Navigant Research Blog

Eclipsing Solar Generation: Lessons Learned from the 2015 European Eclipse

— June 8, 2017

The United States will experience a solar eclipse at 10 a.m. PST on August 21, 2017. This will be the first total solar eclipse in 26 years—and the first since the solar PV industry expanded and PV became a meaningful source of electricity in certain US markets (especially in the California Independent System Operator, or CAISO, territory). The eclipse’s route is expected to skirt the states with the most solar installations, influencing generation in states such as California and North Carolina.

Globally, this will be the second time a region faces this challenge. On March 20, 2015, a total solar eclipse passed through Northern Europe (and partially in the southern part of the continent) between 9:40 a.m. and 12:00 p.m. CET. My colleagues at Ecofys did a presentation at the time to explain the effects the eclipse could have on the German grid. Back then, Germany had a total generation capacity of about 190 GW, 39 GW (20.5%) of which were solar.

At the time, the Ecofys team projected that PV power generation could drop by up to 13 GW for more than 1 hour in Germany and by up to 34 GW across Europe for a few minutes. That would represent 2-3 times the magnitude of variation due to other natural events like sudden storms.

Projected Trajectories of the 2017 and 2024 Total Solar Eclipses

(Source: Xavier M. Jubier)

Prior Knowledge Maps the Way

The nature of solar resources means that the effects can vary significantly depending on the local weather. The day of the 2015 event had cloudier weather conditions than originally forecast, which led to a less severe reduction in PV generation. Those areas that did have clear skies were affected significantly, but European energy markets managed to cope. Some of lessons from the eclipse included:

  • The hourly day-ahead market was mostly unaffected by the eclipse. German transmission system operators (TSOs) successfully marketed the PV in a first step at the hourly market and in a second step at the quarter-hour market.
  • In case of high demand or supply, there is a de facto quarter-hour market (over-the-counter and power exchange) in Germany, Austria, and Switzerland that can provide significant contributions for intra-quarter-hourly compensation. This solution is a fine-tune balancing done by the TSO.
  • The quarter-hour market showed big spreads. A European coupling of quarter-hour markets should contribute to increased liquidity of the market and reduce these spreads. At the same time, the quarter-hour trading should be combined with the hourly market.

The main challenge is how to balance the power system against this dynamically changing generation backdrop. This requires flexibility in the power fleet and significant amounts of reserve control over a short period of time. To tackle this challenge, the European Network of Transmission System Operators for Electricity (ENTSO-E) put in place the framework below to reduce the effects of future eclipses that the US regional transmission organizations/independent system operators (RTOs/ISOs) can use as a guideline:

  • Develop a plan to disconnect part of the installed utility-scale PV generation in advance of the eclipse and establish the amount and timeframe for disconnection and reconnection.
  • Detail the steps necessary to reconnect PV systems to the grid.
  • Add backup generation and/or interconnectors to allow transfers to fulfill load in the absence of PV generation.
  • Establish a clear description of the installed PV capacity and its capabilities to improve the accuracy of forecast studies.
  • Enable real-time measurement of distributed PV generation so operational strategy can be adapted in real-time.

The Effect of the 2015 European Solar Eclipse in the German Market

(Source: Energy Charts)

 

Could Global Distributed Solar PV Prices Drop Thanks to Suniva’s Petition?

— June 6, 2017

On May 24, 2017, the US International Trade Commission (ITC) announced that it will consider a petition by Suniva, a bankrupt solar manufacturer in Atlanta, Georgia, to place tariffs on the most common kind of PV solar cells imported from around the globe. Suniva put forward a petition to set a minimum import price (MIP) to $0.78/W and requested a 4-year tariff schedule on crystalline silicon imports. According to the petition, the floor price would fall to $0.72/W in year 2, $0.69/W in year 3, and $0.68/W in year 4.

While the outcome of the ITC investigation will not be known for some time, the uncertainty that the investigation brings to project developers and investors is important. Both short-term and long-term effects can be expected:

  • Short term: Module OEMs will increase imports to meet their firm contracts for the year. Projects in the late stages of development will try to secure modules before any decision on the tariff is made, potentially bringing projects forward. Uncertainty could boost installations for the rest of the year. Currently, there is a glut of module capacity, so any increase in demand could easily be met.
  • Long term: For those developers unable to make the arrangements necessary to lessen the risks to their projects, they may postpone investment decisions until the risks are better understood (i.e., after the ITC decision).

