Navigant Research Blog

If $9 Billion of Renewable Energy Is Curtailed in 2030, What Opportunities Will Emerge? Part 1

— September 1, 2016

Cyber Security MonitoringThe intermittent nature of renewables is well established, though hard data on its impact is just now starting to become available. Germany, a world leader in wind and solar, is showing growing levels of curtailment (defined here as the reduction of otherwise scheduled electricity output). As the wind plus solar share of electricity grew from 10% to 26%, the share of curtailed (or wasted) wind plus solar energy grew from about 0.2% to around 1.8%. As seen on the chart below, since 2009, a consistent pattern has emerged relating curtailment to renewable penetration.

Growth of Renewables and Curtailment

CurtailmentTrends

 (Sources: AG Energiebilanzen, German Federal Network Agency, Electricity Reliability Council of Texas, UK National Grid, Lantau Group)

Consider if the rest of the world followed this trend line through 2030. The 2016 Renewable Energy Roadmap (REmap) from the International Renewable Energy Agency (IRENA) outlines a feasible path to doubling the share of renewables by 2030. The 40 countries covered represent 80% of global energy consumption. Under the REmap scenario, 60% of global solar plus wind energy would come from countries generating between 20% and 30% of their electricity from such sources, comparable to Germany’s 26% in 2015.

If each country followed the curtailment trend established above, annual curtailment would amount to 128 TWh, or 0.4% of total global generation. This energy is worth $9 billion, assuming a value of $70/MWh, the estimated variable cost of a combined-cycle generator in the United States in 2030. Given the low cost of renewables and compared to the $1 trillion or more in annual savings projected by IRENA, the curtailment may be easily justified.

Caveats and Variations

Even if renewables grow that quickly, there are many caveats to this assessment. Curtailment occurs locally, a nuance that country-level analysis does not capture. Furthermore, there are vast variations among countries in geography, transmission infrastructure, generation mix, market structures, and other variables. Germany’s trailblazing growth has led to some specific growing pains that are being addressed, with major transmission upgrades being built to address the issue. Still, given the poor track record of curtailments in other places with less renewables, curtailment could even be higher. See approximate trends on chart.

China has curtailed 15% of its wind since 2011, worth over $6 billion at the rates above. The Electricity Reliability Council of Texas (ERCOT) cut curtailment from 17% (2009) to 0.5% (2014) with transmission upgrades and market reform, but with just 11% of generation from wind still did “worse” than Germany by not falling below the trend line. With curtailment data just starting to be collected in some regions and the feverish projected growth of renewables, this high-level approximation can outline the potential magnitude of curtailment.

So if $9 billion of energy is curtailed, what opportunities will emerge? The second part in this blog series will cover some of these potential options. Transmission upgrades and storage technologies have been getting a lot of coverage lately, but flexible generation technologies may be even more important to our clean energy future.

 

Overcoming Hurdles to Monetizing Value Streams from Energy Storage Systems

— August 19, 2016

GeneratorFederal Energy Regulatory Commission (FERC) Order 755 requiring regional transmission organizations (RTOs) and independent system operators (ISOs) to implement a pay-for-performance structure for frequency regulation service has been instrumental in demonstrating the benefits that fast-responding resources like battery energy storage systems (BESSs) can provide to the grid. For example, since Order 755’s implementation, PJM experienced a 30% reduction in overall regulation reserve requirements as more fast-responding resources have cleared the market. However, despite the early regulation successes in PJM, storage directly connected to a distribution system (known as front-of-meter, or FTM) continues to faces uncertainty and barriers in the United States associated with rate treatment.

On another front, energy storage stakeholders now recognize that BESSs connected to the distribution system from behind the meter at a residential and/or commercial & industrial customer’s property can deliver benefits to the host, RTOs/ISOs, and utility distribution system operators. This evolution is driving the development of software and hardware platforms that can analyze, control, and optimize not only a single BESS, but also aggregated BESSs. These advances are now giving rise to energy storage assets that can recognize multiple value streams by stacking grid benefits in virtual power plants (VPPs).

Regulations and Requirements

However, regulatory eligibility and performance requirements for aggregated behind-the-meter battery energy storage assets have not caught up with these technological advances. To date, there has been limited participation by energy storage in demand response markets, and several instances demonstrate how wholesale market rules are missing opportunities for these assets to provide multiple grid benefits. For example, the CAISO Proxy Demand Resource (PDR) prohibits a VPP from providing frequency regulation, even though the systems would be technically capable of doing so. And in ISO-NE and NYISO, Northeast Power Coordinating Council rules prohibit behind-the-meter energy storage from providing spinning/synchronized reserves.

