Navigant Research Blog

Natural Gas Demand Response – Exploring Opportunities: Part 4

— August 24, 2017

Coauthored by Brett Feldman

As discussed in earlier blogs (parts 1, 2, and 3), demand response (DR) has been less prevalent in the natural gas industry than in electricity markets due to the lack of clear market signals that would otherwise enable market participants to put a price on deferred natural gas consumption. However, changing market factors are leading to increased interest in the practice. In this blog, we discuss how one company, National Grid, is participating in innovative natural gas DR programs to discern the value of DR to alleviate distribution system constraints.

Getting with the Program: EnerNOC and National Grid Partnership

From 2012 to March 2017, National Grid offered a fuel switching tariff, known as the Temperature Controlled (TC) rate, to industrial, commercial, and institutional customers in Brooklyn and Queens in New York. National Grid partnered with EnerNOC to manage natural gas consumption at approximately 4,000 customer sites in Brooklyn and Queens. EnerNOC provided National Grid with wireless hardware that enabled automated fuel switching at enrolled customer sites. When onsite sensors detect that outdoor temperatures have dropped below a predefined level, the devices automatically shift fuel sources, optimizing fuel use based on weather and availability.

National Grid is now interested in developing a scalable offering that does not require or incentivize the use of backup fuels. It is exploring opportunities to apply targeted DR to understand how such an offering could alleviate physical delivery constraints on its natural gas distribution system. As part of a pilot program in its downstate New York service territory, National Grid is investigating customer willingness to reduce natural gas demand for a specific 3-hour block of time, 6:00 a.m. to 9:00 a.m., during peak morning usage. Unlike the TC, this pilot will not require customers to have a backup system and will not rely on fuel switching to achieve demand reductions. Instead, National Grid will work with customers to understand how they use gas and what usage can be shifted, earlier or later, or reduced to minimize demand during the peak period.

National Grid hopes to learn how reducing demand during periods of peak usage can serve as an alternative to system expansions. It also wants to gain insights into customer willingness to participate in incentivized natural gas demand reduction programs, similar to its electric DR offerings.

“National Grid knows how valuable [DR] can be based on our experience with electric [DR]. We are hopeful that this pilot will demonstrate that same sort of benefits can be achieved for our gas system while offering our customers a new revenue stream and a program that works for how they do business,” says Owen Brady, New Energy Solutions program manager. “National Grid is always seeking innovative ways to optimize operational performance. Unlike the traditional utility business model of installing pipes to address system needs, we see gas [DR] as a non-pipe alternative that will help us make possible the energy systems of tomorrow.”

In Massachusetts, National Grid is implementing a similar pilot program that is focused on conducting market research to ascertain the appetite of firm and commercial customers for natural gas DR. This program is funded by the Massachusetts Department of Energy Resources (DOER) via a grant to the Fraunhofer Center for Sustainable Energy.

Reducing Costs

The absence of a clear price signal is a significant impediment to the adoption of natural gas DR. Yet, these innovative programs demonstrate that natural gas utilities have a strong interest in exploring the promise of natural gas DR to provide a potentially less expensive means of alleviating pipeline constraints at the distribution level.

 

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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