All-renewable microgrids such as the one powering Borrego Springs are likely to remain scarce for years because of inverter shortcomings, according to an expert.
The current state of inverter technology makes it difficult to maintain microgrid stability once renewable energy generation surpasses around 40 percent of peak-power consumption on the system, explained Vicente Salas, associate professor at the Carlos III de Madrid University, speaking at the Microgrid Global Innovation Forum.
“Most manufacturers are focused on creating inverters for grid-connected systems,” he said. “Developing ones for microgrids isn’t like trying to build the atom bomb, but it could take time. It’s hard to say how long, but it could be five years for a commercial product.”
Designing equipment for isolated grids is already complicated because of the wide range of formats encompassed within the broad term “microgrid.” Systems can range from less than 5 kilowatts to several megawatts, and contain a range of generation sources, potentially along with storage.
Where intermittent generation sources such as PV represent less than 20 percent of total consumption, most of the power for the system usually comes from gensets that operate continuously, Salas told an audience in Barcelona this month.
In these situations, PV merely reduces the diesel load and no particular supervisory control system is needed. At medium PV penetration levels of up to 65 percent of peak load, microgrid designers have the option of operating gensets continuously or intermittently.
In the first case, or if gensets are used intermittently with up to a 40 percent PV contribution and no energy storage, microgrids can still get away with relatively simple control systems.
But once PV penetration hits 40 percent, some form of energy storage becomes essential and more sophisticated control is needed. That isn’t easy, because the load keeps changing at the same time as the energy available from solar, Salas said.
In the absence of control systems, bidirectional inverters have to balance power coming in from PV with that going to users and batteries. Current inverters aren’t up to it. As a result, current high-PV-penetration microgrids still tend to rely heavily on diesel generation.
In the microgrid supplying power to Banggi Island in Malaysia, for example, 1.2 megawatts of PV and 2.9 megawatt-hours of battery storage supplement one 350-kilowatt and two 500-kilowatt generators.
In the Malaysian coastal community of Tanjung Labian, meanwhile, a 1.2-megawatt PV plant forms part of a microgrid that includes 4.3 megawatt-hours of storage and more than 1.2 megawatts of diesel generation.
Malaysia boasts other microgrids with high renewable energy penetration, including Bario, with 906 kilowatts of PV, 3.9 megawatt-hours of batteries and 1.4 megawatts of diesel, as well as Kema, with 850 kilowatts of solar, 4.8 megawatt-hours of battery storage and 1.6 megawatts of genset generation.
At the world’s largest PV-diesel hybrid microgrid, in Cobija, northern Bolivia, 16 megawatts of diesel generation are used alongside 5 megawatts of PV and 1.2 megawatt-hours of Saft Intensium lithium-ion battery storage, with control coming from four SMA Sunny Central Storage 630 inverters.
According to another Microgrid Global Innovation Forum presenter, David Cruanyes, an application engineer at SMA Solar Technology, there is a clear business case for PV and diesel hybrid systems in high-irradiation regions where diesel costs more than $1.00 a liter.
PV can generate savings of more than $0.21 per kilowatt-hour compared to continuously operated gensets running on diesel at $4 per gallon, he calculated.
At present, maximizing these benefits further may be difficult because of the limitations of inverter technology — although San Diego Gas & Electric (SDG&E) has at least demonstrated that renewables-only microgrids can function for short periods of time with the right control systems.
In late May, SDG&E avoided an interruption of service to its Borrego Springs customers as a result of planned grid maintenance, by providing them electricity from a microgrid based around a nearby 26-megawatt PV power plant for nine hours.
“The microgrid generated the majority of power during this time from the large Borrego Solar facility, using batteries and traditional distributed generation to ‘follow the load’ and fill in gaps created by the solar facility,” reported SDG&E.
New York Times: Enacting Cap-and-Trade Will Present Challenges Under China’s System
American officials have applauded President Xi Jinping’s commitment to a national market for greenhouse-gas quotas as a breakthrough in environmental cooperation.
