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.

 

Electric Vehicles and the Clean Power Plan

— August 24, 2015

Power_Paddle_webPlug-in electric vehicles (PEVs) bridge the gap between transportation and electric power—two sectors that until 5 years ago were effectively disparate. Overall, the potential future synergies between the two sectors seem promising. However, because these sectors are somewhat foreign to each other, some uncertainties are likely early on. One area of uncertainty is with regard to the U.S. Environmental Protection Agency’s (EPA’s) Clean Power Plan (CPP), released August 3, 2015.

The CPP is not designed to explicitly affect PEVs; rather, it is designed to decrease electric power sector CO2 emissions from existing fossil-fuel power plants. However, depending on the method by which each state implements the policy, PEVs may present a detrimental or beneficial component to state compliance strategies.

Because each state has a different electric power generation mix, each state will have individual goals and pursue varying strategies in order to comply with the CPP. The CPP CO2 reduction goals have been developed by the EPA using a rate-based approach, which places CO2 per megawatt-hour limits on power plants, but states may also use a mass-based approach (i.e., total metric tons of CO2 from the electric power sector).

PEVs Increase Demand

The mass-based approach will likely create complications for states with fast growing PEV markets. The complication arises on behalf of the fact that PEVs increase electricity demand, which increases the total emissions from power plants, while the overall CO2 reductions achieved on behalf of the PEV are not integrated in CPP calculations. This means that while a PEV would likely reduce net CO2 emissions, PEVs could make state compliance efforts for the CPP more difficult.

The rate-based approach may produce similar complications; however, this is entirely dependent on what grid resources are used to fuel PEVs. For instance, utilities may design incentives to coordinate PEV charging with peak solar or wind generation times, which would in effect increase utilization of renewable generation assets, decreasing the average rate of CO2 emitted per megawatt-hour produced in a state.

Vehicle Grid Integration

Programs and technologies to shift PEV charging to off-peak hours and integrate PEV charging into advanced grid services are being developed in large PEV markets. BMW’s iChargeForward program, which aggregates 100 BMW i3s in the San Francisco Bay Area for grid services, launched in July. Recently, charging station manufacturer eMotorWerks and non-profit software developer WattTime debuted a charging station that can automatically schedule PEV charging when the carbon emissions from the grid are lowest.

While the load represented by PEVs is still marginal compared to overall electric power sector demand, PEVs will become an ever increasing concern. Navigant Research estimates that the average PEV can increase the average U.S. household annual energy consumption by around a third and estimates that the median state PEV market share of 0.5% in 2014 will grow to over 2.5% by 2024. By the time the CPP takes effect in 2022, this equates to 4.4 million light duty PEVs in use, each consuming around 3,000–4,000 kWh annually.

PEV Market Share (% of New vehicle sales) by State, United States: 2014, 2024

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(Source: Navigant Research)

As PEV adoption reduces overall emissions in most states and cases, state PEV adoption incentives should not run contrary to state CPP compliance efforts. Rather, states should encourage efforts to utilize PEVs as potential distributed generation/energy storage resources useful for CPP compliance.

 

Proposed ASHRAE Standard Enables Smart Facility to Smart Grid Communication

— August 24, 2015

The Facility Smart Grid Information Model devised by the American Society of Heating, Refrigerating and Air-Conditioning Engineers (ASHRAE) and the National Electrical Manufacturers Association (NEMA) is open for public review until October 6, 2015. The purpose of the standard is to define an information model to enable building automation systems and appliances in commercial, industrial, and residential facilities to manage electrical loads and generation sources in response to communication from a smart electrical grid. As a result, utilities and electrical service providers also receive information about electrical loads and distributed generation production. The standard is also under consideration for adoption as an international standard by the International Organization for Standardization.

The Benefits

An improved information model can be extremely beneficial to facilities. If energy characteristics of a facility’s energy consuming, storing, or producing systems can be tracked and communicated between the grid, facility managers will better understand what factors are affecting their energy consumption. They can then find ways to effectively reduce the energy consumption of their facility. The facility also gains the ability to receive information from the grid; information on supply shortages, real-time energy pricing information, or demand response signals can be received and adjusted for by facility operators. Enhanced grid communication will allow for operators to be more aggressive with energy management.

