No state has led the energy transition like California has. While other states may have higher portions of wind in their electricity mix, at full sun the output of solar panels in California rivals that of Texas wind power. It has often been the first state in the nation to pass policies that drive the move to renewable energy and electrification, and these policies are regularly imitated elsewhere. As a result California has been a pioneer for a range of clean energy technologies.

California has also been the first to experience the challenges of the transition. The state is famous for its “duck curve,” where solar floods the grid in mid-day and forces other sources of power to ramp quickly in the evening to meet demand when the sun goes down. The responses to this and other challenges in California have taken many forms—including an emphasis on demand response and using imports and gas plants more flexibly. It has also meant a lot of batteries.

California has long been the nation’s leading market for both battery storage, and “solar plus storage” solutions. But PV Intel’s examination of the interconnection queue from California’s grid operator shows that in terms of large-scale projects, this transformation is reaching another stage. California is on the cusp of no longer being a solar market where batteries are being added—instead, it is becoming a battery market that (sometimes) includes solar.

Rapid battery growth

The numbers are stark: at the end of January the California Independent System Operator (CAISO) queue included a total of 282 projects with a solar component (including various hybrids of solar+storage & solar+wind), compared to 533 projects with a battery component. The raw capacities tell the same story: At 135 gigawatts (GW) the capacity of battery projects is 78% higher than the 76 GW of solar projects.

These numbers underscore the very rapid growth of battery technology in California. According to the American Clean Power Association, California had only 256 MW of utility-scale batteries before 2020, but had reached 2.1 GW by the end of 2021—an 8x increase.

In fact, few standalone solar projects are being proposed anymore. We found only 23 solar projects in the queue that don’t include batteries, meaning that more than 90% of solar projects that have applied for interconnection have a battery component.

This is in stark contrast to other grid operator queues, where solar + storage projects are still niche. The most advanced may be ISO-New England, where in January 30% of total active solar projects were paired with batteries. In Texas (ERCOT) there is also substantial battery capacity in the interconnection queue, but it is not clear how much is paired with solar.

Chocolate and Peanut Butter—or Just Peanut Butter?

When pairing generation, solar and batteries are still the main choice in California, as the “chocolate and peanut butter” combination of the energy transition. The 256 solar + storage projects representing 72 gigawatts of solar and 64 gigawatts of batteries make up the vast majority of hybrid projects in the CAISO queue, with only a handful of wind + storage or solar + wind projects. 

Another notable factor is the size of the batteries. Gone are the days when small batteries were added to solar projects. The average ratio of battery capacity to solar capacity was .89. Nor are the standalone battery projects small; the average capacity of a standalone battery project in the CAISO queue is 248 MW.

In terms of projects with interconnection agreements—a subset of projects which are more likely to be completed and to come online more quickly—solar + storage is still dominant.  76 solar + storage projects are approved for interconnection, as opposed to 31 standalone battery projects. 

But the large majority of this capacity is scheduled to come online in 2022 and 2023. This means that with new projects getting approved, as early as 2024 the market could flip to standalone battery projects being dominant.

The Era of the Battery

This is not to imply that all the energy storage projects that will be built are batteries. Notably there is a 500 MW pumped hydroelectric project in California that has an interconnection agreement and is scheduled to come online in 2028; the long-term plans of California utilities show 1 GW of “long-duration storage,” which implications that this will be pumped hydro.

But the capacities of pumped hydro and other novel storage technologies planned are dwarfed by batteries, with lithium-ion continuing to dominate the market. And as a recent solicitation by California’s community choice aggregators shows, lithium-ion batteries are even being chosen for long-duration storage needs.

California will need all the energy storage it can get its hands on; a recent analysis suggests that the state needs 37 GW of batteries over the next 20 years, as well as 53.2 GW of utility-scale solar. But the projects that are being planned put the state well on its way; as 23.5 GW of large-scale battery projects already have interconnection agreements. The next few years will see whether or not California’s battery market can overcome supply chain challenges and stand on its own. But the path forward is clear. In California, the energy transition has entered a new era: the era of the battery. 

Jason O’Leary, Principal Analyst at pv-intel.com, contributed to this article with data analysis and data visualization.

If you want to get an idea of where the solar market in the United States is headed, a good place to start is the process every developer has to go through to plug their project into the grid. Every grid operator has an interconnection queue and you can learn a lot about where the market is going by looking at this public data.

On January 1, 2019, John Weaver and I published the first “Solar Tsunami” article in pv magazine USA. At the time we were really excited about the 139 GWac of solar that we found in the queues of six of the nation’s seven big grid operators. Even if only a small portion of it would get built, it was so much solar!

Growing 3x in 3 Years

But 139 GWac is chicken scratch by comparison to what we found at the beginning of this year. In our latest analysis, we found no less than 639 GWac of large-scale solar projects in the queues of the seven wholesale power markets, plus TVA, the Bonneville Power Administration, and two of the nation’s largest investor-owned utilities (Florida Power & Light and Southern Company). If we limit that to the queues we tracked in 2019, it still shows a more than 3x increase.

It’s important to keep in mind that this is not even all the solar projects being planned. The 639 GWac number does not include projects in the queues of dozens of other utilities across the South and Mountain West, or the smaller projects, like rooftop solar, that connect to the distribution grid. And these can add up; in California, distributed solar accounts for around 1/3 of the total capacity online.

But to understand these numbers, you have to also keep in mind that putting a project in the queue does not necessarily mean that it will ever get built. Also, there are plenty of speculative projects. ISO-New England estimates that only 30% of the capacity in its interconnection queue gets built; Lawrence Berkeley National Laboratory, in a very detailed 2021 report, estimates that only 16% of the solar projects in grid operator queues have been completed.

