Navigant Research Blog

Should We Worry About Carbon Dioxide Emissions From Natural Gas Surpassing Coal?

— September 13, 2016

Smoke StacksAccording to the US Energy Information Administration, in 2016, CO2 emissions from natural gas are expected to surpass coal emissions in the United States for the first time since 1972. As CO2 emissions from natural gas increase due to growing natural gas consumption in the energy sector, major concerns have developed among environmental groups and others about natural gas becoming a threat to climate change. However, to generate the same amount of power, natural gas emits only 55% of the CO2 compared to coal. As natural gas displaces coal, CO2 emissions that could have come from coal will be cut by half. As long as the growth of natural gas is at the expense of coal consumption, it will help the fight against climate change.

It would be ideal if both natural gas and coal could be replaced with renewable energy such as solar and wind. However, when the sun doesn’t shine and wind doesn’t blow, electricity still needs to be generated. Even with cutting edge technology on energy storage, demand-side management, and energy efficiency, the need for stable electricity generation from reliable sources cannot be fully eliminated. Natural gas is by far the best option for such a reliable source due to its affordability and abundance in the United States. Besides the benefit of fewer  emissions, the price of natural gas is also competitive with coal. The United States is also the largest natural gas producer in the world thanks to the boom of shale gas. In general, as more renewable generation capacity will be added than fossil fuel capacity this year (and likely in the next few years), natural gas is essential as a backstop for grid operators to address the intermittency of renewable energy.

The Problem of Methane Leakage

Nevertheless, natural gas is not perfect. The methane leakage problem could seriously undermine the climate benefit of natural gas. At the same time, the US Environmental Protection Agency is making crucial progress in setting regulations on restricting methane leakage. With proper regulatory incentives and continuing technology improvement, the effects of methane leakage can be contained to make natural gas a viable complement to a lower carbon future.

 

Europe’s Energy Transition Megatrends and Tipping Points, Part V: Globalisation and Regionalisation of Energy Resources

— September 2, 2016

Oil and Gas ProductionJan Vrins coauthored this post.

In our initial blog on Europe’s energy transition, we discussed seven megatrends that are fundamentally changing how we produce and use power. Here we discuss how the globalisation and regionalisation of energy resources is fundamentally changing the European energy industry.

What’s Happening?

The EU is actively aiming to deliver on Europe’s 2030 climate and energy targets while ensuring security of supply and affordable prices. The EU also seeks to be a world leader in renewable energy. Achieving these goals requires a transformation of Europe’s electricity system. To assist in this transformation, the EU must achieve a balance of meeting consumers’ expectations, delivering benefits from new technologies, and facilitating investments in low-carbon generation while also recognising the interdependence of member states. A critical part of this initiative is connecting isolated national and regional electricity systems to secure supply to help achieve a truly integrated EU-wide energy market—a key enabler for the continent and one that goes well beyond precursors such as Nord Pool. While the United Kingdom’s vote to leave the EU raises a number of questions about future policy, it is too early to say what effect Brexit will have on the United Kingdom’s participation in the EU’s future single energy market. (The United Kingdom has, however, been an enthusiastic proponent of this to date.) What is clear is that a focus on greater levels of interconnection (both offshore and onshore) and energy efficiency will continue to be necessary aspects of EU energy policy—and ones that receive much scrutiny.

To get access to the necessary energy supply and resources, more regions, countries, energy markets, and utilities—including those in Europe—are looking beyond the traditional borders of their energy business and territory.

What’s Driving This Change?

The main drivers behind this globalisation and regionalisation of energy resources are:

  • Access to cheaper natural gas globally
  • Accelerated shift of generation resources to renewables, which requires greater system flexibility to maintain security of supply
  • Economic and political imperatives for energy import and export

Access to Cheap Natural Gas Globally

Driven by a technology breakthrough applied in the field, shale gas has transformed the North American gas market and stands poised to significantly affect the global gas market in the future. On February 24, 2016, for the first time in history, liquefied natural gas (LNG) from North America was exported from the contiguous United States—from the Cheniere Sabine Pass facility in Louisiana—to Europe, a historic moment in the North American gas industry.

Globally diverse sources of natural gas and increased movement of these sources—in the form of LNG by ship—is becoming increasingly prevalent from places far from one another. As Australia, the United States, and Canada follow Qatar with plans to export LNG in large volumes, the global gas market is poised for a renaissance. Although the LNG industry has been a victim of its own success as prices have declined, the growing availability of gas to global markets is set to impact places that never previously had access. This movement is bringing with it the opportunity for new gas-powered industries such as petrochemicals and an increased availability of cleaner gas-fired power generation to people and places around the world.