But to work well, Mr. Xi’s pledge, made at the White House on Friday, will demand big changes from a Chinese government accustomed to heavy-handed intervention and skewed statistics. It will take years of effort to build a substantial market that plays a major role in curbing emissions, and even then, it could founder, like similar initiatives elsewhere, experts said.
Vox: Solar Power Is Booming in India. Will It Reach the People Who Need It Most?
The sun is shining on India, and India is poised to take advantage of it, with massive investments in solar energy facilities to help meet the needs of a population that is expected to grow to make it the planet’s most populous nation by 2022. But will the power go to the people who need it most?
With its large land mass and tropical location, many experts consider the country particularly suitable for solar power. In fact, a recent study by Deloitte and the Confederation of Indian Industry estimated India’s solar power potential at 749 gigawatts — nearly three times the country’s entire installed electrical capacity in 2012 — and reported that not even 1 percent of this potential is currently tapped.
Climate Central: Obama Says Paris Climate Talks Bound to ‘Fall Short’
President Barack Obama said he hopes major countries agree to “aggressive enough targets” to cut carbon emissions at climate talks in Paris later this year, but he said any deal will fall short of what is needed to slow global warming.
“I'm less concerned about the precise number, because let's stipulate right now, whatever various country targets are, it's still going to fall short of what the science requires,” Obama said in an interview published in Rolling Stone magazine.
Quartz: This Sports Car Runs on Seawater
When a months-old company called NanoFlowcell AG showed up at the Geneva Motor Show in March 2014, debuting its prototype for a “supercar” powered by saltwater-filled flow battery, onlookers appeared intrigued but skeptical.
But now that the Quant e-Sportlimousine has been approved for use on European roads, there’s more enthusiasm, and some in the tech media are making the inevitable comparison with the high-profile luxury electric carmaker Tesla Motors and its Model S. The concept of the car, after all, is stupendously attractive. It has four motors — one for each wheel — powered by electricity generated from a process of filtering ionic liquid, or saltwater. The car carries the electrolyte fluids in two adjacent 200-liter tanks separated by a membrane. The fluids in each tank are slightly different, and it’s the reaction between them when they cross the membrane that creates electricity.
Guardian: George Osborne Presses on With Hinkley Power Station Despite Criticism
Nuclear power returned to the top of the political agenda this week when George Osborne used his visit to China to underline the government’s determination to push through the Hinkley Point C power station project.
There are expectations that the energy company behind the proposed plant, EDF of France, will announce a final investment decision on the £24.5B scheme during the visit of Chinese premier Xi Jinping to London next month.
Beijing holds the key to Hinkley because state-controlled EDF wants two of China’s nuclear companies to commit as investors before it gives the green light.
Flow-battery builder Imergy Power Systems is working with China's Juno Capital to develop energy storage and backup power for China’s telecommunications market. This phase is a pilot program looking to replace diesel backup at remote telecom equipment sites with vanadium redox batteries.
The Juno Capital Group is an investment company based in Beijing “specializing in bringing financing” and “assisting the cleantech partner to establish a strong strategic foothold in the Chinese market.” Juno intends to integrate the flow battery with renewable energy for “off- and weak-grid telecommunications installations across China.”
SunEdison has pledged to buy up to 1,000 of Imergy's 30-kilowatt flow batteries as part of its goal of bringing power to 20 million people by 2020.
Bill Watkins is the CEO of this startup, which now has to deliver on the largest flow-battery order to date. Imergy has around 110 units in the field. The Imergy product can provide from two to 12 hours of output duration.
Imergy, formerly known as Deeya, has raised more than $100 million from Technology Partners, New Enterprise Associates, DFJ, BlueRun Ventures and SunEdison. The company pivoted from its original iron-chromium chemistry to a refinement of a vanadium-electrolyte technology licensed from Pacific Northwest National Laboratory.
Remote telecom sites in China or India have long been targets for flow batteries as diesel replacements. Imergy Power Systems' COO Tim Hennessy told GTM that Imergy flow batteries paired with solar can deliver electricity in Hawaii for 12 cents per kilowatt-hour. Diesel-generated electricity in the developing world costs around 50 cents, as opposed to 10 cents for combined PV and Imergy storage, according to GTM's reporting.