Looking only at projects that have gotten approval to connect to the grid gets you closer to what might actually see built in the near term—and this still shows very big numbers. Across the queues tracked in this article, 82GWac of solar projects had been granted interconnection approval.

By comparison, the U.S. Department of Energy estimates that 15.5GWac of solar came online in the United States in 2021, and predicts 21.5GW in 2022.

The capacity of projects with interconnection approval is also higher than the amount the Federal Energy Regulatory Commission (FERC) expects over the next three years. In FERC’s latest update, the Commission found 53GWac of solar projects with a “high probability” of getting built—far more than any other resource.

FERC doesn’t share its methodology of how it determines which projects are most likely to get built. Our team is currently developing our own methodologies so that we can offer more specific numbers in the future.

To Texas, and the Midwest

Digging into the massive volume waiting to be built also tells the story of how solar is moving beyond California to conquer the entire United States. While we don’t yet have final data, 2021 looks like the first year when Texas installed more solar than California. Even more is coming. The 25GWac of solar projects in the Electric Reliability Council of Texas (ERCOT) grid that hold interconnection agreements exceeds the California Independent System Operator’s (CAISO) 21 GW.

And the story goes beyond Texas. The Midwest and Mid-Atlantic are the new hot spots for solar development; the Midcontinent System Operator (MISO) and PJM Interconnection together have more than 26GW of solar projects with interconnection agreements.

Looking at all the active projects in the queue shows an even bigger geographical shift. PJM, the nation’s largest wholesale market, has the largest capacity in its queue and nearly 2x the capacity in ERCOT. And after these two and CAISO, MISO is in third place with 87GW. 

It is important to not infer too much into the numbers of active projects, as speculative projects affect the overall size of queues, and there will be different amounts from queue to queue. Regardless, the sheer volume of projects—with nearly 2,000 active solar projects in PJM’s queue—suggests that these regions could be the next to take off in a big way.

Batteries, Batteries, and More Batteries
The second major trend documented by these queues is the explosion of the battery storage market, and in particular solar + storage. As happened with solar, California is in the lead. Not only does CAISO represent more than 1/3 of the 329GWac of battery projects (including those paired with solar*) that we found in various queues, but more importantly CAISO dominates projects with interconnection agreements. Of the 27GW of battery projects with interconnection agreements, 21 GW were in CAISO’s queue.

The only other region showing large-scale near-term battery deployment is Texas, with 4GWac of projects with interconnection agreements in ERCOT. For the other grid operators there may be many battery projects but few are ready to build; of the 78GW of battery projects in the PJM queue, only 203MW were approved for interconnection. 

The biggest factor to consider here is that it takes time to move through the interconnection process. Many of these battery projects are likely simply too new to show up in the list of projects with approvals. There is also the matter that grid operators are struggling with the large numbers of solar, wind, and battery projects that are being proposed. MISO has already had to make major changes to its queue process to deal with this volume, and other grid operators are also considering doing so.

Another trend that we’re seeing is solar being paired with batteries, but this varies widely by queue. In CAISO, more than 90% of the solar projects in the queue include battery storage, whereas in ISO-New England it is around one quarter and in PJM it is 16%.

Over time, as penetrations of solar increase and policies catch up, we expect to see solar increasingly paired with energy storage, as the peanut butter and chocolate combination of the energy transition. But if California is any indication, as the market evolves there will also be many standalone energy storage projects; in California’s queue there were 270.

That’s all for the January 2022 edition of Solar Tsunami. Stay tuned, as we will be publishing another look at the queues in April, featuring expanded research to bring in more data from more queues.

Jason O’Leary, of pv-intel.com, contributed to this article with data collection, sorting, and graphics creation.

With the U.S. Investment Tax Credit (ITC) set to phase down at the end of this year, the U.S. solar market is seeing not just a boom in construction to qualify for the full 30% ITC, but also a stockpiling of PV modules under the “safe harbor” provision of the policy.

This has been documented by the latest information from the U.S. Department of Energy’s Energy Information Administration (EIA). EIA reports that 1.53 GW of PV modules were shipped in the month of September, more than double the volume a year ago and higher than in any month since at least 2016. This included 1.30 GW of imports.

According to EIA’s data 13.5 GW of modules were shipped during the full year 2016, but it has not released monthly shipment levels for that year, making a comparison impossible.

Many of these modules are likely bound for projects under construction. Wood Mackenzie has reported that at the end of Q2 there were 37.9 GW of utility-scale solar projects under construction in the United States – the highest level to date – and it is unlikely that construction has slowed down since then.

Part of the reason is the “commence construction” provision of the ITC, under which solar projects can quality for the full 30% ITC if they start physical work by the end of the year. Alternately, under the current IRS guidance developers can lock in the 30% ITC through the “safe harbor” provision, by paying for 5% or more of the cost of a project.

This does not apply to individuals, only businesses, meaning that homeowners buying PV systems outright still must complete work by the end of the year to get the 30% ITC. However, it does apply to third-party solar companies, and modules represent more than 5% of total project costs.

This means that there has been a rush to “safe harbor” modules, with Sunrun alone estimating that it will safe harbor 500 MW, and SunPower partnering with Hannon Armstrong to safe harbor 200 MW of projects.

U.S. module assembly on the rise

And while this included 1.3 GW of imports, there were also 230 MW of modules which were either exported by U.S. companies, shipped within the United States, or sold to U.S. contract manufacturers for resale. It is impossible to know how much of which, as EIA has redacted that data.

However, with manufacturers reporting year-long lead times to order modules, there is clearly a market for the new module assembly which has sprung up after the Section 201 tariffs and Republican tax cuts.