For utilities and energy providers, the information model enables communications with various facility types through a common protocol.  The energy providers can then more accurately forecast energy demands and responses to any energy supply constraints.

Interoperability

Smart grid cyber security and interoperability are challenges of great significance. Under the Energy Independence and Security Act (EISA) of 2007, the National Institute of Standards and Technology (NIST) is primarily responsible to develop the standards for information management to achieve interoperability of smart grid systems and devices. To generate the requirements needed for interoperability standards, a Smart Grid Interoperability Panel (SGIP) was formed by experts from the fields of communications technology, power and transmission, renewables, transportation, energy storage, regulators, consumers, and smart buildings. The Facility Smart Grid Information Model is a supporting effort by ASHRAE and NEMA to help the SGIP.

Enabler for Technologies

An approved and standardized information model will allow for enhancements to enabling technologies. Building automation system manufacturers can then enhance product offerings to better monitor and manage facility equipment with received information about supply shortages or real-time energy prices. Generation or storage systems can also be optimized for potential weather impacts or supply shortages. The Facility Smart Grid Information model is an important step toward information exchange between facilities and the grid. Looking ahead, it can drastically change the landscape of building energy management.

 

Distribution Resource Plans: Integrated Capacity Analysis

— August 24, 2015

As discussed previously, California investor-owned utilities recently submitted their inaugural Distribution Resource Plans (DRPs), establishing a framework for the integration of distributed energy resources (DER) into the existing electric grid. As adoption rates for rooftop PV generation, behind-the-meter storage, and electric vehicles (EVs) rise, it becomes increasingly important to determine the extent to which the distribution system can accommodate the newcomers. To this end, the DRP filings include an integration capacity analysis (ICA), providing utility estimates of the ability of each of their circuits to incorporate DER. One of the goals of this analysis is to improve the efficiency of the grid interconnection process by providing DER hosting capacity data to the general public and third-party providers.

Integration Constraints

Per the guidance of the California Public Utilities Commission (CPUC), the utilities collaborated and developed a common set of constraints on integration capacity. The distribution system is designed to operate below equipment thermal limits, maintain voltage within acceptable bounds, avoid compromising protection schemes, and function safely. Therefore, each circuit segment was evaluated to determine the maximum amount of DER that can be connected to the existing electric systems without violating these rules. Southern California Edison (SCE) performed this analysis on a set of representative feeders and extrapolated the results to its entire service territory while Pacific Gas and Electric (PG&E) studied each individual circuit. Navigant expects that the next iteration of the DRP filings will require individual circuit analysis. In addition, there are plans to extend the set of evaluated criteria, as well as include an assessment of hosting capacity during expected switching operations and abnormal conditions.

Integration Capacity Criteria

Fig 1 blog
(Source: Pacific Gas and Electric)

DER Profiles

Because each category of DER has its own effect on the grid, the utilities had to perform different calculations for each resource type. Each utility had a different approach for this task. SCE separated resources into load-reducing (PV and storage) and load-increasing (EVs and storage) resources, while PG&E considered the hourly profile of each resource type separately. As the integration metrics are driven by net load, using hourly load impact profiles for each resource type will be necessary to optimally perform the analysis in the future. San Diego Gas & Electric (SDG&E) notes that it will acquire customer demand profiles from its advanced metering infrastructure (AMI) and localized DER impact profiles in order to improve the locational granularity of its next ICA.

DER Profiles 

Fig 2 blog
(Source: Pacific Gas and Electric)

Streamlining Interconnection Processes

One of the requirements of the CPUC guidance on DRP content was consideration of the applicability of the ICA to Electric Rules 15, 16, and 21 governing EV and distributed generation interconnection requirements. Perhaps contrary to CPUC expectations, while the utilities each allowed that the results of the ICA could be used to inform the interconnection process, none allowed it to immediately replace any of the required screens for fast track analysis. An augmented iteration that includes fast-tracked circuits and estimates of locational value would strongly support the integration of distributed resources.

The approach to the ICA displays a consistent theme across the DRP filings. Despite organizing around the same principles, the outcome methodologies are different enough to portend plenty of alignment discussions heading into the 2017 filing period.

 

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