Orocovis sits right in the mountainous middle of Puerto Rico. It’s one of the island’s “more remote areas with challenging terrain” that on Thursday the U.S. Army Corps of Engineers said may not have electricity restored until April or May.
The town hasn’t had grid-connected power in the four months since Hurricane Maria. Instead, like many others on the island, Orocovis residents have been relying on costly generators. Alberto Melendez Castillo, the director of the S.U. Matrullas school there, said residents have also had to rely on canned food and milk.
This week, Sonnen and Pura Energía, a local solar installer, announced they’d brought two storage-plus-solar systems online at SU Matrullas. Now, Castillo says that teachers can use their computers, the school’s 150 students have enough light to do homework, the school's kitchens have running refrigerators, and the community has an off-grid center to help them weather the next storm.
While it may take months for workers from the Puerto Rico Electric Power Authority (PREPA) and mainland mutual aid crews to connect Orocovis back to the grid, the school can continue operating with the help of a 15-kilowatt rooftop solar system and two batteries -- one 4 kilowatts/8 kilowatt-hours and the other 8 kilowatts/14 kilowatt-hours.
Even after grid-connected power becomes available, said Castillo, the school plans to stay disconnected and run on its own energy. Plans for a water collection and purification system would make the school an entirely independent lifeline for the community in the case of another disaster.
Castillo said the school isn’t stepping away from grid connection because the community lacks confidence in PREPA or the government, but rather because the system will lower electricity costs. The project in Orocovis represents a larger trend in Puerto Rico, where residents -- especially those who can independently afford it -- are investigating renewables and storage systems that support an off-grid lifestyle.
As the territory’s government looks to privatize its utility and haltingly moves forward on plans for a less-centralized grid powered by more renewables, interest in leaving the grid altogether has grown. In a Feb. 14 status report, PREPA reported that the utility had restored power to about 76 percent of customers. On Friday, the island's federal oversight board scrambled to get a $300 million loan, with warnings that the utility would soon have to ration service if the money didn't come through.
“I’m hearing a lot of talk about going off-grid,” said Adam Gentner, director of business development and Latin American expansion at Sonnen.
Solar-plus-storage is not yet a mainstream technology, especially not in the U.S. Most applications are niche and uneconomical, even in the most favorable markets -- although that is changing. Dire circumstances have compelled Puerto Ricans to become energy experts in a hurry.
“Very few people really looked at storage as a solution, because -- well, they saw it as something costly and that...it was not a critical need,” said David Portalatin, CFO at local solar contractor Pura Energía. “Now, what Puerto Rico is talking about is having energy independence, and everyone wants battery storage.”
A natural disaster has turned into a value proposition for the technology.
“One thing I hear from every partner down here is that before the hurricanes, you always had to explain the value of solar and solar-powered off-grid backup systems to people. You had to explain why you would spend money on this, and why you need it, and what it does for you,” said Gentner. “Now, you don’t have to explain that to anyone in Puerto Rico.”
Since Hurricane Maria, Sonnen and Pura Energía have installed 10 solar-and-battery microgrids, including the two in Orocovis. The partners donated the equipment for each at a total cost of about $350,000.
Recently, their mission has shifted from emergency relief at critical load centers like a community-center-turned-shelter in Humacao and a children’s therapy center in Aguadilla, to providing "sustaining support” in remote areas that will continue to be without power for months to come. The Orocovis installation fits within that new direction.
The installs include laundromats, where residents can safely wash clothes without risking contamination and illness from bacteria, and locations with cellular routers, electrical outlets and refrigerators.
After installation, the sites become community-owned and -managed. Along with the logistical difficulties of reaching remote locations, Gentner and Portalatin said it has been a challenge to find a local site manager willing to shoulder a full-time, unpaid and hefty responsibility so many months after the hurricane, with much of the island still without electricity.
“It gets to a point where people get frustrated, I would say,” said Portalatin. “Because you can do this as a relief for a month, two months, three months, but it’s getting to a point where people are getting heartbroken and disillusioned with how this is all being rolled out on the island. […] This is not [an extremely] long-term solution; this is a solution that can work for a certain time. But at a point where your whole community doesn’t have light, we need to get long-term solutions to them and really fix the problem.”
Many Puerto Ricans are looking for long-term solutions on their own. On the for-profit side, Gentner said Sonnen’s business is also growing.
“In some instances, our business has become easier because people come seeking out a solar power backup system,” said Gentner. He added that Sonnen has seen growth since Hurricane Maria in part because it had landed several new partners just before the disaster. But he also thinks storage systems have “become far more mainstream” there as Puerto Ricans cope with the vulnerability of the central grid.
That’s "dramatically" changed business for Pura Energía as well, Portalatin said, which mostly focused on solar-only installations prior to the hurricanes. The contractor has repaired most of the damage to its residential and commercial customers, and is now working on many solar-plus-storage systems.
“Now, that’s what everyone wants,” said Portalatin. “It’s not an interconnected system -- it’s really an independent system, off-grid and microgrid.”
Gentner agrees that going off-grid is “a natural reaction to uncertainty.” But he said the growing desire to completely leave the grid has him worried about Puerto Rico’s future.
“I see a risk in Puerto Rico right now where there’s a lot of uncertainty with what’s going to come after PREPA. People don’t know what’s going to happen,” Gentner said.
According to Gentner, that’s led to more talk of grid defection -- that is, residents buying islanded systems and planning to stay off-grid for good.
That "is certainly something that our Sonnen battery can do, and something we’ve seen in our installations in Puerto Rico,” he said. “But our roots at Sonnen are in grid-tied energy storage.”
Gentner said Sonnen wants to build lines of communication with PREPA and other stakeholders to make sure that uncertainty and interest in off-grid systems don’t lead to a disjointed system.
Instead, Gentner envisions potential models like Germany’s, where Sonnen is based, with a “hugely decentralized grid,” and an open market for new utilities to join. Gentner said battery systems could connect into an island-wide virtual power plant, similar to Sonnen’s work in Germany and on the mainland.
Portalatin paints a similar vision, also referencing Sonnen’s example in Germany.
Though Portalatin said he sees Puerto Rico’s future -- like many on the island -- with a privatized PREPA, clean energy generation and microgrids, uncertainty is currently driving the conversation more than he’d like.
“What makes it complicated right now [is that] there are too many unknowns,” he said. “People are looking more into, 'How can I get the solution in my hands?' versus having to rely on PREPA to resolve the energy situation.”
Expanding the solar market to lower-income individuals and the businesses and nonprofits that serve them remains a top priority for the solar industry. They key is to figure out how.
Historically, participation in the solar economy has primarily been enjoyed by homeowners and large corporations with good credit. However, a valuable success story out of Colorado deserves to be highlighted and considered for replication. There, the Housing Authority of the City and County of Denver (informally known as the Denver Housing Authority, or DHA) has been working for several years to make solar available to the low-income neighborhoods it serves.
According to Chris Jedd, portfolio energy manager for DHA, there are two sets of questions that should be asked of those interested in going solar: What type of housing are they in? And who pays for the energy?