Jack Stark, Imergy CFO, told GTM, “If there's a need for discharge duration in excess of two hours or for a relatively fast charge or multiple cycles, no other battery can do those things well, and it's in those markets that we will thrive.”
As far as revenue is concerned, Stark said, “The home run is demand charges, energy and the SGIP, and then add on aggregation of storage assets.”
GTM Squared, GTM's new premium service, is taking a deeper look at flow batteries in a just-published first installment of a three-part series.
Arizona Public Service has offered to withdraw its request to increase the grid access charge for residential solar customers, claiming that opponents have turned the issue into “political theater.”
In a filing submitted on Friday, APS said it would drop its proposed fee increase if regulators move forward instead with hearings on the cost of providing electricity service, in order to determine future rates that are fair to all customers.
If the Arizona Corporation Commission accepts the APS recommendation, regulators would launch an investigation into the value-of-solar that would establish 1.) the actual costs for APS to serve rooftop solar customers and 2.) the amount those customers pay for continued reliance on the grid. The utility asked for the ACC to reach a decision by March 2016 so the results could be incorporated in the next APS rate case.
In April, APS requested to increase fees on solar customers from 70 cents per kilowatt, or roughly $5 per month, to $3 per kilowatt, or roughly $21 per month. The utility contends that solar customers are currently underpaying for their use of the power grid, which shifts costs to non-solar customers.
Rooftop solar advocates argue that the fees are designed to harm the industry, which has been growing feverishly in recent years, leading to lower electricity sales for utilities.
Since APS proposed the $21 fee, several conflict of interest complaints have been filed against Arizona commissioners. The utility is believed to have spent as much as $3.2 million in last year’s ACC election to help its favored candidates win office. Three commissioners have been asked to recuse themselves from a decision on the solar charges, because of their ties to APS.
APS said these complaints were filed to disrupt the regulatory process and prevent the ACC from considering serious-minded rate design.
“Unfortunately, what should have been a relatively simple decision-making process has been turned into political theater by attacks and distortions from rooftop solar leasing companies that seek to paralyze Arizona regulators,” APS said in a statement.
“We hope our proposal will provide an alternative for the ACC to move forward with a much-needed discussion about how to update electricity pricing to reflect energy innovations like rooftop solar, battery storage and home energy management systems,” the statement read.
Research groups have conducted several studies to try and assess the value of solar. Some studies find that solar creates a cost-shift, while others show that grid-tied solar produces a net benefit to all ratepayers.
SolarCity launched a new solar service this week to provide solar to affordable housing developers so residents can pay less for their electricity.
The projects will be built on-site, on the rooftops of either the apartment buildings or carports. In some cases, SolarCity may build a carport over a parking lot on which to install the solar panels.
“The key to solar growth is to bring it to new audiences,” said Jonathan Bass, VP of communications for SolarCity.
In this case, the key is also an additional $54 million in incentive funding for the California Public Utilities Commission’s Multifamily Affordable Solar Housing (MASH) program. The money will support 35 megawatts of new solar capacity.
Bass said that the combination of net metering and the MASH funds makes the projects viable. Low-income residents in California receive subsidized electricity at a lower cost than other ratepayers, so making the cost of solar pencil out for those customers can still be a challenge despite the falling costs of the technology.
“Today, it would be tough to make the economics work without MASH,” said Bass.
But that could change in California depending on what happens with the state's net metering 2.0 proceedings. One policy proposal, CleanCARE, would shift some of the funds that go to low-income customer subsidies to renewable-energy facilities, energy-efficiency measures, energy storage and demand response. Customers would still receive a low rate, but it would be enabled by clean energy rather than just a subsidy.
There are many challenges to make solar and clean energy work for low-income markets, but it is increasingly happening elsewhere. SunEdison has various power purchase agreements with public housing authorities in Massachusetts that provide net metering credits for solar PV arrays installed elsewhere in the utility’s territory. SunEdison provides the PPAs through PowerOptions, which purchases power for nonprofits and government entities.
SolarCity is leveraging its multifamily housing experience in its expansion into affordable housing. The company has more than 100 multifamily projects in California. It also recently started offering community solar to renters in Minnesota. Bass said that the Northeast would likely be the next place that SolarCity might try to introduce its affordable housing solution.