First Solar put online its 1.3 GW solar factory in Lake Township, Ohio last month, and while that one is still ramping Hanwha Q Cells’ 1.7 GW module factory in northern Georgia has been up and running for some time. When you add in the 500 MW LG factory in Alabama and the 400 MW JinkoSolar factory in Florida, the United States has much more module assembly than it has seen in some time.

Even this does not appear to have dampened the market, and EIA is reporting that the average price of PV modules shipped in September rose to $0.41 per watt – the highest level since January.

Hanwha Q Cells’ patent infringement suit against JinkoSolar, LONGi and REC Group is about to reach its final phase, and it isn’t looking good for the Korean-German PV maker.

In April the U.S. International Trade Commission launched an investigation into claims by Hanwha that the three Asian solar manufacturers had infringed on the patents behind its particular recipe for passivated emitter and rear cell (PERC) technology. Hanwha has asked trade authorities to keep the three companies’ PERC-based products out of the U.S. market as a consequence.

However, on Tuesday Administrative Law Judge MaryJoan McNamara issued a ruling staying indefinitely both an evidentiary hearing and the rest of the procedural schedule. She also stated that within two weeks, an initial determination would be made granting the respondents’ motions for summary determination of non-infringement.

Hanwha sent a statement to pv magazine indicating that it plans to “immediately appeal” the anticipated summary determination. It also notes that these anticipated rulings will not affect its cases against the three manufacturers in Australia and Germany.

LONGi and Jinko have stated that they feel the claims are without merit, with LONGi citing specific aspects of the technology and process.

Sunrun continues to carry the torch of third-party solar, as not only the largest third-party solar company but the largest residential solar company overall. The 107 MW that the company deployed is nearly double that of its nearest competitor, Vivint (65 MW), and a 7% year-over-year increase.

This was at the low end of the company’s guidance, and Sunrun referenced labor shortages in installation and its sales force on the company’s results call. But these are likely short-term issues, and there are deeper causes for concern about the company’s growth path. Like Vivint, Sunrun is seeing increasingly higher sales and marketing costs, which rose slightly to $0.81 per watt this quarter.

This is 10% higher than a year ago, and these costs have been rising all year. Thanks mostly to the continued decline in installation costs and a drop in general and administrative costs, the company is able to claim a slightly lower “creation cost”, but as in previous quarters this also includes around a quarter per watt in platform services revenue.

Sunrun attributes this quarter’s sales and market costs to a higher mix of direct business, but did not comment on the larger trend that the third-party solar industry writ large is facing.

Along with this, the company’s profitability appears to be flagging. Revenues rose only 5% year-over-year to $215 million, despite the aforementioned larger share of direct sales. Operating income was negative, as it consistently is for third-party solar providers, with a $60 million loss. Overall, the company’s net loss was $142 million for the quarter.

Like a squirrel preparing for winter, Sunrun is still accumulating value in its assets. However, this rose only $9 million this quarter to $1.438 billion. This metric has grown only 3.5% from the third quarter of 2018, suggesting that the value creation in its pool of assets – the main thing that a third-party solar company does – is slowing.

Overall, it is notable that while Sunrun’s quarterly installs continue to grow at a higher rate than the overall market, neither revenues or retained value is matching this rate.

That being said, the company is certainly not in any near-term danger. The first thing that a third-party solar company must do is to amass enough cash to keep deploying, and Sunrun notes that it has debt and tax equity lined up through Q4 of next year, as well as increasing its cash position by $69 million over the last year to a $373 million.

Hope for the future

Sunrun also has several factors pulling in its favor. First off, the company notes that it expects to “safe harbor” around 500 MW of PV systems under the 30% federal Investment Tax Credit (ITC) by the end of the year. And Q4 installs are expected to be a nice bump to 115-118 MW, labor shortage or no.

Another factor working in its favor is the rising demand for pairing solar and storage, and CEO Lynn Jurich wasted no time on the company’s results call noting the demand for its Brightbox system that has risen in the wake of utilities proactively shutting off power to fire-prone regions of California. Sunrun is currently reporting very high attachment rates of solar + storage in the state, which is still by far the biggest residential market.

Sunrun is clearly looking towards Brightbox, and the sale of not only this solution to homeowners but also the providing of grid services as its future. While it struggles to eke additional value out of solar under a situation of rising sales costs, these new revenues may be the future.

Eight years ago, the solar industry was focused on manufacturing. Crystalline silicon was under threat from improving thin-film products, including Copper Indium Gallium diSelenide (CIGS) which was accelerating through efficiency records.

But after a rapid ramp-out of Chinese capacity, that story came to an end. Low-cost crystalline silicon crushed nearly all of its thin-film rivals, and the resulting evisceration of margins meant that low-cost PERC was the only cell-level technology innovation that most companies invested in for many years.

But as capital not supplied by the Chinese government dried up, innovation went downstream. New third-party solar models brought residential solar to a wider range of homeowners. New residential solar empires were built on this model, including SolarCity, Sunrun and Vivint.

This model has since been eclipsed by newer, more sophisticated and flexible loan products, and even more significantly behind-the-meter solar is joining with battery storage to evolve into part of both a home energy ecosystem and increasingly a contributor to grid reliability.

It is within this larger context that today’s announcement from SunPower can be understood, as SunPower has followed these trends by evolving from not only from a manufacturer into a downstream solar company, but through its dealer network the second-largest residential solar company in the United States by megawatts deployed.

Along with this size is increasing sophistication, and an increasingly wider array of products to differentiate its business. These include its Equinox and Helix integrated platforms for the residential and commercial and industrial businesses, which can include battery storage, and even a new tool for visualizing residential installations.