Subsidized housing type
There are a number of programs and subsidies that facilitate affordable housing, which can be confusing for a solar developer trying to comprehend the market opportunity. These programs include:
- Public housing -- Generally owned and operated by municipal housing authorities and funded with annual operating subsidies from the Department of Housing and Urban Development (HUD) to pay for expenses such as operations and maintenance, capital improvements and utilities, including electricity.
- Section 8 -- Another HUD-supported program designed to facilitate home affordability through two means: a voucher program administered by local housing authorities and a project-based system that incentivizes construction of multifamily affordable housing by the private sector.
- Low-Income Housing Tax Credits -- A federal tax credit program used to finance the construction and rehabilitation of low-income affordable rental housing. (HUD offers insight and data on LIHTC here.)
- Additional state programs.
Complicating things further, some low-income properties incorporate several of the above housing types into one building behind a single electrical meter. Of course, these programs may be insufficient to fully meet the needs of the low-income neighborhood. In Colorado, for example, of the 45 housing authorities that offer Section 8 vouchers, only four have an open waiting list. As such, many low-income households may be paying market rates for electricity that are likely beyond their means.
Who pays the energy bills?
Because HUD directly or indirectly pays the utilities for a large portion of subsidized housing, there is often little incentive for local housing authorities to take the risk of investing and making a long-term (20-year) commitment in cost-reduction technologies (solar and efficiency measures). The savings would pass through to HUD and not be retained by the housing authority or the tenant.
A similar challenge often exists with Section 8 housing that’s owned by third parties -- participation in the Section 8 program requires a cap on total housing-related expenses, including energy costs, which a resident is required to pay. If energy cost-reduction measures lower electricity payments, for example, the building owner could raise the rent, so long as the total affordability cap is not violated.
In addition, there are LIHTC properties that are owned by partnerships, and the utilities are generally paid for as an operating expense out of the partnership's budget (without any support from HUD). The largest LIHTC properties may have hundreds of units in them and are master-metered (a single meter for the entire building). This means the roof space cannot support enough solar to meaningfully cut into the electricity bill, making it difficult to allocate the benefits back to the low-income tenants.
The good news is that HUD continues to modify and develop programs and policies to overcome these challenges in an effort to expand solar access to low-income Americans.
Two specific policies that have proven to be helpful include HUD’s Energy Performance Contracting System and HUD’s Rate Reduction Incentive Program.
Third-party power-purchase agreement: To overcome some of these disincentive barriers, DHA came up with a win-win solution. In 2012, DHA entered into a power-purchase agreement (PPA) focused solely on public housing, which narrowed and simplified the subsidy structure. The PPA was financed, owned and maintained by a third-party provider, which then sells the electricity to the DHA.
The project included a combination of roughly 660 solar systems, equating to a total capacity of about 2.5 megawatts. To share the utility savings generated from the PPA between DHA and HUD, DHA pays a lower utility rate, of which HUD retains the savings by providing less utility subsidies to DHA. In addition, DHA leases its rooftops to the PPA provider, retaining some of the savings through rental income.
Community solar: Another solution to these barriers is turning to an innovative community solar concept. DHA recently closed on financing a 2-megawatt system that will be built by Namaste Solar. DHA is the developer, owner and subscriber of the garden, and partnered with Grid Alternatives and other industry experts, to assist in navigating the complex utility policies, financing structures and allocation of benefits.
The system will power approximately 700 low-income units across Xcel Energy’s Denver territory, including DHA properties, other local housing authorities and affordable housing developers. Xcel’s virtual net metering program allows DHA to allocate energy from the DHA Community Solar Program to the various low income properties.
In addition, Xcel conducts a competitive RFP for renewable energy credits from community solar projects. Bid evaluation factors include "level of low-income subscribership" and "innovative proposals that benefit low-income subscribers throughout the life of the contract." This helps encourage projects, like DHA’s, within the community solar program. To support the long-term financing of the system, DHA had to act as the counterparty to the deal. It committed to subscribe the 2-megawatt system in its entirety or pay the financing partners in lieu of PPA payments. The system was sized and the PPA rates were designed in order to produce a 20 percent savings on electricity costs.
Jedd’s advice to solar developers trying to play a part in this opportunity is to “thoughtfully think through the subsidy structures to optimize benefit flow and minimize risk.” In addition, local champions within the housing authority are key. DHA and larger housing agencies generally have staff, like Jedd, as dedicated energy managers. The agency’s chief financial officer will also be a key stakeholder, so reach out to her early in the process to explain how the cost reduction benefits can allow for expansion of their mission to provide affordable housing.
Advocacy is also a key component. DHA has collaborated with local stakeholders and Xcel Energy to expand opportunities for affordable housing inclusion in community solar. Through a recent renewable energy planning proceeding in Colorado, Xcel specifically included nonprofit affordable housing providers in new, dedicated community solar programs that serve low-income customers, and will solicit bids for almost 20 megawatts of such projects through 2019.
Other states, like Massachusetts, offer adders for low-income inclusion in community solar projects. These policies are essential to ensuring that low-income customers and affordable housing providers will continue to benefit from community solar programs. California recently approved $1 billion for its Solar on Multifamily Affordable Housing program.
The Solar Energy Industries Association is also currently working on model community solar master, and individual, subscription agreements with leading law firms, developers and other stakeholders. These documents incorporate much of experience gleaned via the DHA Community Solar case and will be available to the public so the proverbial wheel doesn’t need to be reinvented each time.
The pieces of the puzzle are in place. Let’s leverage DHA’s great work so solar access can continue to expand across the country.
Mike Mendelsohn is senior director of project finance and capital markets at the Solar Energy Industries Association.
A proposal in Germany to phase out coal made headlines this month, but would barely make a dent in global coal consumption, according to the International Energy Agency.
If Europe’s largest economy goes ahead with plans to shutter its more than 46 gigawatts of coal-based generating capacity, global consumption would only drop by 2 percent, said Carlos Fernández Alvarez, a senior coal analyst at the agency.
“The impact of a phaseout will be limited,” he said. “Actually, consumption in the European Union is only around 6 percent of global coal demand. This percentage is declining and will decline over time.”
Earlier this month, plans to curtail coal-fired power generation emerged as part of a joint policy platform agreed on by Germany’s Christian Democratic Union (CDU) and Social Democratic Party (Sozialdemokratische Partei Deutschlands, or SPD in German) political groups.
The two parties have been locked in talks about forming a coalition government since the CDU, led by German Chancellor Angela Merkel, failed to secure a majority in national elections last September.
Whether or not the coal reduction program will come to pass is still in doubt, though. The SPD is planning to vote on the agreement with the CDU at the beginning of March. If the SPD’s 460,000 members don’t affirm the deal, Germany could face new elections.
And the SPD’s stance on coal is far from clear. Although the party backs Germany’s efforts to meet climate targets, it is also keen to be seen as a standard-bearer for employment in coal-mining communities and has refused to commit to an end date for coal-fired generation.
For now, said Fernández Alvarez, the proposal on the table “is for a commission on growth, structural change and employment to come up with, by the end of 2018, a plan for the gradual reduction and phaseout of coal-fired power generation, rather than an immediate coal ban.”
