Navigant Research Blog

Navigant’s 2017 Mid-Year Energy Market Outlook: Ongoing Drivers and Cutting-Edge Trends in North American Energy Market

— August 31, 2017

Industry trends and uncertainties continue to transform the North American energy market. Examples include increased renewables in the power sector, technological innovation in energy storage, shifting supply and demand patterns in the natural gas market, and environmental policy uncertainty due to the administration change. Navigant’s 2017 Mid-Year Energy Outlook (NEMO) analyzes how these trends and others are expected to affect the energy and capacity mix as well as market prices over the next 24 years.

Energy Demand

The rate of growth in energy consumption and peak demand has decreased in recent years despite an increase in economic growth. The United States and Canada appear to be transitioning from the long-term trend where growth in energy consumption closely tracked economic growth. While NEMO forecasts overall growth in both consumption and peak demand, the levels of growth (as well as energy efficiency and other demand-side resources) vary between regions. For example, Electric Reliability Council of Texas (ERCOT) and parts of Western Electricity Coordinating Council (WECC) are among the faster growing regions in the forecast. However, New York, New England, and PJM are expected to see lower levels of growth, leading to a slowdown in generation additions. This marks a shift in PJM, where coal retirements, the capacity market, and low natural gas prices have driven the construction of many new merchant natural gas combined cycle power plants in recent years.

Renewable Energy Growth

Despite the absence of a carbon policy, Navigant expects that solar installations will continue to grow in North America as costs decline—though not as steeply as in recent history—and as the technology continues to be pushed by state policies and consumers. In 2016, the United States installed 14.8 GW of solar PV projects, second only to China for annual installations that year. The wind forecast is more dependent on the federal Production Tax Credit that is already declining and set to expire by 2020. This has led to a boom in construction that is expected to peak in 2020 (the last year projects can go online and still get 100% of the tax credit) before declining steeply.

The convergence of increasing renewables penetration and declining battery costs indicates that battery storage is likely on the precipice of increased deployment across the electric grid for renewables integration and the provision of ancillary services. For the first time, Navigant’s NEMO includes an energy storage addition outlook. Energy storage is being implemented in areas such as California to meet policy targets without adding significant new natural gas generation. The revenue that storage projects would expect to receive from avoiding curtailment of renewables is not yet enough to cover the overnight cost of storage, though this could change in the future as the costs of storage decline and renewables penetration increases.

Natural Gas Market Transformation

While the power market grapples with the evolving energy generation mix and the associated effects on the grid, the natural gas market in North America continues its own evolution characterized by threshold events. Exports of natural gas have overtaken imports into the country for the first time in 60 years. US natural gas pipeline exports to Mexico have more than quadrupled since 2010. Exports by ship occurred for the first time from the lower 48 states, with the Cheniere Sabine Pass liquefied natural gas (LNG) export facility delivering LNG to the world market in February 2016. From this point forward, at least to the end of the NEMO term in 2040, Navigant expects exports by pipeline and by ship to continue increasing. Exports are anticipated to grow to represent over 18% of the US natural gas market by 2040.

Navigant’s NEMO covers the changing supply and demand dynamics in the natural gas market, continued renewables generation buildout, slowing load growth, the introduction of emerging technologies like storage, and the continued absence of a federal carbon policy. David Walls and Rob Patrylak will present further details on Navigant’s forecast via a webinar on September 13.


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.


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