The split

Today SunPower announced that it will be spinning off the high-efficiency manufacturing business which the company was founded on into a new company, Maxeon solar, named after its interdigitated back contact (IBC) cell product.

Maxeon products have traditionally led the industry as the highest-efficiency products available for most applications other than satellites. This evolution continues with the company working a new Maxeon 6 after the U.S. launch of its A-Series modules based on its Maxeon 5 (NGT) cells earlier this year.

Tainjin Zhonghouan Semiconductor (TZS) pouring $298 million into the new company, which SunPower says will enable both a scaling of Maxeon 5 – including faster conversion of Maxeon 2 lines to Maxeon 5, as well as development of Maxeon 6.

TZS is already one of the world’s largest wafer makers with 40 GW of capacity, as one of the two big Chinese monocrystalline wafer makers (LONGi is the other) whose rapid growth is enabling monocrystalline silicon to eclipse multicrystalline as the main cell technology.

The relationship between TZS and SunPower is not new, and the two companies have been working together for some time including in a joint venture for a multi-gigawatt Chinese factory to make SunPower’s shingled P-series product. Maxeon will keep a 20% stake in this venture.

And while continuing to innovate on Maxeon cells, Maxeon also plans to expand its manufacturing capacity to make the lower-cost P-Series.

This does not mean that SunPower will be entirely free of manufacturing or R&D. The company will retain the P-Series module factory in Hillsboro, Oregon. It will also keep its SIlicon Valley-based R&D, while Maxeon gets the overseas R&D capabilities, and the two companies plan to partner on development of new products.

Under the current deal, which still must receive regulator approval, existing SunPower shareholders will keep SunPower shares and receive a 71% stake in the Maxeon, with TZS holding the balance. The company will also keep a multi-year, exclusive supply agreement with SunPower.

Jeff Waters, who currently serves as CEO of SunPower Technologies, will take over as CEO of Maxeon. The company will be headquartered in Singapore, and plans to launch as a publicly traded company the NASDAQ after closing of the split.

The new SunPower

With its manufacturing spun off, the new SunPower is free to focus on what has increasingly occupied its time, which is its downstream presence. SunPower has built a powerful presence through dealer network, which includes companies who only sell and install SunPower products.

The megawatts sold through this network make SunPower the 2nd-largest company in the U.S. residential solar space, second only to Sunrun. Unlike Sunrun, SunPower also has a large presence in the nation’s commercial and industrial market.

But this is just the beginning. SunPower estimates that it has a 50% market share in the new homes market, and contracts with 18 of the top 20 builders in California. “We are ideally positioned to lead the California new homes mandate in 2020,” notes Werner.

And SunPower’s innovation is not limited to its cell and module work. “We are increasingly living in a digital world,” notes SunPower CEO Tom Werner, emphasizing the company’s software innovations, such as its new Design Studio.

SunPower is one of only two companies known to pv magazine to have won contracts to supply capacity to U.S. grid operators from behind-the-meter solar, and this may be just the beginning.

Werner says that SunPower has an “opportunity to capitalize in the growing energy services market”, and says that the company plans to offer ancillary services as well as capacity from behind-the-meter resources. This of course will be enabled by increasing deployment of solar plus storage.

The deal has received the blessing of French oil company Total, SunPower’s main shareholder. “We support this transaction which will bring clarity and focus for both entities on their respective activities,” stated Total CEO Patrick Pouyanné. Total will remain a shareholder of both companies.

The most central mission of any utility is to supply reliable power, and that’s the one thing that Pacific Gas & Electric Company (PG&E) has shown that it can’t – or won’t do. Starting last month, the bankrupt utility has been proactively shutting off the power in waves to hundreds of thousands of its customers, with outages sometimes lasting as long as days.

But PG&E isn’t the only actor in Northern California’s power sector. The region’s community choice aggregators (CCAs) have taken a state-level requirement to secure resources to keep the lights on, and turned it into a solicitation for energy storage to provide resiliency in their communities.

Yesterday three CCAs in the San Francisco Bay Area – East Bay Community Energy, Silicon Valley Energy and Peninsula Clean Energy, along with Silicon Valley Power (SVP), the municipal utility for the city of Santa Clara, filed a joint solicitation seeking a total of 32.7 MW of batteries. These systems can be paired with existing or new PV systems.

To be clear, these entities need to procure resources to meet state-requirements designed to ensure that they have enough local resources to meet demand, called resource adequacy (RA). And they’ve been struggling to do this; the three CCAs are among 19 that asked state regulators a week ago for a waiver on their RA requirements, arguing that the market for eligible resources is “seriously constrained”.

But these public power entities are turning this into an opportunity. There’s nothing in the RA requirements that say that you need to be able to form microgrids, but that’s what these organizations are doing. Among a list of the types of resources that are eligible under the new solicitation is the following requirement:

All systems must be able to island from the grid to provide resilience to participating customers

And while RA can be met outside a utility or CCA’s service area, the four public power entities have expressed a definite preference for projects in their areas – which is likely so that if they do need to island, they can do so for the benefit of their customers, not somewhere else.

The load serving entities will not automatically exclude proposals that include geographies outside of its service area, provided that the RA capacity originating outside of its service territory is clearly indicated, but the load serving entities also reserve the right to exclude any of these non-conforming bids from consideration.

It’s notable that some of the Public Safety Power Shutoffs (PSPS) that PG&E has imposed over the past month affect some of the customers of the three CCAs and SVP, particularly those of East Bay Community Energy.