While Germany's decision will have a relatively small effect on global emissions, it will have a significant impact domestically.
Figures from Euracoal, the European Association for Coal and Lignite, show that more than 46,000 people were employed in Germany’s coal-related industries in 2015. The SPD wants to see these jobs redeployed in other sectors, such as renewable energy.
Policymakers in both parties are aware that Germany’s failure to curb coal consumption is a serious threat to the country’s credibility as a climate change leader.
As Bloomberg reported last November, “The country still gets 40 percent of its energy from coal, a bigger share than most other European countries. And much of it is lignite, the dirtiest kind of coal. As a result, Germany is set to fall well short of its 2020 [emissions reduction] goal.”
Energy policy in Germany has historically focused on axing nuclear and boosting wind and solar, with coal taking a back seat. Only this year is the country slashing state aid for mining.
The CDU and SPD have reaffirmed their commitment to phasing out nuclear power by 2022, which means any cuts in coal generation will have to be made up for by a mix of renewables and natural gas.
U.S. Energy Information Administration data shows switching from lignite to natural gas could reduce carbon emissions by more than 45 percent.
Even if all of the 212 terawatt-hours of lignite and hard-coal-based energy consumed in Germany in 2017 were to be switched to gas, though, the generation capacity would still emit a significant amount of carbon dioxide (more than 42 million tons of carbon dioxide a year, according to this author's calculations based on EIA emissions data).
Boosting generation from renewables, meanwhile, is fraught because of the capacity factors for wind and solar.
Even assuming a highly optimistic capacity factor of around 50 percent for offshore wind, replacing Germany’s coal generation would require more than 92 gigawatts of renewable capacity. That is almost six times all the offshore wind installed to date in Europe.
How Germany resolves this conundrum, assuming it decides to go ahead with coal phaseout plans next month, will be instructive to other countries aiming to go down the same route.
But even if the rest of the European Union decides to follow suit, it will have a minimal impact on global coal demand, which is overwhelmingly dominated by China. “For better or worse, the relevance of Europe on coal markets is no longer great,” said Fernández Alvarez.
Former Energy Secretary Ernest Moniz returned to MIT at the end of the Obama administration last year to continue working on clean energy and nuclear security. He also became CEO of the Nuclear Threat Initiative and CEO of Energy Futures Initiative, a nonprofit energy innovation policy institute.
Now, he's taken on another role as board member of one of the country’s largest utilities, Southern Company.
Southern Company has made some cutting-edge moves into distributed energy, such as its acquisition of microgrid company PowerSecure. But its subsidiary Georgia Power has also pursued controversial and expensive new nuclear power plants.
“I have long admired Southern Company for its innovative approach to research and development within the clean energy space, and look forward to joining the board,” Moniz said, in a statement. “Tom is an industry leader and I’m eager to work with him and the entire board in helping Southern advance at a time of great change in the energy world.”
Adding to his to-do list, Moniz was also appointed to the advisory board of Terrestrial Energy this week.
At Greentech Media’s Energy Storage Summit in late 2017, most attendees said they believed at least 40 percent of utilities would have energy storage in their integrated resource plans within five years. The growth of energy storage also means plenty of moves afoot in the burgeoning industry.
Marissa Gillett has joined the Energy Storage Association as vice president of external relations and Jason Burwen has been promoted to VP of policy.
Liquid air energy storage provider Highview Power has expanded into the U.S. with an office in New York and brought on financier Colin Roy as chairman. Roy previously helped establish German franchises of Merrill Lynch and SG Warburg and was a co-founder and CEO at investment bank Greenhill & Co.
Zinc-iron flow battery startup ViZn Energy Systems named Stephen Bonner president and interim CEO after Ron Van Dell resigned last month. Bonner is also chairman of the board. ViZn vowed last summer it could undercut the cost of lithium-ion storage and deliver its technology at 4 cents per kilowatt-hour, 20 percent below the 4.5-cent per kilowatt-hour solar-plus-storage PPA NextEra signed with Tucson Electric Power in mid-2017.
Ninety-year-old energy storage company Trojan Battery has a new president and CEO, Neil Thomas, who succeeds Jeff Elder. Trojan makes deep-cycle batteries for everything from solar backup to marine and oil and gas applications.
A much more recent entrant to the world of batteries, SolidEnergy Systems, has brought on energy storage veteran Bud Collins as COO. Collins joins the lithium-metal battery startup from NEC Energy Solutions where he was CEO; he was previously with A123 Systems and APC-MGE.
Another fairly recent market entrant, Romeo Power Technology, picked up Ned Horneffer in December as its director of business development. Horneffer was previously at Pure Energy Partners. Romeo is developing battery packs for everything from EVs to C&I applications to personal power options.
Enertech Search Partners, an executive search firm with a dedicated cleantech practice, is the sponsor of the GTM jobs column.
Among its many active searches, Enertech is looking for an SVP of project development.
The client is seeking an Senior Vice President to manage a large team to develop and implement ongoing strategy for a variety of technologies, industry segments and geographic markets, including a global reach. The ideal candidate for the role is highly analytical by nature, is a strong mentor and leader, has extensive energy contract negotiation experience and understands FERC policies such as PURPA. The SVP should have a strong track record of renewable energy project delivery (solar and/or wind required) and be a "hands-on" leader, active in all phases of the process.
Enertech Search Partners welcomes Betsy Martin as managing director for Smart Cities and eMobility. Her 15 years of experience leading technical recruiting and building teams in Silicon Valley and Boston positions her perfectly to help Enertech continue to expand its service offerings. “The addition of Betsy to our firm will translate into a natural expansion of our successes in distributed energy, energy efficiency, electric vehicles and grid transformation,” said Enertech CEO Paige Carratturo. Read more here.
GTM and Enertech recently surveyed hundreds of cleantech professionals in a wide variety of roles to understand how the industry is attracting and retaining the talent it needs to flourish. Download the free report here.
In the solar world, Sunverge Energy hired tech industry veteran Jon Bode as CFO. Bode was most recently CFO of grid management software startup Nexant.
Former SunShot Initiative director Minh Le is now general manager of energy and environmental services for Los Angeles County’s Internal Services Department. He will be responsible for the county’s energy efficiency and renewable energy initiatives including PACE and the Southern California Regional Energy Network.
Naveed Hasan has left Kaco New Energy as head of marketing for the Americas to join Sungrow USA as senior marketing manager.
Also in solar marketing, Tor Valenza is now director of marketing at SepiSolar. He was previously chief marketing officer of solar at Impress Labs.
Brian Scaccia has joined SunPower as corporate counsel, where he’ll focus on strategic M&A transactions as the company restructures. He joins SunPower from Cypress Creek Renewables.
Solar Installers of Washington, a state trade association, has named its first executive director, Allison Arnold. She was previously head of policy advocacy, marketing and communications for the U.S. solar business of Mitsubishi Electric.
New York utility Consolidated Edison has promoted longtime executive and electrical engineer, Timothy Cawley, to be its new president. He was previously president of Con Edison subsidiary Orange and Rockland Utilities. “We’re going to continue to innovate and use technology to give our customers more options, convenience and ability to control their costs,” Cawley said in a statement.
