in order to meet the needs of the utilities and system operators that ran DR programs. It was mostly used for peak load reductions, which meant there were long lead times and events that lasted several hours. Operators did not require immediate performance measurements to ensure system reliability; they could see the aggregated system load shape and determine with enough accuracy whether the desired reductions were occurring. Settlement of DR performance and payments could wait several weeks or months until customer meter data was available and baseline measurements could be calculated. Such was the world before advanced metering infrastructure (AMI), real-time communication capability, and fast-response DR programs and markets.

The use of DR in grid planning and operations has solidified as utilities increasingly rely on DR to meet installed capacity requirements and sometimes even operating reserve requirements. Furthermore, independent system operators (ISOs) led by PJM have incorporated DR into procurement mechanisms for capacity, energy, and ancillary services. DR has been active in the synchronous reserves market in PJM for several years, providing up to 25% of the requirement at times. The frequency regulation market has shown signs of growth for DR, particularly since ISOs implemented FERC Order 755, which affords greater compensation to faster-responding resources.
Such fast-responding programs require more robust data and communication infrastructure than in the past, and such upgrades are typically much more expensive but can be offset by increased program revenue opportunities. PJM recently approved a measurement and verification methodology to allow residential DR to participate in the synchronous reserve market based on sampling of meter data rather than every house needing full-blown metering.

Additional Benefits

Another aspect of data enhancing DR is on the program management side. AMI data gives utilities near real-time views to customer usage in order to forecast loads and availability of DR resources. On the back end of a DR dispatch event, the utility can see almost immediately if it is getting the desired response and react as needed if not, as opposed to flying blind in the past without a means to make dynamic decisions.

The benefits of data even flow into DR program design and outreach. It enables actions such as targeting and geo-targeting for maximum value and the use of smart data in resource potential studies. It helps in developing DR and other distributed energy resources (DER) such that their impacts can be identified at the grid level for functions like integrating DR with other DER (i.e., distributed generation, storage, and renewables) to assess synergies and interactions and use grid-level data combined with customer use data in analyses. The accuracy of virtual audits based on AMI data is still being tested, but is now used to target which customers are likely to benefit most from DR. This can reduce the costs of implementation, provide greater savings, and increase the value of a program.

The topic of data in DR will be addressed in the upcoming webinar, The Rapid Telemetry Edge: Market Trends and Technology Drivers for High Performance Demand Response, on August 18 featuring Silver Spring Networks and Navigant Research.


This Land Is a Demand Response Land for You and Me

— June 26, 2015

Just like the old folk song, June has been a good month for demand response (DR) from California to the New York Island. First, the California Independent System Operator (CAISO) released a proposal to allow aggregated distributed resources to bid into its markets, potentially as early as next year. Then, the New York Public Service Commission (NYPSC) approved all of the plans of the state’s utilities (aside from Consolidated Edison [ConEd]) to commence DR programs this summer. The programs are modeled on ConEd’s existing suite of DR programs.

CAISO found a way to introduce a new acronym, distributed energy resource provider, or DERP, into the industry lexicon. The proposal lays out a framework for allowing aggregated resources of at least 500 kW to participate in the market. There is also a requirement that any aggregations serving more than a single grid pricing point must be limited to a single type of technology. Metering has been one of the hurdles to DR participating in CAISO markets because the system requires generation-scale monitoring. The new rules would allow DR to be aggregated via the Internet, providing for a broader range of resources to be brought to market with less cost. DERP aggregators will be a scheduling coordinator metered entity, which will avoid “having each sub-resource in a DERP aggregation engaged in a direct metering arrangement with the CAISO,” according to the proposal. Access to ancillary markets, however, will still require resources to allow constant monitoring by CAISO. CAISO’s board is set to consider the proposal in July, but would need approval from the Federal Energy Regulatory Commission (FERC) before it can move ahead with the plan.

Meanwhile, in New York …

A week later across the country, NYPSC gave the green light for the upstate investor-owned utilities to follow ConEd’s lead and offer distribution-level DR programs to their customers starting this summer, a very quick turnaround time. This order is one of the early wins of New York’s Reforming the Energy Vision proceeding to transform the utility model in the state. The programs have three basic types: a peak shaving program to be called on a day-ahead basis when demand is expected to hit the summer peak; a local distribution reliability program to be called on as needed for localized issues; and a direct-load control program that lets customers install a device that can be controlled by utilities to control loads to compensate for system stress. Customers can take part in the programs individually or through an aggregator. This summer, the utilities are prioritizing areas that offer the greatest benefits at the lowest costs, based on factors including system stress and local distribution constraints for the year. All of the DR programs will be available starting next summer.

So, while the DR community continues to wait for the Supreme Court’s ruling on FERC Order 745 on DR compensation, the states are pushing the DR agenda ahead rather than waiting for direction from the feds.


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