A version of this article was originally published on October 23, 2015 on Greentech Media.
By Eric Gimon and Michael O’Boyle
One year ago, the D.C. Circuit Court of Appeals decided to vacate FERC Order 745, holding that demand response could not be traded in wholesale energy markets. In the wake of that decision, we discussed ways to pay for demand response in case the ruling were to stand. Since then, the ground has shifted, as demand response (DR) companies and large customers adjust to an uncertain future in which DR may be restricted to retail energy markets.
Now that the Supreme Court has held oral arguments in the appeal of the case and a final resolution is imminent, we contemplate how DR will fare and how the market might evolve. The following discussion—between Eric Gimon and Mike O’Boyle—assumes that the Supreme Court refuses to overturn the D.C. Circuit’s decision and that the bar against demand response in wholesale energy markets stands. Even in the case that wholesale energy markets are barred from trading DR, utilities will still be able to use demand response to hedge against wholesale price spikes. While this ruling potentially affects DR in capacity and ancillary service markets as well, for brevity’s sake the following discussion about the future of DR focuses on the wholesale energy market.
ERIC GIMON
Vacating Order 745 delays progress toward a more efficient grid, but a pivot by utilities and regulators to real time prices for consumers could mitigate the damage and is ultimately a better solution for harnessing flexible demand.
Upholding the D.C. Circuit Court ruling will certainly not spell the end of the DR industry. Regardless of what is happening in deregulated markets, DR is also making headway in regulated markets. In Nevada, for example, the NV Energy mPowered program run by EcoFactor is a demand response and home energy management program that uses an internet-connected smart thermostat and interacts with the customer’s air conditioner. Today, the mPowered program includes more than 50,000 devices, driving a significant peak reduction (>100MW, 3kWs peak per home) while saving customers 10 to 15 percent of their energy bills. Unfortunately, when the local utility is the only arbiter of value, they may or may not do a good job of valuing flexible demand in their own territory; and given how some are unable to share other resources like generation reserves, we can’t assume utilities are going to trade that flexibility with neighboring utilities.
Because utilities are not good at promoting customer flexibility at scale, an alternate solution is required: ultimately, DR’s participation in wholesale markets provides that alternative by allowing customers to largely sidestep utilities. However, real-time prices, updated at least every half-hour, can also provide the necessary conduit through the utility for developing and optimizing the use of flexible DR, in both regulated and restructured markets. This more properly aligns financial reality with the material reality that customers are connected to the grid via their utilities. If customers can respond to rates coupled to wholesale prices, potential DR providers have a financial incentive to provide similar benefits as Order 745 to the market as a whole.
With both wholesale DR and real-time pricing, participating loads need better visibility into and control over their own energy use and generation. Leading DR companies can see the writing on the wall: an energy industry rich in data using software to maximize value. DR providers are branching into other services like energy management software; EnerNOC’s new Energy Intelligence Software business is an example. These activities, as a side benefit, prepare customers for a world with more transparent and granular pricing.
MIKE O’BOYLE
One of the reasons for FERC Order 745 was the lack of real-time pricing on the retail level, which inhibits the market for DR. Since 2011 when Order 745 was issued, not much has changed.
Real-time pricing remains a distant goal for residential and smaller consumers because such consumers generally prefer stable retail prices. Moreover, according to one amicus brief to the U.S. Supreme Court, even in ISO markets where real-time pricing is available to large industrial and commercial consumers, they often purchase their power at a fixed price to hedge against price spikes, reducing the potential effectiveness of real-time pricing programs and obscuring the full value of DR.
Where customers are offered real-time pricing plans, the uptake has been underwhelming. For example in ComEd’s territory in Illinois, enrollment in residential real-time pricing (RRTP) has declined more than 10 percent since 2010. In fact, more than five percent of customers left the RRTP program in 2014, expressing dissatisfaction with rate hikes during the Polar Vortex.
Few if any consumers will take the time to manually react to real-time or hour-ahead wholesale market prices. Automation technologies, like programmable communicating thermostats, are really the only way grid operators and customers can take advantage of the flexibility and bill savings that real-time pricing can provide. Customers’ inability to respond to price spikes (as shown during the Polar Vortex) may reflect the fact that they have not adopted technologies to maximize the benefits of real-time pricing; less than a quarter of ComEd RRTP customers surveyed had any demand management technologies installed even ten years after the program began. These low levels of technology adoption leave savings and grid flexibility on the table.
By contrast, FERC Order 745 allows third-parties to bypass utilities and provide needed flexibility where regulated retail markets have been unable to deliver it. Specialized third-parties can pair technologies with innovative compensation structures that maximize customer satisfaction and price responsiveness. This competitive option also sends a clear signal to utilities to explore demand-side management. But without DR’s participation in the wholesale energy market, customers lose a valuable alternative to potentially under-achieving utility DR programs.
ERIC GIMON
Actually customers are just beginning to benefit from real time markets, and many more might also if regulators made it possible. Customers that are participating in DR markets at the wholesale level already have strategies in place to modulate demand that they can easily adapt to take advantage of real-time prices. Regulators shouldn’t avoid exposing consumers to real-time prices because they can manage risk and the technology is there to support them.