Community solar in its various forms is growing quickly. A recent report from GTM Research, U.S. Community Solar Outlook 2015-2020, found that community solar is the most significant U.S. solar growth market, with more than 500 megawatts installed in 2020.
The focus on multifamily and low-income clean-energy solutions has been growing considerably in the past year. In July, the Obama administration announced the availability of more than $500 million for community solar for low-income citizens.
Earlier this year, WegoWise, a leader in multifamily efficiency projects, teamed up with Elevate Energy and New Ecology to bring energy-efficiency projects to low-income housing in seven states. The funding comes from a series of grants from various energy and environmental organizations.
Property-assessed clean energy financing is also coming to the multifamily sector now that the U.S. Department of Housing and Urban Development has given its backing to PACE projects for multifamily properties. So far, most of the projects haven’t been targeted toward low-income housing, but the support from HUD should allow PACE providers to tackle the affordable housing market.
Multifamily affordable housing may be just one avenue to bring clean-energy solutions to low-income communities. In New York, Con Edison is partnering with local startup BlocPower to bring efficiency and solar projects to houses of worship and nonprofits in underserved communities as part of its demand-side management program to reduce electric load in order to avoid building a $1 billion substation.
BlocPower CEO and founder Donnel Baird sees an opportunity, albeit a complex one, which doesn’t have to rely on government money and grants.
“Let’s be honest: There’s a problem of finding the right community leaders who will actually get something done,” he said at the REV4NY Exchange in New York City. “But you can also look at the low- and moderate-income group as a $400 billion market opportunity that’s not being appropriately served in many ways.”
There’s a simple and obvious logic to pairing batteries with solar power: capture solar energy when the sun is shining, and then use it when the sun goes down.
But the economic realities of the commercial-scale solar-plus-storage projects being deployed today don’t often match up with that seemingly simple proposition.
That’s clear from taking a close look at four utility-scale solar-battery projects announced in the past two weeks. Only one, a 17-megawatt solar PV array with 52 megawatt-hours of lithium-ion batteries being built by SolarCity on the Hawaiian island of Kauai, is intended for long-term shifting of solar power from midday to evening. That business proposition makes sense for a co-op that’s trying to replace expensive diesel-fueled generation with a clean alternative.
But with three other projects on the mainland in Texas, Ohio and Georgia, very different economic imperatives apply. There’s plenty of low-cost coal-fired and gas-fired power for these grids to draw from, and batteries are still too expensive to compete with those alternatives. That means the economic opportunities for these projects will be the same ones that work for standalone energy storage systems today: frequency regulation, peak shaving, asset deferral, and other well-defined use cases.
These three battery projects are still taking advantage of the benefits of co-locating with solar power, however. Those include a lower cost of siting and grid interconnection, taking advantage of soon-to-expire federal investment tax credits to lower the cost of the batteries, and in some cases, actively managing batteries and solar as a single, grid-connected resource.
GTM Research projects a $1 billion U.S. market for battery-backed solar PV systems by 2018, with much of the growth to come in “front-of-meter” applications at utility scale. Here’s how some of the earliest commercial-scale projects in the arena are approaching the market.
Stacking value streams for commercially viable projects
Take S&C Electric Company’s new 7-megawatt, 3-megawatt-hour battery system being built for the municipal utility of Minster, Ohio. S&C is teaming up with Half Moon Ventures, which will tie the batteries to its 4.2-megawatt PV solar array.
“This project is standing on its own. There’s no money coming from outside sources, no money from the government,” Troy Miller, S&C’s grid solutions director, said in an interview this week. That’s a critical distinction from almost all the existing utility-scale solar-storage projects out there today, which have used government grants or research funds to avoid the tricky question of whether the projects can stand on their own, financially speaking.
To make that happen, S&C and Half Moon Ventures have targeted four specific economic value streams. First, they’ll play the batteries into mid-Atlantic grid operator PJM’s frequency regulation market — the primary market for most of the country’s deployed megawatt-scale battery capacity today.