So What If It Happens?

For now, it seems that developers see the risk of the new tariff as manageable. On the same day that the ITC began its investigation, a new contract signed by Arizona utility Tucson Electric Power (TEP) and US developer NextEra Energy set a record low price for large-scale solar power in the country. The TEP and NextEra contract allows the United States to join a select club of countries with solar at or below $0.03/kWh (alongside Chile, Mexico, and the United Arab Emirates). The project is expected to be commissioned by the end of 2019, when the tariff will have its full effect.

Navigant Research anticipates 2019 module prices will be $0.39/W. With module prices potentially leaping by at least 50%, on the surface the TEP-NextEra contract seems like a potential disaster. But while the drop in module costs over the last few years has been impressive, reductions in other costs have been at least as impressive, limiting the effect that the MIP will have on the final cost of the project.

According to the Navigant Research model, the cost of developing a utility-scale project in the United States with a 2019 commissioning date would increase from $0.93/W to $1.24/W (over 33%) due to the new MIP. In the case of the Arizona project, the cost per kilowatt-hour generated would increase from just below $0.03/kWh to just below $0.04/kWh.

More Bang (kWh) for Your Buck

Interestingly, the MIP requested by Suniva uses peak power (Wp) as its basis. This would drive a rapid shift toward quality, namely high efficiency modules. For example, developers could use SunPower’s X-series panels (currently with an efficiency of around 23%) instead of a conventional multi-Si module (with an efficiency of around 16%), thereby reducing the footprint of the plant by up to 30% for the same output. This would allow developers to offset higher module costs with lower balance of system costs and operations and maintenance costs. Using bifacial modules—which are hitting the market right now and could work well in the Arizona desert—could help reduce the footprint by another 15%-30%.

It is difficult to say whether NextEra could really bring the project cost back down to $0.03/kWh if the tariff comes into effect. However, it is important to remember that module costs do not make or break a project nowadays and that new technology is available that can reduce the module’s effect on the final cost of a project.

 

Self-Consumption Markets Are the Future of Solar

— May 2, 2017

Regulatory changes and the increase in retail electricity prices have made some markets ripe for new business models built around increasing solar self-consumption by adding other energy solutions (like batteries or Internet of Things, or IoT).

In my previous blog, I showed how solar installations can benefit from increasing levels of self-consumption. When this is the main economic driver for solar, we define the market as a self-consumption market. While the blog cited the United Kingdom as an example, that is not the only country in which this strategy works.

European Countries Lead Self-Consumption Markets

Here’s a selection of the most attractive self-consumption markets:

  • Germany: Germany is in a similar situation to the United Kingdom. The feed-in tariff in the country (€0.123/kWh [$0.135/kWh]) is significantly below some retail electricity prices. For example, residential rates cost around €0.30/kWh ($0.33/kWh). To fully benefit from a solar installation, Germans need to displace as much as possible of their own consumption. In addition, Germany offers an incentive to install batteries along solar PV systems. German government incentives cover up to 30% of cost for a PV system battery, making the economics of self-consumption even more attractive.
  • France: Like in Germany, the current French feed-in tariff of €0.1382/kWh ($0.151/kWh) for behind-the-meter installations of up to 36 kWp is below retail electricity prices (€0.20/kWh [$0.22/kWh] for residential customers). So there is also an arbitrage opportunity for installations, although the economics are weaker than in Germany.
  • Spain: Despite Spain’s bad reputation in the renewables sector—well deserved given the retroactive changes to its incentive program and the introduction of the infamous tax on the sun—the country is becoming an attractive self-consumption market for installations under 10 kW. Spain has the best solar resources in Europe. Now the levelized cost of distributed solar is below the retail electricity price, opening an arbitrage opportunity for solar installations with high levels of self-consumption.

Self-Consumption Markets by Attractiveness

(Source: Navigant Research)

US Self-Consumption Markets Are Trying to Catch Up

The economics of self-consumption of solar in the United States are weak given the dominance of net metering as the main tool to incentivize solar. There are some states that are moving away from pure net metering that will increasingly be more attractive to providers of integrated solutions.