DER system provider EnSync Energy Systems has a new CFO, Bill Dallapiazza, who joins the firm from Franklin Energy Services. EnSync also promoted Kenneth Alft to VP of customer engineering.
Frederic Dross has left DNV GL as head of its module business to join global health and materials firm DSM as VP of technology Americas.
Jubran Whalan has joined distributed energy and power-focused private investment firm Constant Energy Capital as managing director. Previously Whalan was managing director at BP’s Global Structured Products division.
The National Association of Regulatory Utility Commissioners appointed John Rosales, commissioner at the Illinois Commerce Commission, to its board of directors.
The Electric Power Research Institute has chosen Andrew Phillips as VP of transmission and distribution infrastructure. Phillips is filling the role left by Rob Manning, who was recently elected to the board of the North American Electric Reliability Corporation.
Josh Cornfeld, a one-time GTM Research summer associate, has been promoted to VP at Marathon Capital where he is responsible for executing M&A and private placement engagements in the renewable energy and power sectors.
As always, please send clean energy jobs moves to tips@greentechmedia.
Last year, Bloomberg New Energy Finance defined renewable energy as the “new normal" in its Sustainable Energy in America Factbook. This year's edition affirms that finding.
While U.S. clean energy installations lagged, a record amount of capacity brought online in 2016 drove generation from renewables (including hydropower) in 2017 -- a year of uncertainty -- to its highest level ever, at 18 percent of the overall energy mix.
Natural gas and coal still remain the top producers of U.S. electricity, but both sources experienced a slight dip in 2017. Natural-gas generation dropped 2 percent, while coal fell 3 percent.
Rachel Luo, senior analyst for U.S. utilities and market reform at BNEF, said 18 percent may not sound like much, but it brings clean energy “within striking distance” of nuclear’s 20 percent generation contribution. The jump in renewable generation stems from the 2016 construction boom as well as an easing of drought in the West, which increased hydropower generation.
“In 2017 it’s a very significant story that renewables are making a lot of headway in pushing forward the decarbonization of the power sector, even as the natural gas share decreases,” Luo said.
But, she added, “natural gas still remains the largest single contributor to the electricity mix. [Its] downtick could be from a variety of factors [such as] the increasing penetration of renewables, but load growth is also stalling and…natural gas prices have recovered a little.”
Source: Bloomberg New Energy Finance
In recent years, the switch from coal to gas emerged as a main theme in BNEF’s Factbooks, which are produced in conjunction with the Business Council for Sustainable Energy. Now, clean energy claims more of the generation spotlight. But coal still accounts for 30 percent of the country’s generation.
While electricity generation from coal did fall year-over-year, Luo said its portion of the generation mix remained flat in 2017 because of changing demand and load. Coal retirements also slowed down from eight in 2016 to six in 2017.
BNEF said next year, though, the 12.5 gigawatts of coal plants already slated for retirement nearly rivals the all-time high of 15 gigawatts in 2015. Adding to those struggles, the ill-fated Department of Energy proposal to offer coal plants compensation for resilience made it among BNEF’s top five policy developments of the year. Luo said the resource is still facing economic headwinds from the same fuel sources that have troubled the coal industry in the last few years.
“For coal there’s more of a long-term story of displacement by cheaper natural gas and renewable energy,” said Luo.
That displacement became increasingly problematic for the industry after 2015, when electricity generation from natural gas rivaled that produced from coal for the first time. In 2016 and 2017 natural gas generated more electricity than coal. In 2017, for the first time, the U.S. exported more natural gas each month than it imported -- a potentially exciting data point for the Trump administration's "energy dominance" agenda.
Source: Bloomberg New Energy Finance
Still, according to BNEF, “renewable additions have dominated [the] U.S. power sector build in recent years.” Last year was the same, with renewables accounting for 62 percent, the largest portion, of new generating capacity. GTM Research data showed wind and solar adding a collective 65 percent of generating capacity in 2016 and 69 percent in 2015, after a more modest 52 percent in 2014.
Natural gas buildouts, after a boom in the early aughts, have remained relatively steady per BNEF data. But in 2017 the industry saw the highest capacity of gas builds -- 10.7 gigawatts -- since 2005. In the last 25 years, natural gas and clean energy, including hydropower, accounted for a full 93 percent of all new generation -- with coal and nuclear lagging behind.
Clean energy technology prices also continued to fall in 2017. According to BNEF’s data, U.S. solar power-purchase agreements bottomed out at just over $20 per megawatt-hour and wind in the blustery U.S. “wind belt” averaged $17 per megawatt-hour. BNEF notes that some regions this year broke through "the symbolic 'dollar-per-watt' threshold."
GTM Research noted that utility-scale fixed-tilt systems reached sub-$1 per watt prices in January of last year and the Department of Energy recognized the milestone in September of 2017. Data GTM Research released in November showed average fixed-tilt system price had inched back up over $1 per watt due to uncertainty surrounding the solar trade case. But prices are expected to decline again in the coming months.
Despite the fluctuations, the long-range trend of declining costs helped along the surge in build-outs of both wind and solar, even as installations dropped 19 percent from a record year in 2016.
Bloomberg New Energy Finance
While wind projects dominated renewable energy capacity builds between 2008 and 2012, solar has since emerged as the leader. In 2017 the solar industry installed 10.7 gigawatts to the wind industry’s 7.3 gigawatts.
BNEF attributes some of the slowdown in wind projects between 2016 and 2017 to developers playing the waiting game. They need to finish projects before 2020 to qualify for the Production Tax Credit, but expected future drops in equipment prices also mean it’s advantageous to wait in order to capitalize on that cost differential.
A similar situation befell utility-scale solar developers last year. A race to slide under the wire of the now-extended tax credit deadline has developers building back their pipelines. Meanwhile, small commercial, residential and utility-scale developers must cope with the added curveball of Section 201 tariffs that took effect this month.
It was a year of “policy turbulence,” according to BNEF, with tricky tax reform measures threatening tax equity for projects and tariffs throwing many developers for a loop. Luo said the Factbook doesn’t offer forward-looking statements, but that BNEF, from a broader perspective, expects clean energy builds to recover from the 2017 downturn.
GTM Research projects the solar industry will suffer less than some anticipated from the Trump administration tariff decision, and tax equity players insist they remain interested in clean energy investments. But the industry won’t fully understand the impacts of those policies until deeper into 2018.
A lack of strong federal leadership, though Luo said it prompted nervousness, also pushed other players to take leadership in clean energy.
“In an uncertain policy environment, we’ve seen other entities step up and take more initiative,” said Luo. “Federal level action aside, we have seen subnational actors step up on climate issues…and we have also seen a lot of corporate action on renewable energy procurement and energy efficiency.”
Despite the Trump administration’s recent decision to levy a 30 percent tariff on solar, we see tremendous opportunity ahead for the industry.
In the next year, the solar industry will develop, construct and finance $25 billion to $30 billion in solar assets. It will build 20 to 25 percent of the country’s new electricity capacity, and will continue to employ hundreds of thousands of people. The core drivers for this success are 1) public support; 2) rapid technological evolution that drives cost reduction and increased efficiency; and 3) significant and increasing support for the solar asset class by institutional investors.