Second, S&C will use its storage management system to improve power quality, inject reactive power, and otherwise manage conditions on the distribution grid where the solar farm is connected. That will allow Minster to avoid deploying grid gear to handle those same issues.
“Most important for Minster is that they’re helping with demand response,” Miller said, by storing solar power and discharging it when the town’s demand for energy is peaking to defer expensive spot-market purchases. “There are certain days when you’re going to run into some trouble there, and then you’ll go into peak shaving and exit the PJM market.”
These use cases don’t yet tie solar and storage directly together. But “as the penetration of solar on feeders becomes higher and higher, there’s more instability on the grid,” he said. “We’re doing a number of projects on solar smoothing, time shifting, and to maximize the stability of that feeder, even if it’s not co-located with PV.”
Lowering costs through standardization of solar-storage
Managing this solar-grid interconnection is one of the key goals of another project announced last week by utility Southern Company. It’s a 1-megawatt, 2-megawatt-hour battery from LG Chem, with power conversion and equipment from grid giant ABB, co-located with a 1-megawatt solar PV array connected to the medium-voltage distribution grid in Cedartown, Georgia, operated by Southern Co. subsidiary Georgia Power.
The final partner in the project, the Electric Power Research Institute (EPRI), is using this combination to “investigate whether there’s a natural advantage of putting storage with solar,” Haresh Kamath, EPRI program director for energy storage and distributed generation, said in an interview this week. “This may be used as a model for how we’d implement storage in places like these in the future to solve problems,” such as two-way power flows and voltage fluctuations.
EPRI is also working with its partners to standardize the approach to siting, interconnecting and operating batteries alongside solar installations, he said. “A lot of the work around this project is targeted at reducing these soft costs,” through standards like the EPRI-developed communications protocols for how solar and battery inverters talk with utility control systems.
“People have talked about this for a long time, but it’s never been achieved at the distribution level,” said Kamath. Even so, utilities like Southern California Edison are already starting to demand standardized plug-and-play battery systems from vendors to deploy quickly into evolving grid-upgrade plans, and bringing solar-storage systems on-line quickly and cheaply will also require this kind of standardization.
The project is mostly funded by Southern Co., though an EPRI-led group of utilities have also contributed money. “We’re looking to take this information and disseminate it to other utilities, and across the industry in general,” said Kamath.
The secret sauce of competitive solar-storage systems
Standardized storage is also a part of the third project announced last week, this one in Texas. Solar developer OCI Solar will be using the Y.Cube systems launched by German startup Younicos last week, which combine batteries, power conversion hardware and control software in 250- or 500-kilowatt units.
Those systems will be built into a 1-megawatt lithium-ion battery to be sited alongside one of OCI’s several solar farms being built in the territory of Texas grid operator ERCOT. For the past year or so, Younicos has been running the 36-megawatt Notrees wind farm battery array owned by Duke Energy, which gives the startup a good deal of experience in how to manage storage in the ERCOT market, spokesperson Eugene Hunt said in an interview this week.
But the companies are keeping quiet right now on just what economic values they’ll be seeking to capture with the battery array, and how they will relate to the economics of solar.
“We haven’t released any final details on this,” Laura Waldrum, communications manager with OCI Solar parent company OCI Energy, said in an interview this week. OCI’s solar projects in Texas range in size from 5.5 megawatts to 110 megawatts, but it isn’t disclosing which one will get the new battery.
Younicos, which is combining batteries with solar in projects in Europe, hasn’t laid out how it will maximize the revenue potential from its OCI project either. But as Hunt noted, “There’s going to be a whole lot more solar deployed, and storage is going to play an increasing role in that.”
Asset-backed securities, such as the one just offered by AES Distributed Energy, are a source of low-cost capital for solar project development. And low-cost capital is the lifeblood of solar projects and solar market growth.
As (expensive) tax equity funding for solar fades in the looming shift of the federal Investment Tax Credit, new classes of financing are going to emerge — and asset-backed securities (ABS) is one of them. (Securitization is the practice of pooling various sources of debt and selling it as a package to investors on the secondary market.)