At the Energy Storage North America (ESNA) expo in October, a panel discussion will feature case studies from across the country on the challenges, feasibility, and economics of how single BESSs and VPPs can stack energy storage value streams. Don’t miss out on the conversation—register for ESNA today.

 

Europe’s Energy Transition Megatrends and Tipping Points, Part III: Shifting Power-Generating Sources

— August 17, 2016

Energy CloudJan 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. In this third blog in the series, we discuss the shift in power generation fuel mix and how this is transforming the European power industry.

European electricity-generating facilities that use oil, coal, and nuclear are devaluing and at risk of becoming stranded as generation sources shift to less expensive renewable generation and natural gas generation. This shift is playing out in different ways across Europe.

Generation Fuel Mix Shift Is Accelerating

According to the US Energy Information Administration (EIA), net European generation capacity will increase by 7 GW in 2016. Much of Europe’s new capacity TippingPointcomes from renewables, with close to 75% of new capacity coming from wind (44%) and solar (29%). While new coal (16%) and gas (6%) capacity was added, far more coal assets were decommissioned. As a result, net new capacity in Europe is virtually 100% renewables. While recent subsidy cuts have tempered solar’s growth, wind is marching onward. There is still no effective utility-scale solution to the inherent intermittency in renewable generation, as storage solutions and grid interconnection/active management are still lacking penetration at scale. Natural gas is the bridging fuel during the shift to renewables, supported by the abundance of natural gas available globally, lower long-term prices, and increasing import capacity in Europe.

What Are the Drivers Behind This Shift?

We see five main drivers for the shift in generation resources described above:

1. Climate Change Policy: Europe has taken definitive steps to decarbonize its power generation, including relatively generous support for renewables and economic penalties for carbon emitters via the EU Emissions Trading System (EU ETS). See our previous blog on the rising number of carbon emissions reduction policies and regulations.

2. European Market Coupling: A second aspect of Europe’s power sector is the physical and economic integration of markets. Interconnection growth has been strong, and the economic incentives via use of power exchanges for dynamic price signaling has provided further support for low-carbon generation.

3. Generation Economics: While policy and regulatory support for low-carbon generation has taken centre stage, the economics of various forms of generation have also been shifting. Within 7 years, solar power has gone from a heavily subsidized resource to a key component of the generation mix, even with zero or minimal subsidies. Europe continues to lead the world in development of offshore wind, particularly in the North Sea. Thermal generation economics have also changed—despite relatively low gas and coal prices, low marginal cost renewables are increasingly forcing thermal plants to shift from stable baseload operation to less efficient cycling and reliance on ancillary service contracts.

4. Decentralization of Generation: The scale of distributed energy resources (DER) is not yet huge across Europe; however, this trend is already shaking the traditional utility business models. The rise of the prosumer is gathering momentum, be it an industrial customer who invests in combined heat and power, a new commercial building with a biomass boiler, or a housing development with rooftop solar panels.

5. Public Sentiment: This driver cannot be underestimated given the prevalence of democratically elected governments in Europe. Public support for action to curb climate change despite the costs has been most obvious in Germany, where the changes via nuclear shutdowns and solar growth have been massive—and expensive. In the UK, it is more expensive to construct offshore wind than onshore, but the public and political preference is that location trumps economics.

How Does This Play Out Across Europe?

Navigant Research forecasts that 66% of European installed renewable generation capacity in 2016 will be in five countries—Germany, Italy, France, Spain, and the UK. In the struggling economies of Portugal, Italy, and Greece, the rate of renewable growth has slowed to just 0%-2%. Countries that are still dependent on coal as a fuel source face economic and fuel supply obstacles.

Beyond the recognized elements of the shifting power generation trend in Europe, there are a series of potential tipping points that will have pronounced consequences depending how they fall:

