Navigant Research Blog

Sunrun: The Large Solar Provider Dilemma

— September 19, 2017

On August 24, Sunrun—the last of the large independent US solar providers—announced an agreement with Comcast, a leading cable provider in the country. The two companies plan to launch a strategic partnership to offer Sunrun’s services to Comcast’s clients.

Sunrun was founded in 2007 and found success innovating new ways to finance residential solar installations such as solar leases and power purchase agreements (PPAs). It created the solar as a service (SOaaS) business model, which became the foundation for the growth of the sector between 2010 and 2015. Until 2014, it seemed that solar leases and PPAs—grouped as third-party ownership in California’s Interconnection Applications Data Set—were going to be the winning business model in the SOaaS industry. These leases allowed large players to both increase the market size and displace local installers.

Changing Solar Market

In 2015, the market share of solar leases and PPAs in California—which itself represents around 60% of the US market—plunged to under 50% from 75% in 2013. Data for 1H 2017 shows third-party ownership at close to 30%.

Third-Party Ownership Market Share, California: 2005-1H 2017

(Sources: Navigant Research; California Distributed Generation Statistics)

The collapse of third-party ownership has weakened large solar providers compared to local installers. Large solar providers relied on their access to cheaper capital backed by significant margins in their leases to run large business development teams and finance the installations. As residential solar customers moved into cash or loan buys, local installers became competitive again, reducing the profit margin per installation in the industry. This left large solar providers like Sunrun with high customer acquisition costs relative to profit per installation.

Under these circumstances, it is not surprising that Sunrun is looking for new and cheaper ways to attract customers. Even if this partnership with Comcast costs Sunrun its independent status, it may be worthwhile if the strategy is successful.

What Is in It for Comcast?

Comcast has shown interest in the energy sector in the past, and its Xfinity Home service includes a smart thermostat as one of the offerings. However, scaling it into a full-fledged energy solution would be costly, as Comcast would need to build a new team from the ground.

For Comcast, this partnership offers a relatively cheap entry into the solar and energy markets in which it can rely on its core skills (customer acquisition and management) without having to invest significantly in a new product. If successful, Comcast can push a more aggressive strategy into the energy sector either through Sunrun or with its own product.

Benefits and Potential

Customers of Comcast and Sunrun could also benefit from this partnership. The companies can put together a convincing solution for home automation by tapping on their offerings on the two main services around home automation—security and energy.

The success of this partnership will depend of Comcast’s ability to cross-sell energy services to its current customer base. Comcast operates in a market with limited competition and high barriers to entry, which is different from the solar market. The sales process of solar is also different from that of cable. Solar is a long-term investment (even leases and PPAs require long-term contracts). Therefore, customers take long before making a final decision and, in some cases, it will require home visits before the deal is closed. This means that Comcast cannot simply add solar to its bundles. It will have to invest in training its sales force if it wants to sell solar services effectively. It won’t be easy, but if Comcast succeeds, it may signal a new era for energy.

 

Energy Market Participation for DER Continues Taking Shape

— September 12, 2017

Distributed energy resources (DER) are often touted as having the potential to disrupt traditional energy markets by providing both reserve capacity and ancillary services. However, to date, there have been limited actual opportunities for this diverse set of technologies to provide these services. Regulatory efforts and collaborations between utilities and technology providers are actively working to change this dynamic in global markets. Likely one of the more innovative programs to bring DER into wholesale energy markets has been California’s Demand Response Auction Mechanism (DRAM).

DRAM is a pay-as-bid solicitation program through which utilities are seeking monthly demand response (DR) system capacity, local capacity, and flexibility capacity from DER. This innovative program aims to allow multiple DER technologies to compete on a relatively level playing field providing load reduction services on-demand for utilities. Contracts for load reduction through the DRAM have been awarded to companies providing DR from both commercial and industrial and residential customers, EV charging providers, and distributed energy storage/solar PV providers. Last month, the DRAM program closed its latest round of awards, with utilities requesting approval for 200 MW worth of contracts.

Tip of the Iceberg

DR is emerging as the primary entry point for DER to participate in competitive energy markets. Many DER, namely distributed energy storage systems, are highly flexible resources capable of providing a range of services, including DR/load reduction, ancillary services, and the ability to absorb excess energy during periods of low demand. Despite the variety of benefits DER can offer, the markets for providing and being compensated for these services are not yet in place in many areas. While existing DR markets only utilize one of the services that DER can provide, they are likely the most viable point of entry into competitive markets. The required integration with utility systems has been effective for decades, and grid operators are comfortable with these programs.

For most DER providers, a DR-type program is not the end goal for grid integration and energy market participation. However, it is a great opportunity to prove both the value and reliability of DER to help solve grid challenges. With California pioneering new programs, and other opportunities taking shape around the world, the evolution of DER participating in energy markets will evolve quickly.

 

Hydrogen in Microgrids: Diverse Business Models Begin to Emerge

— September 7, 2017

Hydrogen has long held promise as an energy carrier, though electrolyzer and fuel cell technologies have so far not broken into the mass market—largely due to high costs and infrastructure challenges. As those technologies continue to get cheaper and more efficient, they present intriguing possibilities for hydrogen in one unexpected application: microgrids.

Microgrids, whether grid-tied or remote, rely on local power generation. While solar PV, wind, and other renewables capture many headlines, fossil-fueled distributed generation (DG) accounts for more capacity than any other—40% of the total—among the microgrids tracked in Navigant Research’s Microgrid Deployment Tracker 2Q17. Fossil-fueled DG is often selected since it can provide dispatchable power for long periods and can generally store energy-dense fuel onsite. These facts also hold true for hydrogen. For longer duration storage, hydrogen often outperforms batteries by a significant margin without the emissions associated with fossil fuels.