Distributed solar power entered the world of securitization when SolarCity offered a private placement of $54.4 million in 2013. This week's AES securitization is now the fifth solar ABS, with three from SolarCity and one from Sunrun, for a total of $560.5 million. The AES deal aggregates a portfolio of 15 projects totaling 43 megawatts of municipal, commercial and residential leases and power-purchase agreements.
AES Distributed Energy was formed earlier this year when AES acquired Main Street Power, a developer of distributed solar projects in the 300-kilowatt to 5-megawatt range. The acquisition followed Duke's stake in REC and Coronal's acquisition of Heliosage, highlighting the trend of utilities and financiers acquiring developers. Morgan Stanley, which finances AES Distributed Energy through a subsidiary, is underwriting the deal.
AES called this securitization “the first deal backed by solar assets to be sponsored by a utility company.” Sunrun and SolarCity are one thing — but a solar ABS from a $17 billion annual revenue power company lends a new level of credibility to this capital-raising tool. AES owns operating power generation resources of more than 35 gigawatts, including 8 gigawatts of renewable generation.
We spoke with Chris Shelton, VP for New Energy Solutions at AES, last week. He noted that AES operates in a lot of markets around the world where power prices are higher and the insolation is substantial. He said, “We don't take the view that incentives in the medium term are necessary across these markets. They are not.” Shelton noted in a previous interview, “While the U.S. opportunity is interesting, for AES, it's exciting to think of our other markets as well.”
Shelton said that the Main Street Power acquisition gave AES “solid core capability” across six strategic units at AES, with some projects already built in El Salvador, and others under development in the Dominican Republic and Mexico. Shelton said that U.S. distributed generation would be driven by a “dual mandate of sustainability and resiliency for the enterprise.”
“If a progressive U.S. company wants a sustainability initiative across a number of its factories, we can serve that enterprise with a comprehensive touch across several countries.” Shelton said that storage would be a part of these projects if it bolstered the project economics.
AES serves over 80 percent of El Salvador with its distribution network and currently has over 65 megawatts of distributed PV generation in operation across North America.
A source close to the AES deal suggested that “as more issuers like AES come to the table, we're going to start to see companies with much greater balance sheets create a much larger issuance pool.” The source envisioned a virtuous cycle in solar ABS as now occurs in the auto market, where investors have become comfortable with the “clean, simple stories and recovery rates” and where “every other [ABS] deal is an auto deal or auto lease” from “Honda or Mercedes–Benz.”
The source also predicts that the ratings of securitized solar will rise to A+ and AA, and that folks “such as Pacific Life and CalPERS will want to get in on this paper.”
Distributed solar is finally reaching the scale and level of familiarity where it can access massive pools of once-unavailable lower-cost capital. It's another piece of the equation where solar is cutting costs and becoming more competitive. This deal could open up the emerging solar ABS landscape.
Photo: A 2.5-megawatt ground-mount PV project in El Salvador
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Brazil is a sleeping solar giant. As the country’s solar market begins to stir, what are the main changes that need to occur for Brazil to join China, the United States, and Japan as one of the top solar markets in the world?
Strong fundamentals, but…
Brazil has impressive strengths. The country boasts a population of 200 million people, 570,000 gigawatt-hours of consumption per year, average retail electricity rates in the double digits, and 70 gigawatts of new generation needed by 2024. There is already a robust auction process for procurement and a bilateral market, and net metering is in place. Several states have passed tax exemptions for solar, and the government has committed to 1 to 2 gigawatts of utility-scale solar per year. As Gabriel Ferreira of local PV company SolarVolt Energia notes, utility-scale procurement will bring more international developers and a supply chain to the country, creating traction that will benefit the distributed generation market.
Even some of the country’s weaknesses actually support the case for solar: while Brazil was recently downgraded due to serious economic concerns, and the electricity sector took a beating last year as drought exposed the dark side of hydro-dependence, accelerating the solar industry could spur economic development and hedge against future volatility in electricity prices.
So why isn't Brazil already a solar juggernaut?