By 2022, we fully expect solar to be the dominant source of new electricity generation in the United States. Here’s why.
America supports solar
Despite the current political headwinds, Americans overwhelmingly support renewable energy and believe climate change is real. As poll after poll demonstrates, we give priority to alternative energy sources, overwhelmingly support conservation of energy over extraction, and prioritize the protection of the environment over the amount of energy we produce -- now, more than ever.
This broad public support will be important in the next decade as we continue to invest in the infrastructure required to support a renewable grid (and we will need to). Depending on geography, solar and wind will scale to provide 35-40 percent of our country’s energy, and in real time, sometimes much more. As we’ve noted in the past, solar projects will do so at increasingly low costs, and will begin to compete head-on with natural gas.
Competition is fierce, but solar competes
Although natural-gas generation fell between 2016 and 2017 from 35 percent to 32 percent of total national electricity production, it remained the primary fuel for power generation for the second year in a row, surpassing coal (around 30 percent) in 2016. Natural gas sets the clearing price in most markets and therefore drives wholesale electricity prices. Natural-gas production is projected to continue to climb in to 90 bcf/day in 2019 as new pipelines transport gas from the Appalachian region and from Permian shale.
In the short term, this increased gas supply should depress electricity prices even as natural gas exports increase; the U.S. Energy Information Administration (EIA) forecasts that natural-gas prices for electric generators will fall to $3.26/mcf in 2019. However, long-term, there is less certainty. Natural gas discoveries have fallen to a 70-year low and have continued to fall consistently in the last five years. Recent studies also indicate that many gas operators have harvested the least expensive wells to optimize short-term revenue and profitability, leaving more expensive gas in the ground and potentially raising extraction prices with time.
Even assuming these concerns are unfounded, most current electricity projections estimate that on-peak wholesale electricity prices increase to $79-$85/MWh (depending on location) by 2039. This price does not include carbon or capacity value, which Wood Mackenzie, ABB and other firms generally do include. This is where utility-scale solar must deliver energy.
Solar is rising to this challenge. Solar power-purchase agreements continue to fall in price, and many PPAs executed in 2017 for assets to be delivered in 2018 and 2019 were executed at a levelized cost of energy below the price it takes to support a new natural-gas plant. See, for example, the GTM Research findings shown below.
We consistently see pricing in PJM, in the mid and low 3 cents, and solar, more than any other technology, has demonstrated significant cost reductions over time. We fully expect solar PPA pricing to be driven down further by competitive financing and technological innovation.
Investor demand for solar assets will increase, reducing the cost of capital
Ninety percent of the solar fleet constructed in the United States is financed, and the cost of capital (the costs of financing these assets) directly drives solar energy cost reductions. The cost of capital for solar projects will continue to decrease as investors overwhelmingly migrate into the asset class for a few reasons: 1) stocks are overvalued and investors are looking to diversify; 2) solar asset investments are non-correlated to other assets; 3) and long-dated; 4) U.S. solar assets are dollar-denominated; and 5) sovereign wealth funds, pension funds and insurance companies increasingly must comport with client demands, and internal mandates, to invest in more sustainable assets like solar.
As to the first point, the investment community must constantly adjust their portfolio based on risk and yield. Currently, investors are looking for yield just about anywhere they can find it because public equities and debt are overpriced. In fact, only at two points in the last 136 years have stocks been valued this high; once during the early dot-com bubble, and right before the crash of 1929. And it’s not just stocks where investors seem to be taking on undue risk. Yield spreads have compressed dramatically between stable debt (like U.S. Treasuries) and less stable debt, (like municipal bonds), indicating investor interest in high yield/risk bonds. This is one way the natural-gas boom was financed.
This demand is a function of low interest rates, limited supply of stocks, and a very large (and growing) number of investors -- think China. This historically low interest rate environment has pushed capital into stocks because yields are higher, driving a positive feedback loop where stock valuation increases more. Further, this environment enables corporations to buy back stock through debt -- and corporate indebtedness is at an all-time high -- to manage and drive earnings.
There is almost certainly cross-asset valuation conflation, which is to say that all stocks are rising because the market isn’t actually differentiating among fundamentals. This may be because the market doesn’t have the liberty to do so. The number of stocks has fallen by close to 50 percent in the last two decades, and there are now 70x as many indices (3.4 million) as there are actual stocks traded. And the number of people investing in U.S. stocks is growing, as Chinese investors pour money in.
Positive feedback loops spin themselves down as quickly as they spin themselves up (our industry has experienced this first-hand with YieldCos), and amid a bull market in everything, and concern about the future stability of this frothy market, investors are looking for non-correlated assets to help hedge against potential volatility so that even if the stock market or bond market implodes, they preserve their capital investment.
The volatility in all major stock markets globally in the last week (the worst since 2008) is just one indication of this uncertainty. Long-term yield curves are another. This is the third-longest bull market since World War II, and it will likely soon be the second-longest. Good things don’t last forever.
For investors looking for non-correlated alternative investments, hedge funds are one option, but not always a great one. There is also specific investor interest in long-dated assets that match liabilities for pension funds and insurance companies, and hedge against future inflation risk. There is also a global preference for dollar-denominated investments, specifically infrastructure, and especially renewable energy investments.
These fundamentals drive overwhelming interest in the renewable energy asset class, and will do so in the foreseeable future. Recent renewable funds by Blackstone, Global Infrastructure Partners' purchase of NRG’s renewable assets, Alaska Permanent's investment in Generate Capital, Temasek's (Singapore’s $275 billion national wealth fund) investment with Cypress Creek, Blackrock's $1.65 billion fund for its Global Renewable Power Fund II, and Sol Systems' and Nationwide Insurance Company’s infrastructure fund Helios are just a few examples.
Two challenges, of course, are rising interest rates and tax reform. Interest rates will rise in 2018, likely between 50 and 100 basis points. Expect the spread between U.S. Treasuries and interest rates for solar to shrink, but for rates to go up nonetheless. This will impact solar, but will also impact all infrastructure.
Further, because electricity rates generally rise with interest rates, and solar infrastructure is more valuable when energy rates are higher, solar may benefit in some ways from inflation since it has no fuel costs (like natural gas). In short, while rising interest rates pose challenges for all infrastructure, we expect solar to work through these challenges.
The recent tax legislation had three impacts on tax equity. First, it reduced the overall pool of tax capital because corporations have a 21 percent tax rate, down from 35, reducing tax liability. Second, it reduced the value of depreciation because depreciation directly offset the nominal value of income (not actual liability), and offsetting income to reduce taxes is only as valuable as the effective rate. Third, it includes BEAT provisions that limit investor appetite from some multinationals like Union Bank, Royal Bank of Scotland and others. The result is likely a 5-10 cent decrease in solar tax equity credit pricing in the short term, depending on the actual structure.
