Navigant Research Blog

This Land Is a Demand Response Land for You and Me

— June 26, 2015

Just like the old children’s song, from California to the New York island, June has been a good month for demand response (DR) from coast to coast. 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 state’s utilities’ plans (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.

 

Dispatches from the National Town Meeting on Demand Response

— June 4, 2015

One year after the U.S. Court of Appeals’ decision to strike down Federal Energy Regulatory Commission (FERC) Order 745 and question FERC’s jurisdiction over demand response (DR), the DR community appeared alive and well at the 12th annual National Town Meeting on DR in Washington, D.C. There was a plethora of enthusiasts, from utilities, regulators, and vendors, talking about drivers for DR and how the industry could progress in a post-745 world should the Supreme Court uphold the lower court’s decision.

The event kicked off with a roundtable of state regulators discussing DR and, more broadly, electricity industry transformation based on distributed energy resources (DER). Michael Picker, president of the California Public Utilities Commission, compared the DR industry to the telecommunications industry by talking about how incumbent communication providers lost 40% of their landline base and the world transitioned to a mobile model. The dialog was past the utility death spiral concept, but it indicated that the reality of stagnant or decreasing load and customer-side energy solutions will have to be addressed. The big chicken-and-egg question was whether regulatory change or business model change needs to come first, and little consensus was reached.

Changes Ahead

Following the regulators, a panel of utility executives outlined their opportunities and pain points from the changing landscape. Interestingly, when given a list of disruptive technologies to rank, energy storage and solar came out on top, while DR was on the bottom. DR is seen more as a positive force and tool for the utility to manage the grid and engage customers. One theme that arose is that utilities will need to add new skills to their workforce as the business shifts from strictly a wires and hardware model to more software, information technology, and customer outreach.

One other major area of focus was New York’s Reforming the Energy Vision (REV) proceeding. REV has gotten a lot of attention since it was launched a year ago, but now people want to know where the rubber will hit the road. It appeared that speakers who are involved in REV had a bit of trouble really explaining the market transformation that is espoused. That doesn’t mean that important changes won’t occur, but as the rest of the country watches REV proceed, it will learn what to emulate and what to avoid.

These issues and other drivers and barriers to DR are discussed in Navigant Research’s new Demand Response Enabling Technologies report. By the time the National Town Meeting comes around next year, the Supreme Court will have decided DR’s fate one way or another … and hopefully it won’t make for an unlucky 13th gathering.

 

California Drought Implications for Electric T&D Becoming Clearer

— June 2, 2015

The implications of climate change and the 4-year California drought are just beginning to become clear. The snowpack in the Sierras, where reservoirs and dams ultimately feed the canal system that delivers water to the Bay Area, the Central Valley, and Southern California, is at an all-time low. While strict water rationing is mandatory for some residential and commercial consumers in many parts of the state, there are other forces at play. Some are laudable, and some are not.

On one hand, many city and municipal water districts are offering new rebate programs and incentives to remove lawns that require watering and replace them with xeriscape landscapes that require little if any water. On the other hand, the agricultural economy in California’s Central Valley needs water for almonds, pistachios, and a host of other products, and the large farms are reportedly pumping down the aquifers to support their business.

Thinking Long Term

Prolonged drought could also have major effects on the electric transmission and distribution (T&D) system, as well as on the water delivery system across California.

  • The major water agencies, including the Association of California Water Agencies (ACWA) managing the canal system between Northern and Southern California, have for many years been not only a major end-use consumer, but also a demand response resource for the California Independent System Operator (CAISO).  If the volume of water moving south through the Central Valley and over the mountains into the Los Angeles basin decreases substantially, the loss of demand response resources during peak demand conditions could be substantial.
  • With limited snowpack, major California reservoirs are now at record low levels and have limited, if any, hydropower capacity. Innovative pumped water storage projects like Pacific Gas and Electric’s (PG&E’s) Helms System, which uses off-peak Diablo Canyon nuclear power to pump water up for day-time generation use, will be at risk.
  • Recent reports in media have suggested that many locations in California’s Central Valley are sinking as a result of ongoing water pumping from the underground aquifers by all types of commercial and agricultural businesses. Not only are residential, commercial, and agricultural wells going dry, but the land itself is subsiding. This has tremendous implications for California’s Peripheral Canal system and other longstanding canals that transport water north to south through the central valley. As subsidence occurs, it is entirely possible that cement canals will fracture, and major leaks will occur, further exacerbating the water loss problem.

