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 – 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.

 

Batteries Overtake Fuel Cells as California Reopens SGIP

— June 12, 2017

California’s Self-Generation Incentive Program (SGIP) reopened in May after a hiatus that included an overhaul and expansion of the program. Public program data continues to shed light on the competitive distributed energy resources (DER) scene in California as vendors stake their claims. Energy storage, historically a small funding recipient, is now front and center. Stationary fuel cells, historically funded by $0.5 billion in SGIP funds, accounted for zero applications (though the industry forges ahead elsewhere).

The key changes to SGIP are as follows:

  • SGIP reopened on May 1, 2017 with double the previous annual budget—$567 million through 2019.
  • There is a new emphasis on storage, with more than 75% of the budget allocated there. Key reasons for this shift include the need for storage to support intermittent renewables and a shift from carbon-emitting generation.
  • Power generation projects, including small wind and natural gas distributed generation (DG), are allotted less than 25% of total funds—in a category that historically took more than 90% of the $1.25 billion of incentives paid since 2001. Gas DG projects must add at least 10% biogas into the gas mix in 2017, increasing in steps to 100% by 2020.
  • Incentives are awarded across the investor-owned utility territories in 5 steps, with a 20-day minimum waiting period between. If a step is fully subscribed, applicants are entered into a lottery. This lottery was needed for the initial storage steps and allowed all applicants to have a shot at program funds.

A deeper look at the 1,237 applications logged during May serves as a guide to California’s DER space:

  • No fuel cell projects applied in 2017—after nearly half of historical SGIP funds (more than half a billion dollars) were awarded to fuel cell projects. Many stationary fuel cell manufacturers are regrouping around a technology that still has potential.
  • Storage was popular, with step 1 fully subscribed on day one across most utilities: 1,198 of the 1,237 total applications were received on the first day.
  • Generation accounted for just 9 of the 1,237 projects. However, the funds requested for those large projects exceed $6 million, more than 10% of total funds in step 1.
  • Generation’s step 1 was not fully subscribed; it appears the rigid biogas rules are discouraging many potential applicants. This requirement aimed to encourage growth in the biogas industry, but it seems there is insufficient supply or the economics aren’t panning out yet. All four natural gas project applications were based around onsite digester gas rather than directed (offsite) biogas.
  • The program roughly subscribes to the 80/20 rule: 80% of the funds were requested by less than 20% of developers (17 of 117, developers requested 80% of the funds). For equipment providers, there is a favorite: Tesla equipment, presumably all lithium ion batteries, accounts for $29 million, or more than half the applicant funds.

A summary of the leading participants is available at the SGIP website. Note that new data is coming in from step 2, which opened the week of June 5. A historical statistical overview of the program is provided below.

Selected SGIP Statistics

(Source: Center for Sustainable Energy, as of May 8, 2017)

SGIP has had its share of detractors, including claims that it unfairly rewarded certain technologies or companies or overspent ratepayer money. Yet, SGIP’s $1.25 billion in payments have helped cement California’s role as a global DER leader by developing industries that that may be worth much more in the future. In addition, the program has supplied valuable data, including information on capacity factors, efficiency, cost, and other metrics. The understanding of these metrics contributes greatly to the public good and the goal of a transparent and sustainable future.

 

Natural Gas Flaring: Time to Turn a $30 Billion Waste Stream into Profit, Part 2

— May 22, 2017

Part 1 of this blog series covered the state of natural gas flaring; this post examines specific developments allowing stakeholders to put the gas to use.

Flaring, the intentional burning of excess natural gas, contributes a great to deal to climate change. Therefore, this practice is regulated across the globe in the hopes of meeting climate goals. But is regulation necessary? Ideally, this wasted gas would be put to profitable, efficient use, limiting the need for specific flare gas regulations. In fact, several developments are pointing toward the profitable use of associated gas, including improved gas-to-liquids (GTL) technologies, improved onsite combustion technologies, and access to electricity offtakers through microgrids. Consider the following:

  • GTL technologies are improving rapidly. Notably, small-scale GTL players like Velocys, CompactGTL, and many others have commercially available products that convert natural gas into a variety of liquid products, including diesel and methanol, among others. These products have generally higher local value than natural gas and can be transported easily. This points to more opportunities in the developing world—much of which relies on liquid fuels, but has limited access to pipelines. GTL technologies have been held back by low oil prices, but become quite economical in many cases when oil costs over $50 per barrel—a scenario playing out with more regularity.
  • Improved combustion technologies, including natural gas reciprocating engines and microturbines, are opening new opportunities. Manufacturers like Caterpillar and Cummins offer dual fuel generator sets (gensets) that can mix natural gas into oilfield diesel generators. Meanwhile, microturbine vendors like Capstone Turbine offer units as small as 30 kW that can run on a wide range of fuels. GE’s Jenbacher gensets, well suited to handle the variable composition and impurities in associated gas, account for more than 450 MW of installed associated gas generation worldwide.
  • Access to new electricity offtakers through microgrids has the potential to put flare gas to use. Improvements in solar, storage, and microgrid controls technologies make microgrids a popular phenomenon—though such microgrids often call for a consistent baseload fossil fuel source to optimize generation. This is a good match for wellhead gas, which is produced with a relatively consistent output. Various companies are developing microgrids tied to oil & gas production, from Horizon Power in Australia to Mesa Natural Gas Solutions in the United States.

Global Opportunities

As a measure of global opportunities, consider developments in two key markets: Nigeria and Indonesia. Both major oil-producing nations, these countries rank No. 7 and No. 12, respectively, on The World Bank’s flare gas ranking list, accounting for a collective $2 billion in wasted gas (based on the $5.61 per million Btu measure previously outlined).

Nigeria has an aggressive strategy of 75% electrification by 2020 and recently released minigrid regulations that encourage decentralized generation. This, combined with continued oil & gas growth, points to opportunities for the $1.5 billion of wasted flare gas.

Indonesia, meanwhile, recently released new rules that incentivize wellhead power developments—provided that they are close to gas fields and to existing transmission lines and consumers. With more than $500 million in gas flared there, this regulation will open opportunities for microgrid developers, generator vendors, and other stakeholders in distributed power. With billions of dollars of gas going up in smoke and technologies and regulations pushing for efficient generation, opportunity looms large in flare gas alternatives.

 

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