Longer-term, tax reform could mean a lower after-tax internal rate of return (although depreciation is accelerated, it is now worth about 60 percent of what it was prior to tax reform for most corporations) but a higher after-tax return on investment (investors pay less tax on their earnings from project ownership). Different investors prioritize these metrics, and prioritize them differently over time, so expect the tax equity market to take six to 12 months to stabilize. Sol Systems has worked proactively with its investor clients to reshape our tax equity product in advance of tax reform and is now deploying $100 million structured slightly differently.
Overall, we expect the blended unlevered after-tax IRR for utility solar projects to be around 6.50-6.75 percent. Tax efficiency, tax structuring and diversified outlooks on future electricity curves (post PPA) mean that this benchmark will vary dramatically for each investor, and investors should stress test their assumptions to ensure they understand where and how these economics work.
Overall, we expect this environment to support significant solar development, and the industry will continue to attract the billions in investment it needs to scale on terms that enable solar assets to outpace its competitors.
Solar costs will come down and efficiency will rise
United States module prices, hit hard by the recent Section 201 trade case, will likely experience sharp downward pressure in Q2 2018. This is because U.S. demand for modules is anemic at the moment. Most large solar projects have their modules, and Credit Suisse estimates that 6.5 gigawatts' worth of solar modules were warehoused in anticipation of the tariff.
But module supply is stable and growing. Massive Chinese demand, which now composes 40 percent (54 gigawatts) of the global market demand for solar, and a global trend toward manufacturing efficiency and automation across almost all industries, including solar, will continue to drive costs down and efficiency up.
Pricing for polysilicon (the raw commodity for most solar cells) was fairly stable through H2 2017 at around $16/kg. We expect those prices to fall to $13-$14/kg in the face of falling U.S. demand and increasing supply in 2018, as companies like Chinese-based GCL and Korean-based OCI ramp up production.
Transforming this raw product into actual solar cells efficiently is also critical in driving down costs. As recently as 2010, an average module utilized in excess of 7 grams/watt of polysilicon. In 2016, the industry utilized 4.8 grams/watt on average, and forecasts show that by 2020, it should achieve 3.6 grams/watt, a 25 percent decrease in raw material costs in just two years from now. Of course, polysilicon doesn’t solely drive economics, but we expect wafer production, manufacturing, backing, framing and wiring to become less expensive with global scale as well.
In addition to these cost reductions, solar module performance (measured in output per watt) will improve, further reducing the cost of solar energy. Many module manufacturers are transitioning old factories to produce higher-efficiency monocrystalline PERC technologies, which increase efficiency by 2-4 percent. A third of the global market is now (or soon will be) PERC. You can expect these same manufacturers to also integrate bifacial technology that enables cells to capture sunlight from the front and the back of a module, increasing yield by 10-15 percent.
Additionally, manufacturers are aggressively pursuing methods to increase the number of busbars within a module (an estimated 0.5 percent efficiency gain), and pursuing half-cut technologies that can lead to the similar outcomes.
We expect these changes to drive overall module production costs to approach 20 cents/watt by 2019. Critically, every 10-cent/watt reduction in the cost of modules delivered to port equates to a 13-13.5 cent/watt reduction in consumer costs, given the tariff. We fully expect modules to dip below 40 cents/watt in the United States again by Q3 2018 (including the 30 percent tariff), with a potential low-30-cent module in 2019.
Inverter technology is benefiting from global scale and innovation. Chinese manufacturers are entering the space aggressively. Prices, currently at 5-6 cents/watt, should come down 5 percent annually for the next few years at a minimum. These manufacturers are also leading the push to 1,500-volt architecture, which enables lower installed cost and higher efficiency at a system level.
Additionally, string inverters, previously common only for small commercial applications, have become the predominant solution for large commercial and small utility projects. Short-term U.S. solar tracker pricing (12-15 cents/watt for single-axis tracking) should follow suit, although recent steel price increases may prevent significant tracker price declines -- expect manufacturers like NEXTracker that utilize less steel to benefit.
None of these projections can be precise, but the general trend is correct. Prices are going down with time, and efficiency is going up, driving down the overall cost of solar energy. We expect to arrive at 95 cent/watt single-axis tracker utility-scale solar in 2019-2020 that is more efficient than solar today, resulting in 3 cent/kilowatt-hour utility-scale electricity, which will outcompete natural gas in many locations.
By 2020, solar will be the predominant source of new electricity generation capacity in the United States. But cheap electricity is only part of the equation.
Adaption is key: Time and location
Truly scaling renewables in the long term is not solely dependent upon price -- location and time are also crucial. As we price 25-year forward electricity curves for solar, regional analysis predicting solar production down to each hour in each day in each month is critical. Pouring enormous amounts of energy into the grid at one time, especially when customers don’t need it, is not sustainable. ERCOT is one example, where wind delivers energy into negative locational marginal price (LMP) price environments consistently.
That’s why the industry needs to continue to focus on shifting the time of day we produce solar and driving customer demand and simplifying how they secure solar.
We need to (and will) dramatically scale our deployment of energy storage with lithium-ion and flow batteries, as well as small-scale hydro. Energy storage will enable better ramping around generation, frequency regulation, and load shifting. This is why utilities like SDG&E are investing in storage, oil companies are investing in energy management companies, and companies like Siemens and AES have launched a joint venture around storage.
Without storage, solar cannot scale in the United States. Luckily, storage costs are expected to decline 10-20 percent annually for the next decade, and have fallen by 50 percent in just the last two years. We expect that most California solar projects will be accompanied by storage in 2020. We also expect that other types of storage, like flow batteries and pumped water storage, will be critical tools in managing load, as they are in California.
We must also continue to empower consumers to choose the energy they want. Otherwise they will secure their energy from utilities and incumbent sources of energy like coal and natural gas. Utilities are not necessarily incentivized to procure more solar through long-term PPAs unless their customers demand it. Sol Systems, along with other renewable energy development firms, will play an important role in helping companies like Microsoft, Apple, Amazon and Walmart achieve their goals of 100 percent renewables.
To serve these customers’ needs, we are focused on less complex solar energy products from remote solar projects to complement rooftop solar systems. This industry must transition complex PPAs and contracts for differences into simplified instruments that mimic normal electricity purchases so that customers can demand a 10-year block of power at a fixed or floating price that’s 50 percent solar, 30 percent wind, 20 percent gas. That is the future.
The path ahead for the solar industry is certainly complex, with fierce competition. But the industry is evolving (as it must) and the core strategic drivers support its evolution and growth. We believe there is tremendous opportunity in this transition, and we believe it is the right thing to do. Every generation carries its burdens -- this is certainly one of ours. Onward.
Yuri Horwitz is the co-founder and CEO of Sol Systems. This is an edited version of his 2018 CEO outlook.
Efforts to boost Egypt’s solar market have created a massive pipeline of work and attracted virtually every kind of PV ecosystem player -- except private investors.
Private-sector financiers remain skittish about Egypt’s potential despite the country hosting an award-winning solar complex that is set to become the largest in the world.
The Benban complex, near Aswan, this year bagged a Project Finance International Global Multilateral of the Year award after 29 projects, representing almost 1.5 gigawatts of capacity, received at least $1.8 billion in public financing.