There are many companies—like Alarm.com, Tendril, Opower, Vivint, ADT, Nest, iControl and EcoFactor to name a few—each with over a million home energy management system devices that could easily adapt to real-time pricing. Other companies are already using behind-the-meter resources like battery storage plus distributed solar PV to minimize bills. These represent a broad class of customers ready to dive into real-time pricing, if utility regulators step up to the challenge of providing it.
If other customers are not ready or prefer not to take advantage of the opportunities offered by real-time pricing, they can use insurance-type products to insulate themselves from price fluctuation. For example, customers could opt out of real-time pricing for flat or time-of-use rates offered by their utilities. Similar transactions are quite common in financial markets. Here, the utility would take on the risk of variable pricing in return for a fixed monthly rate.
As an alternative, a customer might just take out insurance against peak rates or bills reaching a certain threshold, like in those severe weather events, just as they might buy insurance against potentially high medical bills. Customers could negotiate with a third-party to cover the cost of installing equipment on-site to manage demand, pay the real-time rates and charge a fixed rate in return, much like an energy service contract or a solar power-purchase agreement. The key is to have real competition in this risk management space so that utilities are just a convenient provider of last resort and can’t use their monopoly position to take advantage of customers not yet ready for real-time prices.
MIKE O’BOYLE
Compared to the current structure for DR, that financial overlay sounds unnecessarily complicated for customers. Instead of a state-by-state mish-mash, Order 745 created uniform interstate standards for DR compensation at the wholesale level, easing the regulatory burden on companies and improving access for consumers. Mandatory real-time pricing coupled with insurance-like products to hedge against volatility would likely vary in states with different policy objectives for the electricity sector. This complexity could further handicap the market for DR.
Even the D.C. Circuit Court ruling agreed that “demand response payments will lower the wholesale price [and] increase system reliability.” In the PJM energy market, reductions in electricity use during a heat wave in 2006 saved customers more than $650 million in one week. In Texas, a study from the South-Central Partnership for Energy Efficiency as a Resource (SPEER) found that modest DR participation would have saved customers $200 million in five days during 2012-2013. With all of these benefits already flowing to consumers and wide participation by DR providers, it is hard to see how real-time pricing could be better for DR’s development and for consumers.
Although capacity value is not the focus of this discussion, real-time pricing is unable to capture additional capacity value of DR. Where there are capacity markets, the benefits of DR have been even greater than in energy markets. Utility DR programs can limit capacity needs, but that value can only be captured locally. Were DR unable to participate in either, real-time pricing would leave potential capacity value for DR on the table in states with wholesale capacity markets.
ERIC GIMON
Despite some inability to efficiently play a role in capacity markets, real-time pricing does offer some advantages over aggregated DR that are worth considering. Namely, wholesale DR depends on establishing a counter-factual baseline against which to measure demand reduction. Establishing the right baseline can be challenging, and it can lead to some perverse outcomes, as Severin Borenstein does a nice job of pointing out in his column “Money for Nothing?“. I especially like his example of the Baltimore Orioles baseball stadium turning on stadium lights during electricity shortages in order to be paid to then shut them off.
I have to agree that regions with a wholesale capacity market, there is an unfair handicap as real time pricing cannot compensate flexible loads for capacity (capacity markets blunt the wholesale price signal), and a great deal of DR’s economic value would be lost. Ideally, power prices at the customer meter should be left to fluctuate without market manipulation or regulatory constructs such as price ceilings, capacity markets, and resource adequacy requirements. Competitive insurance policies or other financial risk management mechanisms are a better way to handle price spikes prudently. Real-time pricing as a strategy for harnessing load flexibility will work much better in energy-only markets like ERCOT which embrace this philosophy.
In summary, in both regulated and restructured markets, regulators should set rates and create markets that more truly value the minute-by-minute cost of consuming electricity even if the Supreme Court upholds Order 745. Social goals like equity can still be maintained by setting the same real-time rates for broad classes of customers, or by including explicit support for low-income or otherwise underprivileged customers. People who prefer flat rates or block rates can be served by insurance, derivatives and other risk-management tools. Customers are then in the best place to capture the total value of demand response, directly for themselves or via an aggregator.
MIKE O’BOYLE
Even with accurate price signals from real-time pricing, utilities may lack motivation to promote DR. By its nature, DR reduces peak demand, which tends to correlate with the need for traditional infrastructure, i.e. more generation, poles, and wires. In almost all jurisdictions, increased capital investments lead to higher returns for shareholders, increasing the value of publicly-owned distribution utilities. So it falls on public utility regulators to ensure that utilities are promoting DR. New regulatory models like the recent proposal under Track Two of New York’s Reforming the Energy Vision proceeding provide examples for regulators to better align utility incentives with customer value.
If Order 745 is history, regulators should focus on aligning utility incentives with promoting cost-effective DR to reduce peak energy consumption and provide distribution and bulk-system benefits. Where there are capacity markets, these same utilities should ensure that the benefit of reduced reserve requirements are passed along to DR providers via additional compensation. Regulators should also allow third parties to compete to provide DR services to utilities and customers.