Navigant Research Blog

Natural Gas Demand Response – Current Utility Programs: Part 3

— July 25, 2017

Coauthored by Paul Moran

As we discussed in our last blog, demand response (DR) in the natural gas sector has been less prevalent in the natural gas industry than in the electricity industry due to the lack of clear market signals that otherwise would enable market participants to put a price on deferred natural gas consumption. However, changing market factors are leading to increased interest in the practice. There are several utilities currently running innovative natural gas DR programs to discern the value of it alleviating system constraints.

Rebates for Home Heating

This year, Southern California Gas (SoCalGas) launched a natural gas DR program called the SoCalGas Advisory Thermostat Program, partially in response to supply concerns related to a leak at its Aliso Canyon natural gas storage facility. It offers program participants up to $50 in rebates while helping them reduce natural gas costs for home heating. To be eligible for the rebate, program participants agree to allow minor adjustments to their smart thermostat settings on days when a SoCalGas Advisory conservation event is called. SoCalGas manages the ecobee thermostats and makes adjustments remotely, using a software platform developed by EnergyHub. Participants are notified before any adjustments occur. This represents the first rebate program of this type offered by a natural gas utility for gas heating.

Interruptible Gas Has Its Perks

Xcel Energy has an interruptible gas program for large commercial and industrial customers that does not include physical control of the gas supply by the utility. It is used to allay pipeline or distribution constraints as well as economic concerns when gas prices increase or spike. Customers get a notice one hour prior to the need and then it is up to them to decide what to curtail or whether to go on a backup fuel supply. It can be isolated to certain geographic areas on the system rather than an all-or-nothing approach.

Pilot Programs in New England

The New England region is at the literal end of the gas pipeline infrastructure and is at risk of experiencing more supply shortages than other areas of the country. Even before the polar vortex, the Independent System Operator of New England instituted a winter fuel supply program, including winter DR. Some of the Massachusetts utilities have undertaken pilot programs with smart thermostat vendors like Nest to test the natural gas DR theory with residential customers by changing heating setpoints. The programs have not yet moved beyond the pilot stage.

Although the absence of a clear price signal is a significant impediment to the adoption of natural gas DR, these innovative programs demonstrate that utilities have a strong interest in exploring its promise to provide a less expensive means of alleviating pipeline constraints. In our final blog of this series, we will discuss how National Grid is exploring new applications for natural gas DR to reduce peak load and improve system efficiency across its service territory.

 

EnerNOC Loses Its Crown as the Last of the Pure-Play Public Demand Response Companies

— June 23, 2017

And then there were none. All the pure-play energy efficiency and demand response (DR) public companies have now been gobbled up by large industry players. First, Comverge went private in 2011 and was recently acquired by Itron. Then Opower was bought by Oracle in 2016. Now EnerNOC has been acquired by Enel Green Power North America (EGP-NA) for $300 million. It was no secret that this was going to happen, as EnerNOC had essentially put itself on the auction block earlier this year. The only suspense was who the buyer would be. I don’t know anyone that had EGP-NA in their betting pool. I saw EnerNOC’s CEO Tim Healy at the Edison Electric Institute’s annual conference in Boston last week, and he did a great job keeping his poker face on.

The likely scenarios seemed to include either being taken private by a private equity company, like what happened with Comverge, or being bought by a large vendor like General Electric (GE) or Schneider Electric. It was not probable that a US utility would be in the mix. But European utilities like ENGIE have been active in getting footholds in the US distributed energy resources (DER) market with more customer-facing solutions. EGP-NA had been one of the quieter ones. By adding the EnerNOC deal to its recent acquisition of energy storage software/project developer Demand Energy, EGP-NA has pushed itself toward the forefront of this market.

A Lot of Opportunity

EGP-NA has no existing DR infrastructure, so there should not be a lot of overlap in terms of personnel or resources. The move should help EnerNOC expand more quickly in the European markets. The press release on the deal quoted Healy as saying, “we look forward to accelerating the growth of our core businesses and to delivering ever more value to our customers as we lead the transition to a more sustainable, distributed energy future.” So it seems like there is a lot of opportunity for EnerNOC to pursue, but it will likely face integration risks as the deal gets consummated.

I am glad that it appears that EnerNOC’s main business and position in the DR industry will continue. I was worried that a private equity firm might pick it apart and sell the pieces. I look forward to seeing the company expand DR further around the globe.

On the downside, I won’t have any more exciting transactions to write about. I guess we’ll have to wait and see if all of these recent deals pan out in a few years or if the next wave of news will be the large players selling the smaller DER players after unsuccessful integration attempts.

 

PJM’s Latest Capacity Auction Shows Drop in Demand Response, but Not Catastrophic

— May 25, 2017

The holding of breath for PJM’s annual capacity auction results ended on May 23, with the results indicating mixed feelings. The price for most of the market was down from $100/MW/day for the 2019-2020 auction last year to $76.53/MW/day for 2020-2021. However, certain subzones cleared at nearly twice that price or more, so bidders in Chicago, Philadelphia, New Jersey, and Cincinnati came out smiling.