Benban’s backers are a who’s-who of international and development finance bodies, including the International Finance Corporation, the African Development Bank, the Asian Infrastructure Investment Bank, the Arab Bank of Bahrain, CDC Group, the Europe Arab Bank and others.
In total, 16 development banks have provided debt, two other institutions have come through with equity and the World Bank’s Multilateral Investment Guarantee Agency has coughed up $210 million worth of political risk insurance to fund the complex.
The international funding effort has helped push Benban’s average overnight system costs below $900 per kilowatt, said Benjamin Attia, global solar markets analyst with GTM Research, while at the same time giving developers revenues that are not too shabby for the Middle East.
Benban projects are due to get $78 per megawatt-hour under a 25-year power-purchase agreement fixed as part of the second round of Egypt’s feed-in tariff (FIT) program. Unsurprisingly, there is plenty of interest from PV developers.
“So far, there are 25 project developers and sponsors from all over the world in negotiations and planning to build at Benban,” Attia said.
Egyptian PV Project Pipeline
Source: GTM Research
“The average project size is only 58 megawatts, as the procurement structure of the park allows many of the region’s established developers to be involved without oversized risk.”
At the same time, Egypt’s economy, now the second-largest in Africa, after Nigeria, is on a roll.
Under a three-year economic reform program giving Egypt access to an International Monetary Fund (IMF) Extended Fund Facility, the country has introduced changes expected to boost gross domestic product (GDP) to 4.8 percent this financial year, from 3.5 percent in 2016-2017.
“Egypt’s reform program is yielding encouraging results," said David Lipton, first deputy managing director and acting chair of the IMF's executive board, in a statement last December.
“The economy is showing welcome signs of stabilization, with GDP growth recovering, inflation moderating, fiscal consolidation remaining on track and international reserves reaching their highest level since 2011.”
All of this prompts the question: What has scared off private financiers and forced public money to step in to such a great extent at Benban? Part of the answer is most likely to be found in missteps made by the government in the first round of its FIT program.
In 2014, the Egyptian government announced plans to increase the share of renewables in the power mix from 2.1 percent to 20 percent by 2022 and 37 percent by 2035, potentially opening up a major opportunity for renewable energy investors.
But investors were alarmed when the Egyptian Minister of Electricity proposed that disputes for the first round of the FIT program should be tackled through the Cairo International Arbitration Centre.
And an even greater source of unease was the exchange rate: The Egyptian pound fell off a cliff when currency restrictions were lifted in 2016. That same year, Daily News Egypt reported that 19 companies had abandoned plans to build projects in the country.
Egyptian PV Developers
Source: GTM Research
The list included a large number of local developers as well as international players such as Enel Green Power. Perhaps spooked by the exodus, the Minister of Electricity introduced significant changes in the second round of the FIT program, unveiled in 2016.
The government tried to allay foreign-exchange fears by announcing that, for the second round of the FIT, 30 percent of the PV tariff would be based on a fixed rate of EGP 8.88 per dollar. The remainder is pegged to the dollar at the rate applicable at the time of payment.
Lawmakers also tweaked the arbitration arrangements, even if the revised plan still did not convince financiers, according to a February 2017 report by accounting firm KPMG.
“The Minister said that a compromise has been reached, in which arbitration will be governed by the rules of the Cairo Regional Centre for International Commercial Arbitration while the seat of the arbitration itself can take place offshore,” it noted.
“Investors have welcomed the move but remain uncertain about the practical implications of the requirement," according to KPMG.
The upshot is that private money will likely be observing developments at Benban with interest before committing to major investments in Egypt.
“Egypt, and its more than 2-gigawatt utility-scale project pipeline, is one of the Middle East and Africa's largest and most promising markets,” said Attia.
But, he added, “Despite the pipeline and strong support from risk-hungry development finance, developers do face significant political and market-based risks by building at Benban."
The anticipated fallout from the Section 201 solar trade case is now officially underway.
Three Canadian solar panel manufacturers launched a lawsuit against the Trump administration at the United States Court of International Trade last week, claiming the new global safeguard measures violate the Trade Act of 1974 and the NAFTA Implementation Act. The complaint was filed on February 7 -- the same day President Trump’s tariff proclamation took effect.
The European Union also filed a request for consultations with the World Trade Organization that day, following similar steps taken by China, Taiwan and South Korea. Singapore subsequently filed for consultation at the WTO on February 9. Bilateral consultations between the parties are the first stage of formal dispute resolution.
Legal actions follow Trump’s decision in the Section 201 case petitioned by U.S.-based crystalline silicon (CSPV) solar manufacturers Suniva and SolarWorld Americas. In a proclamation issued January 22, Trump decided to impose a 30 percent tariff on imported CSPV solar cells and modules -- set to decline by 5 percentage points per year over the four-year tariff period. The ruling also includes a tariff-free carve-out for the first 2.5 gigawatts of solar cells imported each year.
Several developing nations, listed as Generalized System of Preferences beneficiary countries, were exempt from the tariffs because they currently account for a small portion of U.S. solar imports (although that could soon change).
In recommendations submitted to President Trump by the U.S. International Trade Commission (ITC) last fall, three of the four commissioners determined that imports from Canada are not harmful to U.S. producers. The fourth commissioner did not explicitly address Canada in her proposal. Despite the negative findings, Trump’s ruling did not exempt companies from north of the border.
Similarly, all ITC commissioners exempt U.S. free trade partner Singapore (home to solar manufacturer REC Group) in their recommendations. However, Singapore was not exempt in Trump’s decision.
The Canadian lawsuit -- brought by Silfab Solar, Heliene and Canada Solar Solutions -- states that the president’s proclamation is “unlawful as applied to plaintiffs, and inflicts grave and irreversible harms on them.” They are now seeking an injunction prohibiting the enforcement of new tariffs against them.
Canadian manufacturers face layoffs and plant closures
The case argues that the U.S. violated Sections 201 and 203 of the Trade Act by imposing safeguard measures on Canada without the required recommendation from the ITC. The plaintiffs also claim the U.S. violated Sections 311 and 312 of the NAFTA Act because, as the ITC determined, Canada does not “account for a substantial share of total imports” or “contribute importantly to the serious injury, or threat thereof, caused by imports.”
The plaintiffs state that American-based solar manufacturers account for less than 5 percent of CSPV cells and modules used in the U.S., while Canadian manufacturers account for only 2 percent.
It’s worth noting Trump decided Generalized System of Preference countries are exempt from the tariffs until they reach 3 percent of U.S. CSPV cell and module imports. If the 2 percent figure cited by Canadian manufacturers is correct, it would seem to represent a reasonable level by the administration’s own standards.
But while the effect on the U.S. solar market is minimal, these exports represent the “bulk” of the Canadian solar manufacturing industry, according to a plaintiff memo. Because the plaintiffs produce CSPV modules, and not cells, Canadian solar products are immediately subject to tariffs.
“That tariff will make it prohibitively expensive for Plaintiffs to import CSPV modules from Canada to the United States, and within weeks, it will compel Plaintiffs to terminate employees, close manufacturing facilities, forego business opportunities, lose sales, and -- in several cases -- cease business entirely,” the memo states.