#PSPS map of impacted area of #AlamedaCounty (click to expand): PG&E expects to begin turning off pwr in some areas early Wed, just after midnight. The pwr will be turned off to communities in stages, depending on local timing of the severe wind conditions https://t.co/aU1BjUifZS pic.twitter.com/Rjie76rczT

— PG&E (@PGE4Me) October 9, 2019

The three CCAs are trying to get at least 3-4 MW by September 2020, and two of the three would like to get the rest online by June 2021. Most of the entities are also requiring that some of these batteries be located in disadvantaged communities.

Solar is upending the way that we approach power markets. As one example, for the last century of so, the construction of new power plants in the United States has been driven by rising peak demand peaks, because what is typically needed at the system level is to meet the level of demand seen on a hot summer day when air conditioners and fans are all on.

And while this still set the level of overall capacity needed, something new is happening. In places with high penetrations of behind-the-meter solar, peak summer demand on the bulk power system is going down, not up.

One of the places where this is most visible may surprise you. The windy shores of Cape Cod are not the first place most people think of when they think of solar, but the nearly 3 GWac that has been installed in the six-state region has already reversed the upward trend of the summer peak.

The latest 10-year forecast issued by the New England Independent Operator (ISO-NE) shows that while gross demand is still rising, solar and energy efficiency are driving these peaks down. The organization estimates that New England’s installed solar capacity is going to more than double over the next decade to 6.7 GWac, and that this is going to drive down the summer peak by around 600-900 MW.

The uncertainty in these numbers comes from the fact that no one, including the grid operator, knows exactly how high electric demand will rise in any given summer. But even in its “90/10” load projection, ISO-NE shows summer peak load falling from from 27.2 GW to 26.6 GW from 2019 to 2028.

Incidentally, ISO-NE also sees overall power demand falling due to solar and efficiency. But while this 4% fall may be larger in percentage terms, it may not be as consequential. As explained in the report:

Net peak demand, thus, is not a key driver of new infrastructure needs over the 10-year planning horizon. Growth of demand over the longer term seems likely, however, with additional electrification of transportation and the use of efficient heat pumps replacing fossil systems for providing heating and cooling.

If this were Texas or California, I would say that this is great news for power prices, but in New England these spike in the winter, not the summer. What this does mean is that under the current scenario, the region doesn’t need as many new conventional power plants to keep its reverse margin intact, even with retirements of existing units.

Need for new services

But that doesn’t mean that there aren’t needs. Specifically, ISO-NE says that both behind-the-meter and large-scale solar are creating needs for regulation, ramping, reserves, and voltage control. It states these can be met by flexible resources, storage, demand response, Flexible Alternating Current Transmission Systems (FACTS), and “other controls on variable energy resources”.

One of the big problems that ISO-NE and other grid operators have is that they have limited visibility into rooftop and other forms of behind the meter solar, and no control over its output. The organization has expressed that it will need to be able to “observe and control variable and distributed resources” in order to fully realize the benefits of energy storage, microgrids and smart grid technologies.

Some of the technical tweaks to make behind-the-meter solar be a good player on the grid are already happening. ISO-NE notes that the implementation of voltage and frequency ride-through requirements in IEEE 1547 will improve overall system reliability. But it argues that more work is still needed:

The full implementation of recently approved interconnection standards and testing requirements for distributed resources will prove vital for ensuring overall system reliability and facilitating the economical development of renewable resources, such as PV.

Another concern that ISO-NE has expressed is that even though the higher summer peak is being progressively driven down, this moves the net peak to later in the day, and during the winter the daily peak isn’t served by solar at all. In fact, ISO-NE reported its first system-wide “duck curve” 18 months ago, when solar drove net daytime demand below the overnight demand level. But this was an unusual day, and most of the time in fall, winter and spring more solar just means a steeper evening ramp.

Massachusetts appears to already be ahead of this game, as it is currently designing a Clean Peak Standard to meet peak demand in all four seasons. The latest design of the CPS and its four hour windows appears to be custom-made for the participation of battery storage.

Also, there is a need to point out that unlike many regions which are dependent on relatively inflexible coal and nuclear power plants, New England’s grid is dominated by gas plants, which tend to be more flexible. And with several massive offshore wind plants scheduled to come online over the next four years, even the limitations of existing gas pipelines may not end up being the dire threat to reliability that those who are invested in building these pipelines would like you to believe.

Japanese conglomerate SoftBank is known for many things, including the renewable energy ambitions of its colorful billionaire CEO, Masayoshi Son. But it is coming to be known as a big owner of U.S. solar as well.

Yesterday subsidiary SB Energy announced that it will acquire a portfolio of five solar projects under development by Intersect Power, an equally interesting if smaller player. Under the leadership of power trading guru and U.C. Berkeley Business Professor Sheldon Kimber, in three years Intersect Power has developed and engineered 2 GW of solar projects from inception to COD – not including the five projects it just sold to SoftBank.

The details of these five projects are as follows:

• Aragorn, 250 MWDC: Culberson County, Texas. PPA with Austin Energy. Construction date: June 2020
• Athos I, 350 MWDC: Riverside County, California. PPA with Direct Energy. Construction date: June 2020
• Athos II, 300 MWDC: Riverside County, California. Hedge with an un-named company and a REC purchase agreement. Construction date: October 2020
• Juno, 425 MWDC: Borden County, Texas. PPAs with the Lower Colorado River Authority (LCRA) and one unnamed company. Construction date: February 2020
• Titan, 375 MWDC: Culberson County, Texas. PPA with one unnamed company. Construction date: March 2020

This is not SoftBank’s first involvement in these projects, as it states that it was a developer on them as well. The projects will feature First Solar modules, NEXTracker trackers, and Signal Energy will serve as the engineering, procurement and construction contractor.

pv magazine has reported on these projects before, noting the significance that the Athos 2 project holds a hedge, but not a power purchase agreement (PPA), as one of several projects in Texas that has secured financing under this model. Most of the other projects hold 10-15 year PPAs, which are pretty standard these days, although we do not yet know the length of the contract that the Athos 1 solar project has signed with Direct Energy, which was announced yesterday as well.