For demand response (DR), there was a lot of speculation going into the auction about the effect that the first 100% Capacity Performance procurement would have. Some analysts predicted 50% or greater reductions in DR participation, assuming most DR providers and customers would not want to take on annual performance risk. In my Market Data: Demand Response report for Navigant Research last year, I estimated a 25%-30% reduction, feeling that large commercial and industrial (C&I) customers would continue to participate; DR providers would continue to aggregate midsize C&I customers with more conservative megawatt values; and residential DR would take the biggest hit since it is almost all summer based.

Pricing, Aggregation Rules Influence Auction

The actual reduction was 24% from the last auction, dropping from 10,348 MW to 7,820 MW. Nothing to sneeze at, but far from a total market abandonment. Last year, only 614 MW of DR cleared as an annual product, so there was a large portion that was willing to convert. Pricing may have influenced DR quantities as well. While all zones decreased year-over-year, the zones with the lowest prices showed the biggest drops and those with higher than expected prices shed fewer megawatts.

This was also the first auction in which PJM instituted new aggregation rules, where summer and winter resources could match up with each other to meet the annual obligation. While 2,000 MW of summer resources (mostly DR, energy efficiency, and solar PV) submitted aggregation bids, only 485 MW of winter resources bid (mostly wind), limiting the effects of the new mechanism.

Silver Linings

Historically, EnerNOC has happily proclaimed its percent procurement of PJM DR in the auctions, but has been quiet the last couple of years. However, this year EnerNOC tweeted: “@EnerNOC captures 34% of the DR market in #PJM BRA.”

On the residential DR side, it appears that the Exelon utilities—which have been the biggest bidders in that sector—largely pulled out of the auction from the supply side. The utilities had put out an RFP in March looking for 700 MW of winter resources with which to aggregate, but apparently did not find enough partners. However, this does not mean that they exited the capacity market entirely. PJM reported that, for the first time, price-responsive demand resources cleared in the auction to the tune of 558 MW, mostly in the Baltimore Gas and Electric and Pepco regions—likely from those host utilities. If those megawatts get added to the DR megawatts that cleared in the auction, the drop is only 19% from last year.

All in all, I’d consider this a positive outcome for DR compared to some of the draconian forecasts. Now we’ll have to see how well the market performs once the annual requirement kicks in.

 

Natural Gas Demand Response – Not Just for Electricity Any More: Part 2

— May 17, 2017

Coauthored by Brett Feldman

What Is Holding Back Natural Gas Demand Response?

As we discussed in our earlier blog, demand response (DR) in the electricity sector has been a common practice for decades for utilities and grid operators. Historically, DR has been less prevalent in the natural gas industry, but changing market factors have increased interest in the practice.

In this blog, we discuss the opportunities for DR in the natural gas sector and describe some of the major challenges. A key area of opportunity for natural gas DR lies in alleviating pipeline capacity constraints during periods of peak usage, which are typical spikes in demand driven by extreme weather or logistical issues.

Natural gas DR is alluring because it is theoretically less expensive than expanding existing infrastructure or constructing new pipeline and it incentivizes consumers of natural gas to defer or forego demand during periods of peak usage in exchange for compensation. Before we can determine the price of deferred natural gas consumption, however, we must establish its value.

What Is the Value of Natural Gas DR?

One of the reasons electric DR has been successful is that it reduces electric demand. Perhaps most importantly, it also has a clear, established value: the wholesale, retail capacity, and energy price that an electric DR provider typically receives for each negawatt of reduced demand that other market participants—like generators—are paid for each megawatt of delivered power.

There is no equivalent price for a nega-molecule of methane in natural gas markets. The price value of gas DR would have to be a negotiation due to an absent market structure. To provide an incentive for natural gas DR, the price would need to be equal to or less than the price paid for consuming the gas. A key challenge to determining the value of DR is that although natural gas prices can demonstrate significant volatility during periods of increased demand, many consumers of natural gas do not pay these high prices—at least not directly.

How Do We Develop a Price Signal?

Residential consumers, for example, purchase their natural gas supply and transportation through their local distribution company (LDC). The LDCs, in turn, typically rely on a variety of gas transportation and commodity supply plans with varying terms and prices. As part of their obligation to serve, the LDCs are required to build gas supply plans that mitigate the exposure of customers to volatility in prices. During a period of extreme increases in demand, the LDC may need to procure additional supply during certain days throughout the year, but these purchases are typically a small fraction of the overall daily demand. Most LDCs charge customers monthly, which causes the extreme price increases to become a small component of the overall bill.

Many commercial and industrial (C&I) customers, including power generators, purchase natural gas supply from a LDC. Larger C&I customers arrange transportation through an interstate or intrastate pipeline company to obtain their commodity via a marketer. Although the physical delivery arrangements are different compared to the residential sector, the economics are similar and the barriers to the development of a price signal for deferred consumption remain the same.

The absence of a clear price signal is a significant impediment to the adoption of natural gas DR despite the promise of providing a potentially less expensive means of alleviating pipeline constraints. Regardless of these challenges, natural gas DR offers a viable method to shift gas consumption during periods of peak demand.

Part 3 of our blog series will explore what utilities have tried for natural gas DR in the past and what new concepts could develop in the future.

 

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