Extensive European infrastructure for gas transmission, including pipelines and new LNG facilities, is helping ensure that cheap gas will be available in most parts of Europe. There is a lag effect as to how this impacts gas generation development; however, in the short to medium term, it at least underpins gas’ ability to remain a key fuel source for heating, industrial use, and flexible power generation. While the latter use may fly in the face of carbon targets, with questions around new nuclear and other baseload low-carbon generation, the net reduction from replacing coal with gas is still significant and may prove to be at least a convenient bridging arrangement.

Accelerated Shift of Generation Resources to Renewables

In Part III of this series, we discussed the changing generation mix across Europe. Virtually all net growth in recent years has come from renewables. To achieve this while managing the system security of supply requires much greater flexibility in the way the electricity systems are managed across Europe. Flexibility is essential and the key underpinnings of this are interconnection, storage, and demand response. To date, the most prevalent of these has been the rapid growth in interconnection—for example, the import of French nuclear power to support Germany’s solar boom and the HVDC interconnection to enable the United Kingdom and Denmark to rapidly develop their wind generation sector. It can be argued that without access to hydro reserves from Norway and Sweden, neither country would be able to accelerate their current offshore wind program. This interconnectedness is a strength of the European system, but it also means that, in effect, each nation relies on others for their ultimate security of supply. In the future, the impact of storage will complement this and aid renewables integration and system stability. Storage and the ongoing development of demand response will also lead to local regionalisation, whereby markets at a more local level are necessary to deal with increasingly decentralized generation and the local flexibility enabled by smarter metering.

Economic and Political Imperatives

The third driver may be obvious to some but is the most challenging to achieve in practice in many ways. Greater affordability for consumers across Europe is promoted through a more regional approach to energy supply. However, macroeconomic theory and national politics do not always pull in this same direction. It sounds simple for Norway to increase its exports to the United Kingdom via a new interconnector as both countries gain overall; however, if this leads to higher wholesale prices in Norway through a reduced surplus, then consumers may see an impact on their retail price. To date the economic efficiency of Europe’s market coupling has proven a sound platform for rapidly improving the regionalisation of energy resources across the continent while political will has held firm in most respects. Some initiatives such as the North Sea Grid may work on a region-wide basis yet do not translate into a commercial rationale that leads to specific profitable projects for investors. Given the importance of a united energy policy for maintaining affordability and energy security across the continent, this needs to remain a critical area of policy and regulatory attention as 2030 targets come firmly into focus.

So What Does This Mean?

It is worth reminding ourselves of the underlying objectives as defined by Europe’s Energy Union:

  • Electricity systems will become more reliable, with lower risk of blackouts.
  • Money will be saved by reducing the need to build new power stations.
  • Consumers’ increased choice will put downward pressure on household bills.
  • Electricity grids will be able to better manage increasing levels of renewables, particularly variable renewables like wind and solar.

Looking forward, the EU market, national policymakers, and utilities first need to adapt their long-term resource plans and incorporate regional scenarios for power supply, while also building in a rapidly changing fuel resource mix toward renewables and natural gas. Second, they must think outside the box with regard to securing fuel or access to renewables well beyond their traditional territory borders. Third, to effectively develop system plans, the planning processes need to take into account the entire regional transmission system. Regional entities should find a way to bring together players such as distribution network operators, municipalities, and other smaller industry players to ensure their needs are also addressed and more holistic solutions are presented. Finally, to facilitate and enhance emerging market offerings such as enterprise information management, the planning toolkit needs to expand to better address the challenges of large-scale renewables integration across multiple regions.

This post is the sixth in a series in which we discuss each of the power industry megatrends and the impacts (“so what?”) in more detail. Our next blog will be about merging industries and new entrants. Stay tuned.

Learn more about our clients, projects, solution offerings, and team in our Navigant Energy Practice Overview.

 

Roller Coaster Summer Continues for Fuel Cell Incentives

— June 21, 2016

HydrogenRobust incentives in places like Germany, Japan, and the United States have expanded the market for stationary fuel cells over the past decade. Within the United States, recent changes to major incentive programs hint at the future of the industry.

The California Public Utilities Commission recently proposed changes to the Self-Generation Incentive Program (SGIP). If approved at the Commission’s June 23 business meeting, the wide-ranging changes would substantially restructure the program. Two key changes would specifically affect natural gas generation technologies such as fuel cells, microturbines, and generator sets. First, energy storage projects would be allotted 75% of program funds, with the remaining 25% going to generation projects, including natural gas projects, wind turbines, and others. This would be a strong pivot toward storage over generation since these categories account for 4% and 96%, respectively, of $1.1 billion in historical incentives paid. Second, beginning in 2017, natural gas projects would need to use a minimum of 10% biogas, increasing in steps to 100% in 2020. The changes are intended to strike “the right balance of the program’s goals of reducing [greenhouse gases] GHGs, providing grid support and enabling market transformation.”