And while these 10-15 year PPAs are shorter than what has been standard in previous years, in an interview with pv magazine as part of SunCast Media’s podcast studio at the Solar Power International trade show, Sheldon Kimber has noted that shorter contracts at higher rates can offer a higher level of secured cash flows than longer-term contracts at lower rates.

As for SoftBank, this is a big move in the U.S. market, but it is unclear what kind of solar portfolio SB Energy previously held United States. In a press statement SB Energy claims 5.5 GW of previously existing solar and wind projects under contract in the United States and India. Mixing two nations and two technologies means this doesn’t tell us the capacity – if any – of other U.S. solar holdings. The only renewable energy project outside of Japan shown on its website is a wind farm in Mongolia, and this is the only press releases it has published in 2019 relating to U.S. solar projects.

Regardless, with this purchase SoftBank has put a major stake in the ground in the U.S. solar market, working with a rising power in development. Watch this space.

Third-party solar is a funny business. The amassing of portfolios of solar on the roofs of customers while lease and PPA payments slowly roll in means that any company in this space is something of a vehicle for both borrowing and shelling out cash, and as such it’s difficult to evaluate which companies are getting ahead and which are more shell games.

And while we’ve expressed concern about the finances of several third-party solar companies and the model writ large over the last year, in this latest quarter Sunnova showed incremental improvement. As is consistently the case with third party solar companies Sunnova showed a net loss, this quarter at $34 million, but unlike last quarter its revenues were in excess of its interest payments.

The company is also growing. Sunnova’s $37 million in quarterly revenues is 20% higher than a year ago, and during the third quarter the company added 5,000 new customers, a 48% year-over-year increase. Overall Sunnova deployed 39 MW during the quarter, which puts it within striking distance of Tesla in deployment volume but well behind third-party peers Sunrun and Vivint.

Sunnova’s growth may be attributed to the increase in its dealer network. The company now boasts 136 dealers and sub-dealers, more than double what it had a year ago. And by now it has amassed a neat $1.6 billion in PV assets, with another $141 million under construction. The company calculates that this represents between $846 million and $1.1 billion in net contracted value, depending on the discount rate used.

But as is always the case with third-party solar, the most important metric is whether or not the company can raise enough cash to keep afloat. And here Sunnova appears to be doing fine. During the third quarter Sunnova brought in $201 million in cash through various financing activities in Q3, and around $486 million in the first three quarters of this year. This put the company at $109 million in cash & equivalents at the end of the third quarter, meaning a comfortable level of padding.

And this is just the beginning. In 2020 Sunnova expects to do five securitizations, noting that each successive securitization has been done with a better rate than the previous ones.

With Roth Capital expecting the U.S. residential solar market to grow 25% next year, there is plenty of room for multiple companies and business models. And Sunnova is taking an increasing slice of that pie.

Given where Enphase was just a few years ago, the company’s Q3 2019 results would be hard to predict. After struggling under heavy losses and undergoing a massive restructuring, Enphase reported a stunning 19% operating margin, and $31 million in net income in its third quarter results.

And its growth has been nothing less than stellar. Enphase was already the second-largest inverter maker in the U.S. residential market, but during the quarter it more than doubled its revenues from this time last year to $180 million. This mostly from the sale of no less than 1.8 million microinverters, or 584 MWdc of capacity.

Enphase isn’t doing so badly with cash, either, and has reached $203 million in its coffers.

This is mostly on the back of the sales of its IQ 7 microinverter, which is now being incorporated into AC modules from major brands including Panasonic, Sunpower and Solaria. Enphase has also upgraded to its IQ 7A, to accommodate modules up to 450 watts.

Geographical matters

While we don’t have exact figures on market share, it appears that Enphase is taking a bigger and bigger bite of its core market in the United States. Here the partnership with SunPower is likely a major benefit, given that in the first half of 2019 SunPower’s installer network, if taken as one company, would have the second-largest share of the U.S. residential market after Sunrun.

Enphase is expecting further revenue growth in the range of $200-$210 million during Q4, but with a slightly lower gross margin. This has not satisfied investors, with Roth Capital described the company’s guidance as “mixed/disappointing”. The company’s stock fell in after-hours yesterday after results were released.

And while Roth still sees room for growth for Enphase in the U.S. market, it has expressed concern about the company’s international business. “Many will jump to the conclusion that Enphase’s U.S. business is done growing, but we believe the real story is how much international business has fallen off,” stated Roth in a research note.

Roth says that its own analysis shows that rest of world revenues were down 15% quarter-over-quarter in the third quarter, and may fall again in Q4. Enphase CEO Badri Kothandaraman alluded to such weakness on the company’s results call, noting that Enphase is reviewing the strategic plan for Australia, a key market.

“I am confident that this region is going to bounce back as we transition into 2020,” stated Kothandaraman.

Grid independence on the way

It is also important to note that while microinverters have traditionally been the large majority of its sales, this is not all that Enphase offers. Enphase is currently launching the third iteration of its Encharge battery, a modular 3.3 kWh unit that includes the soon-to-be-launched IQ8 microinverter. Through its Ensemble system, the company can combine solar, energy storage and a generator to stay on during blackouts, but can also integrate with the grid when power is available.