Net metering: Necessary but not sufficient
Net metering has been in place since 2013, but the market has been very slow to develop. In the Latin America PV Playbook, we estimate that a little over 33 megawatts have been installed to date, with two-thirds of that under net metering. On the surface, this may seem surprising, with residential rates averaging $0.17 per kilowatt-hour, commercial rates at $0.15 per kilowatt-hour, rates increasing 42 percent in 2015, and further increases expected. In addition, investing in solar has a serious economic driver as a hedge against inflation, which is currently at 9.53 percent. With 6-kilowatt systems costing around $1.40 to $1.50 per watt, the paybacks under these retail rates could be tremendous.
There are a few contributing factors to the delay in market growth. First, net metering is for individual use only; third-party direct sale is not permitted. Some solar companies have explored alternative contracts structured around renting and energy management, but the lack of explicitly permitted direct sale is definitely a barrier to really scaling the market. Another issue is the cap on system sizes, which must correspond to peak load on-site or demand. This has the de facto effect of incentivizing self-consumption rather than maximizing production and export, particularly with regards to commercial customers.
What needs to happen for the market to grow? Third-party ownership needs to be legally codified in the regulatory structure. Additionally, system-size caps could be removed, and resolved instead at the billing level with bills zeroing out on a monthly or quarterly basis to help offset consumer bills without directly encouraging export. As SolarCity SVP Marco Krapels has noted, “We’ve got our eyes on Brazil—its insolation, electricity rates and demand place it among the most promising solar markets in the world. A few simple, low-cost regulatory changes, such as allowance for third party ownership and expansion of Net Energy Metering, could jumpstart the local distributed solar market and create tens of thousands of new jobs in the process.”
Taxes: Improving, but more work is needed
Taxes increase the cost of installed solar in the country by up to 40 percent compared to Brazil’s neighbors. With the market still highly dependent on cash sales, already price-sensitive customers are often scared off. Early adopters are often the individuals and businesses that view sustainability as a moral investment in their future, although not necessarily as an economic one. This obviously limits the total available market quite a bit.
Taxes are levied at several points in the PV value chain. PV equipment faces federal import taxes, state industrial production tax, and state value-added taxes. Gross electricity consumption is also taxed at the state level. Generators also pay transmission and distribution taxes when selling on the free market.
This has created challenges for every approach to market for PV. Large-scale plants have to pay the taxes on equipment and then taxes on transmission and distribution (although projects of less than 30 megawatts have a discount on the latter). Distributed generation faces higher costs due to the taxes on equipment, as well as longer payback times because net metering does not offset the taxes applied to gross electricity consumption.
What needs to happen for the market to grow? Several states have already passed exemptions on the value-added tax on electricity, accelerating payback times. This needs to happen in most of the country. Solar generators of any size could be exempt from the transmission or distribution tax, or see heavier discounts. Finally, solar equipment — especially modules and inverters – could be exempted from the hefty federal and state taxes.
Cost of capital
Lending rates in Brazil are in the double digits. For capital inside the country, interbank lending rates are at 14.3 percent. What's more, the weakening of the Brazilian real against the U.S. dollar means that bringing in external capital requires expensive currency hedges.
The Brazilian National Development Bank has offered low-cost financing to utility-scale developers, but this is contingent on the use of local content. Local module production in particular is likely to be very expensive compared to imported equipment, and far more expensive than tax-free imported equipment.
The other issue is credit ratings. Although commercial clients often have a strong track record with local banks, the credit-scoring system for individuals is still relatively new. This makes finding financeable offtakers in the residential market more difficult.
What needs to happen for the market to grow? Federal and state development banks need to offer low-cost financing to a wider range of players and eliminate the local content requirement. Lending to small and medium-sized enterprises, or to intermediaries that can in turn fund individual systems, would greatly increase access to capital. While the currency risk issue is not likely to be solved overnight, the government could explore dollar-denominated power-purchase agreements and currency hedging systems, such as the one proposed in India, to help attract international developers into the market. Continued support for measuring consumer credit through partnerships with local banks would help get financiers more comfortable with making large capital injections into the residential market.