Emerging business models are setting the stage for hydrogen to play multiple and significant roles in microgrids. Some of these business models are briefly described below.

Remote Microgrids: Hydrogen Displacing Diesel

A new Chilean microgrid developed by Enel, with support from Electro Power Systems (EPS), is showing that hydrogen can fill the same role as diesel, but without the emissions associated with the latter. Remote microgrids have historically depended on diesel gensets, often because many days’ worth of fuel can be stored onsite. While batteries are generally too expensive for multiday storage durations, hydrogen tanks can be easily scaled, independent of the peak power demand.

According to EPS, this type of model is quickly becoming commercially viable. Some reasons include capital and operating cost declines, tighter emissions regulations across the globe, and an eagerness to bypass the diesel value chain across hazardous terrain in remote areas.

Microgrids Exporting Hydrogen

The developers of the Stone Edge Farm microgrid in California had a challenge: despite having excess onsite electricity production from PV and other sources, they faced hurdles in exporting that power in an economically viable way. For example, some of the hurdles to exporting into the California Independent System Operator (CAISO) market include reaching the minimum threshold of 0.5 MW and meeting the ISO’s resource implementation requirements, which include building an onsite meteorological station and control platform. Since these presented significant barriers, the developer looked to another product to export from the microgrid: hydrogen. A bank of onsite electrolyzers turns excess electricity into hydrogen, which then fuels the onsite Toyota Mirai fuel cell vehicles and can also feed the microgrid’s fuel cell bank to generate power.

Islands: Hydrogen as Local Energy Commodity

Many islands are dependent on diesel fuel for both transport and electricity, since it has historically been the cheapest large-scale energy carrier available. However, in places like Hawaii, the appeal of hydrogen is growing thanks to concern over climate change and a growing need to store the high output of intermittent renewables—often using power-to-gas schemes (for more information, see Navigant Research’s Power-to-Gas for Renewables Integration report). In addition, the captive nature of the vehicles helps alleviate the infrastructure problem since relatively few stations are needed. ENGIE, a member of the Hydrogen Council, has been bullish on hydrogen as a future fuel. The company is helping to build an island microgrid based around hydrogen technologies near Singapore. More projects are sure to be announced as the technologies continue to improve.

Thanks to cheap renewables and improving electrolysis technology, hydrogen’s outlook is getting better. Due to the challenges with major fueling infrastructure rollouts, Navigant Research anticipates that hydrogen development will be focused in small geographic areas through 2020. Fitting, then, that hydrogen should find a foothold on the small scale of microgrids.

 

Can Solar Make an Impact on the Transportation Market? Part 2

— September 5, 2017

After a few conversations with Scott Shepard about PV systems in EVs, I began to come around to his view that solar is too expensive and the roof space too limited to make a solar-equipped EV work at the mass market scale. But then I read about another PV in transport project that made economic sense: Indian Railways’ newly launched solar diesel multiple unit (DEMU) trains. A total of 16 300W solar modules are installed on each coach on the train for ₹9 lakh ($13,950 or $2.9/W). The Indian Institute of Science estimates that the annual energy yield in a solar rail coach will be between 6,820 kWh and 7,452 kWh. This could displace 1,862 liters of diesel, saving around $1,650 per year at $0.88/liter diesel.

Lessons Learned

I see two key elements that make the project work. The first lesson from India is that solar in transport makes more sense when it is displacing liquid fuels rather than electrons. Going back to the Prius example from the first blog in this series, if the solar roof was available in Toyota’s non-plug-in version of the car, its economic effect would be significantly better. If a non-plug-in version of the Prius could run for 2,190 km per year on only solar, it could save about 150 liters per year, which would have a value of around $180 per year (using Japan’s gasoline price in July 2017). The investment in a solar roof could break even within the lifetime of the car, so the current cost of the add-on could be justified.

The second lesson is the use of off-the-shelf modules. In this way, the project benefits from the economies of scale that PV systems are famous for. It would be difficult to use off-the-shelf modules in cars, but if Toyota introduced the solar roof in all its Prius cars (for example), it could increase the production rate of solar roofs for the Prius from a couple of thousand per year to about 350,000 per year (global Prius sales in 2016). Modules with similar high efficiency cells in the wholesale market sell for about $0.50/W (i.e., $90 for the 180W used in the Prius).

Most of the costs arise from integrating the PV cells into the roof of the car. These costs could decline significantly due to economies of scale as well. If Toyota could cut costs to those of the train company ($540 for 180W already installed in the car, including inverters and other costs), the breakeven period would be about 2.5 years. Slashing costs would make a solar roof a no-brainer (especially for consumers like me who would be able to drive the car without ever using a charging point or stopping at a gas station).

Interesting Niche

This would open an interesting niche for solar companies. If all the EV and hybrid EV cars sold globally in 2017 (expected to be between 3 million and 4 million) had a 180W roof, an additional 840 MW (an extra 1%) could be added to global solar PV demand. But solar roofs need a champion to push them into the mass market in the same way Tesla pushed EVs away from the margins. My last blog discussed two startups that are exploring this niche. However, traditional manufacturers could do the same to differentiate their brand and cars from the competition. Toyota is an obvious choice given its brand association with hybrid cars, but other manufacturers could step in. For example, Volvo could be a great candidate since it is hybridizing all its models.

 

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