The key to this is the long-awaited IQ 8, which Enphase describes as a “grid-agnostic” battery. If the company can get this product out in time, it has a ready and eager market for battery storage in California homeowners who are experiencing repeated proactive blackouts.

Two and a half years ago, Bob Murray was hugging Energy Secretary Rick Perry, and giving him an “action plan” to save the U.S. coal industry. Today the coal company he founded is filing for bankruptcy, and he will be stepping down as president and CEO.

Murray Energy, which has been described by S&P Global Market Intelligence as the largest privately held coal company in the United States, voluntarily filed for Chapter 11 bankruptcy in federal courts this morning. In a press statement, the company noted that this allows it to enter into a restructuring support agreement with lenders who own the majority of $1.7 billion in claims.

The company’s main operating subsidiaries have joined the parent company in filing for Chapter 11 bankruptcy.

Crisis in U.S. coal

Coal has been falling as a share of electricity generation in the United States for decades. Even before the rise of wind and solar as significant contributors to the electricity mix, cheap fracked gas was eating coal’s lunch, and the capacity factors of coal plants have fallen sharply, undermining their economics.

These economic realities have been reflected in infrastructure choices. While the United States has put online a truly massive amount of gas-fired power plants in the last 20 years, the nation’s fleet of coal-fired power plants have been shutting down, and new ones are not being built to replace them.

Fewer plants running less means less coal being shipped. According to the U.S. Department of Energy less than 600 million short tons of coal were shipped to the U.S. power sector last year, the lowest volume since 1983.

And despite an increase in coal exports, companies along the value chain of U.S. coal have felt the heat. Murray Energy is the sixth major U.S. coal company to file for bankruptcy this year, following on three others in 2017 and 2018.

Renewables vs. gas

The decline of coal presents opportunities for wind, solar and battery storage, but these are only opportunities. So far most of the market share that coal has relinquished has been filled by cheap natural gas from shale plays in Appalachia, Northern Louisiana, Texas and across the front range of the Rocky Mountains.

As always, geography plays a role. While utilities in the West such as PacifiCorp are increasingly planning rapid retirements of coal and to replace these plants largely with renewable energy, much of the nation’s coal capacity is not in the West, but rather in the South, Midwest and Mid-Atlantic Region.

Many of these regions are not as windy or sunny as the West or the Plains States, meaning that productivity is lower and the levelized price of electricity from solar and wind are higher, making it harder to compete with cheap gas. Regardless, in much of the United States, solar and wind are still the least expensive forms of new generation per unit of electricity delivered.

But even where wind and solar could cost-effectively replace coal-fired generation, utilities and regulators are often tipping the scales in favor of gas. Numerous examples include Michigan regulators declining to seriously consider alternatives to a gas-fired power plant that DTE Energy chose to build, Entergy hiring actors to fake support for a gas plant (and boo solar), and New England’s grid operator proposing measures that would hinder the participation of renewable energy in the region’s wholesale market.

There are other situations where utilities and state legislatures. In a famous example, Duke Energy has released modeling that fails to even consider the option of shutting coal plants early, and then there is the coal and nuclear bailout which recently passed in Ohio.

In the end, superior economics alone will not allow solar, wind or battery storage to realize its potential in capturing the market share vacated by coal. It will require a policy environment which does not throw up barriers to participation of renewable energy. So while the bankruptcy of coal companies is good news for the energy transition, it is just the beginning.

Listening to Elon Musk on conference calls is always an experience.

“We can make roofs come alive,” Musk began the call. “There are all these roofs out there just gathering sunlight, but not doing anything with it. In the future it will be odd for roofs to be dormant, or dead, or not gathering energy.”

With this allusion to a future of android roofs, Musk revealed the basic features in V3 of the product, where he aims to go where no company has successfully gone before – to a successful business based on photovoltaic-integrated roofs.

The redesign of this highly ambitious product appears to have centered on several changes: bigger tiles, easier manufacturability, fewer parts and easier/faster install. And of course, lower cost.

Tesla had advertised that its cost would be 40% lower for the Solar Roof versus previous versions. Online, it is advertising a 2,000 square foot roof for just under $34,000, at $17.00 per square foot (Tesla mistakenly says $7) or $1.99 per watt; however this appears to assume full monetization of the Investment Tax Credit (ITC).

Electrek is showing slightly different numbers on a customer quote on a 1,862 square foot roof at $38,000, before the tax credit. This comes out to more like $20 per square foot; with the tax credit it is more like $2.83 per square foot. Either way, this is still a 40% reduction on an earlier estimate for V2 of the solar roof.

Cheaper, or no?

Elon Musk’s approach to rooftop solar has featured an obsession with bringing down costs, as was seen with the move to online sales for Tesla’s rooftop solar.

One of Musks’ big arguments for the solar roof is that it will be cheaper than the combination of a new roof and new solar panels, which Musk argued will be the case for the majority of homeowners. However, there are inevitably assumptions here, and Tesla’s new solar roof is compared to the combination of a “premium roof” with PV.

“Maybe 80% of the time, or more, the Tesla Solar Roof should make the most economic sense, and look the best, and be the longest lasting,” stated Musk on the call.

But while economics are important to getting to mass adoption, too much of a focus can be misleading. A glass tile, building integrated photovoltaic roof is a premium product, and can’t realistically be compared to an asphalt composition roof with the least expensive solar panels on the market.

If Tesla can do this for $4.04 per watt before incentives and $2.83 per watt after the ITC, that’s major progress.

Roofs for installers

An important piece of strategic information on the Tesla call was that while only Tesla employees are currently installing the Solar Roof, that in the future the company plans to open this to outside contractors, who of course must be Tesla certified.