  • New Nuclear: This is a topic of much debate in the UK and France. Germany has all but made its mind up, barring a major political reversal. Until recently, the UK Department of Energy and Climate Change (now part of the Department of Business, Energy and Industrial Strategy) was a strong supporter of new nuclear in a portfolio of low-carbon generation. The new Hinkley Point C nuclear facility was planned to begin a renaissance of new nuclear, but with new skepticism rearing its head in the UK media, there is still a chance that the nuclear renaissance will stall and the UK will turn to a mix of more gas and offshore wind. France is another country to watch given its historic strength in nuclear power. Unless the struggling Flamanville facility can turn the corner soon and get commissioned, the growing renewables may get a massive boost that goes beyond current political support. Public sentiment is also an important card to play in the nuclear game. As the power system shifts from the traditional centralized model toward a more dynamic, distributed environment, there are both significant strengths and significant weaknesses in retaining large inflexible baseload generators. Ultimately they are likely to look increasingly out of place in the new world order.
  • Electricity Storage Technology and Economics: Elements of storage in the electricity system are not new, but pumped hydro storage and fuel storage to provide thermal generation are increasingly being surpassed in the perceptual stakes by other new technologies. The recent National Grid Enhanced Frequency Response tender in the UK was massively oversubscribed. Among all the disruptive technologies that affect the electricity system, a breakthrough in electricity storage technology and economics offers perhaps the greatest potential to radically change the power system of the future. The US Department of Energy is so convinced of this that it is funding 75 breakthrough research projects developing electricity storage solutions. These include radical new options such as organic flow batteries, which avoid the need for costly and rare metals such as lithium and vanadium. The race is on to find ways to bring storage costs down below $100/kWh or €90/kWh at present exchange rates.
  • European Shale Gas Developments: Shale gas has proven revolutionary in the United States; however, it remains questionable in Europe. Even though it is highly unlikely to have the same supply and economic characteristics as it does in the United States, it may indeed prove a further tipping point in favour of gas-fired generation if significant quantities of shale gas are produced within Europe. Security of supply is always of paramount importance, so the notion that countries in Europe would produce then export most of their supply would be hard to comprehend. Whereas coal is struggling to find favour other than in countries with little alternative, Europe has a great deal of relatively modern gas-fired generation that is not being well utilized. There may be a trend toward smaller, more flexible plants, but gas-fired generation has a viable future under most scenarios for many decades yet.
  • Carbon Target Commitments for 2030: While COP21 was a major milestone in global climate change, when the microscope is turned on European national commitments to decarbonize power generation, the image is less rosy. Some countries such as Spain and Italy appear to have reached peak renewables, where their appetite to push on and manage the ongoing system impacts are not high. Germany is struggling to digest its huge solar investment and accept the consequences on battling local firms such as RWE, E.ON, and Vattenfall. The UK has repeatedly backed away from committing to 2030 carbon targets, preferring to stick with existing 2020 and 2050 numbers. Until firm 2030 commitments by country are made in early 2017, there is insufficient muscle to power Europe forward.
  • Interconnect and Brexit: No article about Europe is complete without a mention of Brexit. The immediate question and a potential tipping point is how European interconnect developments will fare, especially those proposed in the North Sea to connect Scandinavia, Germany, the Netherlands, France, and the UK. These projects greatly affect the larger renewable generation economics, allowing easy and unrestricted export and import of power between countries as wind, sunshine, and other renewable sources vary between nations. Most commentators assume that the UK will retain its close ties to European energy markets; however, if this changes, it could precipitate an unravelling of arrangements with far-reaching consequences.

What Does This Mean for Generators?

More traditional generation assets, particularly coal and nuclear, face an uncertain future. For coal without carbon capture and storage, every scenario looks at best bad and at worse grim. As evidenced by Navigant’s Generation Knowledge Service (GKS), the average capacity factor of coal plants has declined by 20%-30%, which translates to a 20%-30% drop in gross revenue opportunity. To deal with the combination of lower realized revenue and higher operating costs, companies are evaluating their plants to determine if they can survive in the new world. They are actively seeking new ways to reduce costs through staffing changes, fewer planned outages, and higher operating efficiencies while maintaining high reliability to support the increased use of variable generation. Older coal plants are being phased out and others converted to burn biofuel. Revenue support from capacity contracts and better ancillary service contracts such as black-start capability is also becoming crucial.

Nuclear power today accounts for 25% of all European electricity produced, and any change in nuclear’s role in the generation mix will take time to implement. However, nuclear also highlights the significant differences in national energy policies across the EU and the wider European context. Nuclear was effectively killed in Germany, yet may still enjoy a renaissance in the UK; new plants are under construction in France, Finland, and Slovakia.

As a result, the economics have changed and some of the existing (coal and nuclear) assets are experiencing eroded profit margins. These margins are resulting in challenging economics and, in some cases, significant devaluation. More generation assets are increasingly at risk of becoming stranded investments, as the fuel mix is shifting more quickly than envisioned.