The Court of International Trade is a special court based in New York City with a very experienced group of judges looking to answer a very specific set of legal questions that differ from the WTO, said Allan Marks, energy and project finance attorney at law firm Milbank, Tweed, Hadley & McCloy.
“They’re looking at whether these tariffs, in particular as applied to Canada, comply with U.S. law,” said Marks, who teaches energy trade issues as an adjunct professor at UC Berkeley. “The WTO is looking at whether U.S. government safeguard measures, broadly applied, comply with international law. Those are different questions and the standards are slightly different.”
Action at the court level is also likely to be much faster than at the WTO level, which could take 18 months or more. In the Canadian company case, the U.S. government will have to respond within the coming weeks. The administration could choose to act through the courts, or the Office of the U.S. Trade Representative could modify the tariff order to exempt Canada, which would render the case moot. Marks noted the USTR has the authority to change or rescind the tariff at any point.
China threatens retaliatory measures
At the WTO, there are several different courses of action countries can take to challenge the tariffs. One route is to question whether or not the sudden increase in imports affecting U.S. companies was “unforeseen.” The Trump administration prepared for this challenge by requesting the ITC submit a supplemental report.
However, countries can also challenge whether the ITC did a good job in making its determination in the global safeguard case, or they can take issue with how the safeguard measures were implemented. To that end, several complaints submitted to the WTO center on the need for proper “consultation” and “compensation” between trading partners, in accordance with international law.
In a global safeguards case, trade authorities only have to find injury against their domestic industry -- they don’t have to prove specific countries have broken the rules, as is required in an anti-dumping and countervailing duties case. As part of the Section 201 process, the U.S. needs to discuss its tariff decision with affected countries prior to applying the safeguard measures, said Marks.
“If the WTO finds that our injury finding wasn’t thoroughly done or it didn’t allow proper time for compensation and consultation, then retaliatory compensation would be allowed under international trade rules,” he said.
Retaliatory measures played a role in convincing the U.S. government to withdraw tariffs on imported steel products in a Section 201 case decided in 2002. Retaliation is intentionally designed to create political pressure, and is often targeted at unrelated industries, said Marks.
Chinese officials have already confirmed they’re launching an investigation into whether about $1 billion of U.S. sorghum exports were being dumped or receiving subsidies -- a move widely viewed as a response to the Trump administration’s protectionist trade policies, The New York Times reports. According to Bloomberg, China is also looking to impose trade restrictions on soybeans imported from the U.S.
“If you’re smart, you [retaliate] on things being exported from districts of congressional leaders,” Marks said, assuming the WTO gives the go-ahead. “You could see [countries] imposing it on coal exports. I’ve also heard whiskey or bourbon mentioned. In the past, it was North Carolina textiles. If Paul Ryan is still Speaker of the House, exporting Wisconsin cheese could get harder. Whatever it’s going to be, it’s going to be something that moves the needle politically.”
The Trump administration is likely also thinking about the political dynamics.
“I don’t think they want to hurt the U.S. economy or even renewable energy; I think they just want to placate their base,” Marks said.
“They want to find a way to thread the needle that meets their political goals,” he surmised. “Whether or not it works is another question.”
As challenges move forward at the WTO and the New York court, individual companies have until the end of the month to request an exclusion from the new tariffs. With American jobs on the line, this decision also comes with political implications.
Arizona Public Service will add a 50-megawatt battery system to its fleet for storing solar energy to use during evening peak hours.
The regulated utility revealed Monday that it had signed a 15-year power-purchase agreement with First Solar for the dispatchable solar power. The storage system will be paired with a new 65-megawatt solar plant in western Maricopa County and should be up and running in 2021.
This represents a significant escalation of storage activity for APS, which has developed storage systems at the single-digit-megawatt scale. Fifty megawatts would overpower any battery system in the U.S. today, although Fluence is slated bring a 100-megawatt system online in 2021.
The joint system suggests a new paradigm for solar-rich markets: the solar peak power plant.
“When you look at the desert Southwest, you’re already seeing the growing pains of having so much solar on the system and having to curtail,” said Brad Albert, APS vice president of resource management. “This [project] is a necessary evolution of how we deploy solar energy and take advantage of what we have in abundance in the Southwest.”
The hours that really matter
APS didn’t set out looking for storage, per se.
This project emerged from a request for proposal that started a year ago. It was open to any technology, but the bids had to deliver power between 3 p.m. and 8 p.m. in the summertime.
Those are the peak hours that drive much of the new capacity investments APS will have to make in coming decades, even as the abundance of midday solar power grows.
Bids included conventional renewables, standalone batteries and natural-gas peaking plants, but First Solar’s hybrid solar-storage proposal won out.
The solar plant will charge up the battery during the day and deliver power during the first few hours of the peak window, until the sun sets. That also allows the whole project to qualify for the federal Investment Tax Credit.
Then the battery will kick in and discharge stored power through the rest of the window. It will come with 135 megawatt-hours, providing a bit less than 3 hours' worth of duration at the full 50-megawatt capacity level.
“For anything outside those hours of 3 p.m. to 8 p.m., APS is not buying that,” Albert said. First Solar technically has free rein to play with other revenue streams in the off-hours, provided it can ensure capacity to deliver its obligation when the rush hour starts.
Albert declined to disclose pricing details, but it’s clear from the timing component that this is a structural advance for solar and storage PPAs.
“We have not seen any like that,” Albert confirmed.
New era for storage
This project entails several notable developments for the solar-plus-storage market.
It is First Solar’s first publicly announced storage project. Recall that the thin-film specialist and largest U.S. solar developer confirmed to GTM last year that it was actively bidding storage alongside new solar.
"We can deliver energy comparable to or less expensively than a new-build fossil fuel plant,” said Scott Rackey, head of PV-plus-storage development, at the time.
Now the company has made good on that promise, beating out gas peakers in reality, not just in theory. First Solar expects this project model to become “very common in many of our markets,” spokesperson Steve Krum said in an email.
That’s crucial for the continued growth of solar power in sunny regions that have more than they need at mid-day. Transforming solar power into a dispatchable capacity resource could allow utilities to reduce reliance on gas peaker plants, reducing costs and carbon emissions to keep the lights on.
Arizona could adopt that model wholesale: Commissioner Andy Tobin of the Arizona Corporation Commission recently proposed an ambitious plan that would raise the state’s clean energy share to 80 percent by leveraging storage for clean peak power.
The First Solar bid came in well before that plan was announced, but offers a data point that suggests this model is cost-effective even before a regulatory driver comes into effect.
The project also showcases an even ratio of solar to storage capacity.
Historically, paired systems had relatively small storage capacity, because battery costs would weigh down project economics. The groundbreaking Tucson Electric Power hybrid PPA got to $45 per megawatt-hour with 100 megawatts of solar and 30 megawatts of 4-hour storage.
The new APS project has stepped a bit closer to 1-to-1. That reflects cheaper battery costs making larger systems tenable, but it also means the value proposition is changing. Storage is no longer a nice add-on to a solar project; it played the key role in winning this bid.