Navigant Research Blog

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.

 

A Microcosm of Massachusetts Solar Policy

— June 19, 2015

I grew up in Massachusetts, went away for school, spent my 20s exploring other parts of the country, and came back home to settle down and start a family. Working in the energy industry, I closely follow state policy from a professional perspective. However, my personal and extracurricular worlds have also now become entwined in the ongoing soap opera that is the Massachusetts solar policy and its politics: the good, the bad, and the ugly.

For the first 8 years of home ownership, I lived in a condo, where I could not control what was done with the exterior of the structure. I would have loved to install solar while there, but it was not possible due to the building restrictions. I did get the condo association to undertake an energy audit with the local utility, which resulted in several thousands of dollars of savings on our condo fees. This was before Community Solar came into being, which has since flourished in Massachusetts and is perfect for the condo/apartment dweller who can’t install on-site panels.

Two years ago, my family moved into our own house in Franklin, Massachusetts. Literally, the first day we arrived, we had an energy audit and I contacted a solar company to get an estimate for a rooftop array. Without any utility bill history, the company had to estimate our electricity usage based on average square footage values and created a proposal. Knowing that our household would be more efficient than the average, I decided to hold off until we got some real data for a year to avoid unnecessarily overbuilding the solar. It turned out that we use about half the electricity of a typical house our size in our area (according to our OPower report), so it was a good thing we didn’t take the plunge right away.

Worth the Wait

After a year of data collection, I started compiling the plethora of mail offers that we received from various solar companies in preparation for getting some new quotes. Then, I heard about the new concept of municipal solar aggregation, promoted by the Massachusetts Clean Energy Center as Solarize Massachusetts. I figured as long as I was going to do it, I might as well take advantage of bulk pricing and get others in town to benefit from solar, as well. I spearheaded the Franklin Solar Challenge, where a committee of community volunteers put together an RFP and selected a vendor to work with who provided the best combination of pricing, product options, and service. I got my system installed in April after the harsh New England winter and got my first utility bill with $0 due and a bill credit! Over 100 homeowners have expressed interest, and we are on our way to getting the best bulk pricing available for everyone who participates.

 The Results

Brett house

(Source: Brett Feldman) 

But Wait… There’s More

The other side to the solar story in Mass is the fact that the net metering caps in certain utility territories are being hit now, meaning that no new projects above residential-scale can be installed. The state government and stakeholders are trying to work out a solution, but in the meantime things are on hold. I am on the Town Council in Franklin, the elected governing body of the town. We own a large piece of property along a highway that would be perfect for solar development, but due to the cap, it can’t be done at this time and the space might be used for condos and office buildings instead.

So there is a personal story for you that offers insight into the various aspects of solar drama in Massachusetts.

 

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