As in many states, the electric transmission infrastructure in California is aging. It’s clear that California’s drought will have a significant effect on the electric power market as well, degrading demand response resources, electric demand for water pumping, and hydropower resources.

 

Waiting for the Supreme Court’s Call

— April 28, 2015

Many are waiting for the Supreme Court to decide whether it will take up the case on the Federal Energy Regulatory Commission’s (FERC’s) Order 745 on demand response (DR) compensation, possibly by the end of April. I thought it would be worthwhile to take a look at the contingency or stop-gap plans that some of the affected regional transmission organizations (RTOs) are contemplating, particularly for the capacity markets where the vast majority of DR participation takes place. PJM started the process several months ago; the New York Independent System Operator (NYISO) began a couple months ago; and the Independent System Operator of New England (ISO-NE) just released its proposal last week. All of them start from similar basics, but there are differing details that may affect the effectiveness of each one.

PJM: Laying the Groundwork

PJM laid the groundwork first and came up with a straightforward proposal whereby the DR would be moved to the demand side of the reliability pricing model (RPM) capacity market. The load-serving entity (LSE), which provides the retail electricity supply to customers (either a utility or a competitive supplier), would reflect the DR in its demand bid. This would lower the total demand in the market, leading to the same price effect as if the DR had bid into the supply stack.

Integration of DR Bids with RPM Demand Curve

(Source: PJM Interconnection)

In theory, this approach gets around the FERC jurisdictional issue in the court case because it would be retail entities bringing the DR to the market instead of direct wholesale market participation. The concern from DR providers is that this structure adds an extra layer of administration between the customer and the market, since the DR providers wouldn’t be able to bid in directly (unless they were an LSE) and they would have to work through the LSEs. That relationship may necessitate extra legal documentation. Plus, some LSEs may not be motivated to encourage DR and could bog it down, leading to a reduction in the amount of DR in the marketplace. PJM even submitted this proposal to the FERC to be proactive and have it in place should the court force its hand, but the FERC ruled that it was premature instead of proactive and should not be formally introduced until the court verdict is clear.

NYISO Twist

NYISO basically used the PJM proposal as a starting point and built upon it. After getting feedback from market participants about the drawbacks of the PJM structure, NYISO added a twist in which the LSE is basically just a pass-through mechanism for the DR to reach the market, while the DR providers are still the contracting agents that register the customers with the NYISO. This adjustment eases some of the perceived constraints from the PJM model, but there are still a lot of details that need to be worked out in terms of bidding and how DR providers can continue to participate in the NYISO stakeholder process.

ISO-NE Approach

ISO-NE had been pretty quiet on the matter until April 17, when it released its contingency plan. It took a different path than NYISO to try to address some of the shortcomings of the PJM approach. It still relies on the LSE to administer the DR, but it purports to provide more incentive to the LSEs to do so by changing the cost allocation methodology for capacity costs from a fixed charge to a performance charge reflecting the actual consumption of customers during scarcity conditions. LSEs consuming less than their allocated share of capacity would see their charge go down; the converse is true for those consuming more. In theory, this model incentivizes LSEs to reduce their load during these times; reality could prove otherwise if none of the large LSEs feel the risk outweighs the potential benefits.

There you have three different approaches to address the same issue. Perhaps none of them will be necessary if the Supreme Court ultimately vacates the lower court’s ruling, but in the meantime, many smart people have spent many hours getting ready for the worst-case scenario.

 

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