Adam James is a Senior Analyst leading global downstream market coverage for GTM Research, with a specialty in Latin American markets. Interesting in seeing more of GTM Research's work on Latin America? Don’t miss the Latin America PV Playbook, and registration is now open for Solar Summit: Mexico, GTM’s first international conference. You can hear more from Adam on Twitter (@Adam_S_James) and stay up to date with the Latin America Solar Newsletter.
Bloomberg: Total Plans $500 Million Annual Investment in Renewable Energy
Total SA plans to invest $500 million a year in renewable energy, a step by Europe’s second-largest oil and gas company to expand in biofuels and solar.
The French company said in a presentation to investors it wanted to take “advantage of [the] fast-growing renewable market” to build a profitable business.
Total bought a majority stake in SunPower Corp., one of the largest manufacturers of solar panels in the U.S., for about $1.4 billion in 2011. The company earlier this year said it would invest 200 million euros ($223 million) to transform its unprofitable La Mede oil refinery into a biofuel plant.
Washington Post: China to Adopt Cap-and-Trade System to Limit Emissions
Chinese President Xi Jinping on Friday will announce a nationwide cap-and-trade program to curtail carbon emissions, adopting a mechanism most widely used in Europe to limit greenhouse gases, Obama administration officials said.
Expanding on a pilot project in seven Chinese cities, the cap-and-trade program will impose a nationwide ceiling on emissions from the most carbon-intensive sectors of the Chinese economy and require companies exceeding their quotas to buy permits from those that have sharply reduced emissions.
Guardian: Hillary Clinton Unveils Her Plan to Make U.S. 'Clean Energy Superpower'
A day after announcing her opposition to the controversial Keystone XL pipeline, Hillary Clinton unveiled a more comprehensive agenda for the U.S. energy infrastructure that seeks to transform the U.S. into “the clean energy superpower of the 21st century.”
The Democratic presidential candidate detailed her proposals on Wednesday in both a blog post on the website Medium and a fact sheet distributed by Clinton’s campaign.
Clinton’s plan calls for the existing energy infrastructure in the U.S. to be modernized through a series of steps, such as repairing or replacing oil and gas pipelines that are outdated and risk both oil and methane leaks and other hazardous accidents.
Vox: What Germany Learned From Its War on Coal
German politicians speak enthusiastically about the ongoing green revolution, dubbed the Energiewende (or “energy transformation”), as a model for tackling climate change. The country is sometimes held up as a template for President Obama's own efforts to reduce coal-fired power and green the U.S. electricity supply.
What gets less attention, however, is how frustrating and difficult Germany's energy turnaround has been in practice. The country offers a cautionary tale on why going green isn't always as smooth a ride as thought, and its Energiewende can offer some valuable lessons for the United States.
MIT Technology Review: Materials Could Capture CO2 and Make It Useful
A team of scientists at Lawrence Berkeley National Laboratory and the University of California, Berkeley have devised a method that uses super-porous molecular structures known as covalent organic frameworks, with catalysts to convert the carbon dioxide to carbon monoxide, which can be used in making a range of materials including fuels, plastics, and even pharmaceuticals.
The new materials, says Chris Chang, a chemist with Berkeley Lab’s Chemical Sciences Division and one of the co-leaders of the research team, are based on “a highly stable, porous structure that’s decorated with all of these catalysts.” Though it’s early-stage research and nowhere near ready to scale up to power-plant levels, it’s an important step toward finding practical ways to absorb and use carbon dioxide in both waste streams and the air.
IEEE Spectrum: Researchers Tweak Artificial Photosynthesis for More Efficient Hydrogen Production
A team of researchers from Germany and the U.S. have announced a new record value of 14% for the efficiency of water splitting by solar energy in a single cell. The previous record, 12.4%, was achieved 17 years ago by the National Renewable Energy Laboratory, and the value in subsequent experiments with a technology called artificial photosynthesis has hovered around that figure. The researchers published this result last week in Nature Communications.
These figures should not be confused with the light conversion percentages of photovoltaic cells, explains Thomas Hannappel of the Technical University Ilmenau in Germany, who was the academic advisor for the researchers. “The percentages refer to the hydrogen efficiency; that is, you compare the light energy captured by the photovoltaic cell to the energy that can be supplied by burning the produced hydrogen,” says Hannappel.