And to Make Things Worse: The Move from Big to Small Power

With the rapid growth of distributed generation (DG), all central generation (coal, gas, hydro, nuclear, and wind) will face more changes in its role on the grid. DG installations are expected to reach 256 GW in 2016; thus, DG is growing faster than central station generation (7 GW additions, minus 8.5 GW retirements, using the EIA forecast). On a 5-year basis (2015-2019), DG in Europe, with some variance by region, will grow almost twice as fast as central generation (47 GW vs. 28 GW), excluding retirements.

Path Forward

As a path forward, generators must clearly define the mission of each generating unit to understand their new role and how to survive economically. To succeed, we believe companies must do the following:

  • Conduct a strategic review of generating assets and determine what, if any, changes need to be made in their generation portfolio and/or how these assets are managed under several regulatory and commodity pricing scenarios.
  • Find innovative ways to reduce O&M costs while maintaining the reliability required by the independent system operators during target operating periods (for plants that will continue to run in the near term).
  • Seek new sources of revenue to replace the capital-intensive position for large generating plants by considering investments in renewables and DER, particularly energy storage, and optimizing commercial contract opportunities with system operators.
  • Have a strategy to manage significant reductions in staffing levels and loss of critical experience across the board, including dealing with the impacts on funding pensions and local economies when plants are retired.
  • Plan for a changing workforce that will include deeper knowledge of digital technology and an understanding of how to optimize operations in a more variable power market.
  • Assess options for global asset diversification given the changes and new opportunities in traditional parts of the value chain such as transmission and distribution.

An understanding of the above disruptive trends and how they affect your company and the rest of industry is crucial to shaping our energy future. Navigant aims to help our clients understand, progress, and protect their business’ future in the context of this massive amount of change.

This blog is the third in a series discussing how industry megatrends will play out across Europe as well as at the regional and country level. Stay tuned for our next blog in this series.

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

 

Tesla and SolarCity: Is Financing a Bundled Clean Energy and Transportation Service on the Horizon?

— July 8, 2016

Electric Vehicle 2Tesla’s recent announcement that it intends to acquire SolarCity was an unprecedented Energy Cloud trifecta. It’s not easy for a single release by one company to stir the interests of three separate sets of passionate stakeholders tracking transformative clean energy and transportation technologies and business models. And rightly so, as the potential for Tesla to pair vehicle electrification with solar and advanced battery energy storage as integrated distributed energy resources (DER) is an eye-opener to say the least.

Tesla’s vehicle and battery manufacturing businesses are very different than SolarCity’s solar business, both technically and revenue model-wise. It will likely be a challenge for the company to explain these separate businesses to its investors and manage expectations. One could argue that Tesla might be better off focusing 100% of its efforts on building out the Model 3 and Nevada Gigafactory battery manufacturing capacities in the short term.

The DER Standpoint

But from a DER technical standpoint, it’s intriguing to consider the possibility of what the new Tesla could do. For example, the new Tesla could couple the energy capacity of plug-in electric vehicle (PEV) batteries with solar, PEV charging infrastructure, and virtual power plant (VPP) software all at the home of a single customer. It’s not hard to envision how this type of arrangement could serve both as DER and an overnight revenue source to utilities. The new Tesla indicated that it plans to continue to partner with utilities, which are increasingly interested in aggregated behind-the-meter demand response capacity. And SolarCity’s recent efforts to partner with utilities in New York on a new program to eliminate net metering along with the company’s recent hiring of former Federal Energy Regulatory Commission (FERC) Chairman Jon Wellinghoff as Chief Policy Officer demonstrates a willingness to pursue such new and innovative business models.

Going to Market

But how might the new Tesla take this sort of concept to market? A key aspect of technology innovation in renewable energy has been financing innovation. The development of power purchase agreement financing has been instrumental in the growth of solar PV. Navigant Research believes that financing innovation will also drive energy storage markets over time, as well.

But the new Tesla could be uniquely positioned to apply financing innovation to an integrated solar battery PEV-based VPP while also providing consumers with the use of the vehicle. Imagine a homeowner entering into a 15-year financing agreement for solar, energy storage, and use of a Tesla Model 3 under a single contract. In this scenario, the new Tesla/utility partner manages the VPP asset while the customer gets access to, but not ownership of, a Tesla Model 3. If the new Tesla/utility partner decides to extensively use a Model 3 battery as part of the VPP, then the homeowners get a new Tesla battery. In this scenario, the long-term assumptions on VPP revenue, replacement batteries, or even new vehicles and solar storage benefits are bundled under one customer-facing agreement.

This type of integrated financing innovation might sound challenging. But I can guarantee that a trifecta (or more) of interested Navigant Research teams will be closely tracking if and how the new Tesla comes together.

 

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