One example is Arizona. Per the new settlement reached between Arizona Public Service (APS) and local solar advocacy groups, energy exports of new distributed solar installations in Arizona will not be included in the old net metering program. Instead, it gives all new distributed solar customers the option to take a demand-based rate or a time-of-use rate.

If the new structure is approved by the Arizona Corporation Commission (ACC), it would set the self-consumption offset rate around ¢12/kWh, which includes a grid access fee that APS solar customers must pay. The new export rate, based on the ACC’s newly adopted resource proxy model, would be ¢12.9/kWh. Although these changes will not be enough to attract investment in expensive technology like batteries, it does send a signal to end users to start behavioral changes to increase self-consumption. It might be enough to encourage some level of IoT investment in energy management systems and automation.

Near-Term Growth Is Unlikely

From a purely growth perspective, self-consumption markets are likely to disappoint in the short term. The extra complexity they present needs to be well understood by solar players. In addition, end users and business models will need to be tested before being rolled out cheaply en masse. The strategies that are successful in those markets—and less dependent on incentives and more so on solar economics—are most likely to rule the distributed solar sector in the future.

 

Can Batteries Save the UK Solar Market?

— April 27, 2017

Last week, E.ON and EDF Energy both announced plans to launch solar plus storage programs for their UK residential customers. E.ON and EDF are two of Europe’s largest energy providers, and EDF is a large owner of coal, gas, and nuclear plants in the United Kingdom with a 13 GW portfolio.

EDF Energy has formed a joint venture with Lightsource, the largest solar operator in the United Kingdom, to launch Sunplug, a company that will be offering residential solar. Sunplug has indicated two contracting options for its systems:

  • One option will be to sign an index-linked, 20-year power purchase agreement with an initial price of £0.099/kWh ($0.123/kWh). Assuming 2% escalation over 20 years, this would average to £0.12/kWh. For comparison, the cheapest electricity tariff in the United Kingdom costs £0.12/kWh or £0.15/kWh ($0.15/kWh or $0.19/kWh) with or without fixed monthly costs, respectively. In this option, Sunplug is the owner of the system and receives any government incentives available to the installation and is responsible for any changes to it.
  • Sunplug’s second option will be a direct purchase for £7,999 ($9,999) that includes the equipment (5 kW PV system, inverter, and 6.6 kWh battery), 2-year labor cover, operations and maintenance, and a 2-year license for its home energy management system—but does not include installation or value added tax.

E.ON’s offerings are less clear, but the direct purchase for a typical system will start at £7,495 ($9,368) including the battery, or £4,495 ($5,618) for the PV system only.

The Economics of Self-Consumption

An interesting question is why both utilities decided to enter the UK residential market with solar plus storage programs rather than only solar. A key driver is the current regulatory environment, which has elevated the attractiveness of self-consumption in the UK solar market.

In the United Kingdom, a residential solar system can currently access the following revenue streams:

  • Generation tariff: This is paid for every kilowatt-hour generated, regardless of its destination. It is currently set at £0.0414/kWh ($0.05/kWh) and is indexed to the UK inflation rate.
  • Export tariff: In theory, this is paid for the electricity exported to the grid. For the time being, the government assumes that half of the kilowatt-hours generated are exported for installations smaller than 30 kW. Currently, the export tariff is set at £0.053 ($0.066).
  • Self-consumption: This is the customer’s bill reduction due to the avoided electricity consumption from the grid. In a northern European country, residential customers are typically only able to use about 20%-30% of the electricity produced by their own solar system without any storage or significant behavioral changes. Assuming 20% self-consumption and an electricity tariff of £0.12/kWh ($0.15/kWh), a solar system owner would save the equivalent of £0.024/kWh ($0.03/kWh) generated.

Taking these revenue streams into account, a residential solar owner with 20% self-consumption would receive £0.09 per kWh ($0.11/kWh) generated, whereas an owner with 100% self-consumption would receive £0.186 per kWh ($0.23/kWh) generated, 106% more. Of course, a battery would be necessary to achieve total self-consumption for a reasonably sized residential system. Using E.ON’s figures, the battery cost is £3,000 ($3,750). In other words, to earn 106% more per kilowatt-hour, the owner would need to invest only 67% more than the solar-only system—not a bad deal!

 UK Solar PV Plus Storage Revenue Streams

(Source: Navigant Research)

 

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