The federal Business Energy Investment Tax Credit (ITC) has been another important incentive, offering as much as a 30% rebate on fuel cells and other energy technologies. Wind and solar won big with the December 2015 extension, though fuel cells and other natural gas technologies were passed over and currently expire at the end of 2016. However, recent comments from congressional leadership indicate that an extension for the overlooked technologies is likely this year and may even be approved as part of the Federal Aviation Administration (FAA) authorization bill, which has a deadline of July 15.

So the news for fuel cells is mixed, with California likely offering smaller incentives than in the past but the ITC likely extending beyond 2016. The goals of such programs are ever changing, though in most cases, increasing focus is placed on GHG reductions. California’s biogas requirement cuts emissions and could thus be good for the industry, provided biogas can be viably sourced in the quantities required.

Successful incentives should ultimately render themselves unnecessary by driving down costs. Fuel cell costs have been falling, though not at the rate of some other technologies like PV. The winners will be those that can creatively cut the costs of manufacturing, installation, and financing to make the systems cost-competitive with other electricity sources. Despite the GHG emissions associated with natural gas fuel cells, current developments play a role in a zero-emissions future. Today’s natural gas fuel cell research can be directly applied to the hydrogen fuel cell, a key emissions-free and dispatchable energy resource that can complement the mix of renewables that will power our future.

 

Breaking New Ground While Exploring Value of Energy Storage in Southern California

— June 7, 2016

Cloud ComputingThe closure of the 2,150 MW San Onofre Nuclear Generating Station (SONGS) has left a huge hole in the power supply portfolio that Southern California Edison (SCE) had traditionally relied upon to serve customers. On top of that, the massive leak of methane from the Aliso Canyon natural gas storage facility has further aggravated the electricity supply challenges facing Southern California.

The leak is the largest known leak of methane into the atmosphere in U.S. history. It continues to make headlines, but longer term impacts could still be felt this summer.

Filling the Gaps

“When full, Aliso Canyon has enough natural gas stored to supply fuel to 18 regional power plants located in the Los Angeles basin for 21 days. But it takes 2 to 3 days for that natural gas to get into the basin where it is needed. So when the sun goes down, we can’t get the gas fuel to power plants where it is needed in time,” said Susan Kennedy, CEO of Advanced Microgrid Solutions (AMS), a company that has won a contract with SCE to deploy up to 50 MW of distributed energy storage to help fill regional supply gaps via hybrid electric buildings such as those owned by the Irvine Company.

“One major heat wave this summer could have major impacts, leading to curtailment of electricity service,” a prospect recalling the power outages that plagued California in the 2000-2001 timeframe, when Kennedy, working on behalf of then-governor Gray Davis, had to resort to emergency measures seeking drastic demand reductions in order to keep the lights on. “Few people seem to make the connection between this natural gas supply and our reliable electricity system,” she noted. But Kennedy does. “What we clearly need to get through this summer and into the future is fully dispatchable demand response [DR], the ability to use customer load as a resource in the same way we use supply. Energy storage allows us to create such a resource that also provides economic value for customers, such as the Inland Empire Utility Agency [IEUA].”

Water-Energy Nexus

The agreement with IEUA is addressing the water-energy nexus in California, an issue that is also raising concerns in light of lingering droughts. IEUA has been leading on renewable energy since 2008, with solar, wind, and biogas resources already part of its electric resource portfolio. With the help of AMS and its partner Tesla, these energy storage devices will allow the agency to maximize value to reduce its energy costs by an estimated 10%, or as much as $230,000 annually.

IEUA did not have to pay any upfront capital costs under the terms of the unique contract with AMS. Yet the biggest surprise to emerge in this project was SCE’s flexibility in contracting. The investor-owned utility had to adjust the existing tariff with IEUA in order to bring the energy storage devices online. “There was no template of how to do this,” said Jesse Pompa, a senior engineer at IEUA. “Batteries had never been connected to a grid in this way before. This was indeed a risk for us, and the biggest surprise is that they accommodated us.”

“I have to say, SCE is the most open-minded of all California utilities in viewing energy storage as a grid resource,” added Audrey Lee, AMS’s VP of analytics and design. She noted that the artificial intelligence software that AMS provides enables the fleet of Tesla batteries to provide a firm, dispatchable DR resource to help SCE get through this summer.

 

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