Along with this there were clearly a number of installations to make it easier and faster to install the roof, with Musk claiming that an 8-hour install time is possible.

This appears to have been a major focus of the redesign of the Solar Roof. “Figuring out how to install it successfully is non-trivial,” mused Musk on the call. Musk has also noted challenges with accelerated life testing, noting that testing a product for a 30-year life in only six months is inherently difficult.

But another big aspect is the simplicity. Tesla reports that the new solar roof product has less than 1/2 the parts of the previous design. “We changed some of the materials in use, changed some of the methods, and the technology we are using to something that is more scalable,” explained Musk.

All of this will be produced at the Buffalo Gigafactory, with Musk targeting deployment of 1,000 solar roofs per week. pv magazine has very little visibility into what is currently going on at that factory, but the news so far indicates that the facility has been under-utilized.

First Solar had a good day today. This morning the company announced the opening of the second-largest PV module factory in the Western Hemisphere, three months ahead of schedule. As clarified in tonight’s results call, when fully ramped the mammoth facility in Lake Township has the ability to pump out 1.3 GW of PV modules annually, up from the 1.2 GW that First Solar had earlier estimated.

This afternoon the company revealed third quarter results which show it running at full capacity, growing its backlog to 12.4 GW, and producing a nice profit. The company reported a 7.6% operating margin on revenues of $547 million, with $30.6 million in net income.

These module bookings make it so that First Solar is sold out through the second quarter of 2021, nearly two years from now. It’s a nice position to be in.

The company did burn through $500 million in cash during the quarter due to a variety of factors, including the ramp of its factories. But First Solar still has cash, restricted cash and marketable securities of $1.6 billion. Again, not bad.

First Solar also marked some costs relating to the shedding of its engineering, procurement and construction division, which it says is because it no longer needs the specialization required to install the smaller Series 4 modules, now that it has mostly moved to the larger Series 6. 100 employees who served in that division will be laid off.

First Solar is also improving its large-format Series 6. It’s unclear how much of the increase in the nameplate capacity of the Lake Township factory (dubbed “Perrysburg 2” in the call) is due to higher efficiencies, but First Solar has started production of its first bin of 440 watt modules, making the Series 6 one of the most powerful modules available on the market.

First Solar is running at 100% capacity utilization, and expects to ship between 5.4 and 5.6 GW of modules by the end of the year. With new factories in Vietnam as well as Ohio, the company is on track to remain a heavyweight in the module industry, as the only thin-film maker to come close to the scale of the Chinese crystalline silicon module giants.

For the full year 2019, First Solar’s guidance is pretty much unchanged, except that it plans to be slightly more profitable.

The company is also marking its 20th anniversary, and has shipped 25 GW of modules over that period of time. CEO Mark Widmar describes the company as operating “from a position of strength”, and many of his statements could be applied to the solar industry writ large.

“What was once a producer of a niche technology has evolved into a global company,” stated Widmar.

General Electric (GE) is not one of the companies that is associated with a serious embrace of the energy transition, and for good reason. While GE is one of the world’s largest makers of wind turbines, its much larger GE Power division invested deeply in building, installing and maintaining coal, gas and nuclear power plants, an investment which deepened after its acquisition of Alstom in 2015.

The result was what the Institute for Energy Economics and Financial Analysis (IEEFA) has described as “a case study in how rapidly and unexpectedly the global energy transition away from fossil fuels travels up the economic chain and destroys value in the power generation sector” – or in other words, a disaster.

From spring 2017 through the fall of 2018, GE’s stock collapsed, leading to a 74% decline in market capitalization, and a loss of $193 billion to investors. Among the investors that has felt the pain is one of the world’s largest asset managers, BlackRock, which is also one of GE’s biggest shareholders.

But now, GE and BlackRock are making another bet. While smaller in scope compared to its investments in conventional generation, a cool quarter of a billion dollars is a sizable chunk of money for the segment it is investing in.

Yesterday Distributed Solar Development (DSD), a joint venture of GE & BlackRock, announced that it has closed a $250 million fund financed by Morgan Stanley, Silicon Valley Bank and Fifth Third Bank to fund a portfolio of commercial and industrial (C&I) solar projects through 2020.

And while we say GE and BlackRock, the latter put the larger stake in, with 80% of the investment when DSD launched in July of this year.

The C&I market

This is not the first investment that GE and its partners have made into this space. GE Solar, which has been around since 2012, has developed more than 125 projects. But this investment is a significant signal from one of the world’s largest power companies in a sector which has seen its own share of troubles.

The International Energy Agency (IEA) has predicted that the C&I segment will be the largest growth segment for solar globally over the next five years. However, according to Wood Mackenzie and Solar Energy Industries Association, the U.S. “non-residential” sector – where it lumps C&I and community solar – was down in 2018 versus 2017, and fell further in the first half of 2019.

Wood Mackenzie attributes this in part due to the slow roll-out of the SMART program in Massachusetts and interconnection delays in multiple leading markets, and expects  renewed growth in this sector in coming years due to more aggressive state renewable energy mandates.

But market barriers remain, and developers often complain of a lack of standardization for C&I deals, with every one a “snowflake”. Additionally, there can be a difference in interests between building owners and tenants, which has been cited as one reason for the slow progress of Los Angeles’ feed-in tariff.

It remains to be seen if BlackRock and GE’s bet on C&I solar will pay off; but for a company that has lost so much betting against the energy transition, it is definitely time to up the stakes.

A few years back, there was talk of contraction in California’s solar market. The rooftop solar market hit snags with the move to Net Metering 2.0 and Tesla’s pull-back. More centrally, the state’s large utilities had already procured the renewable energy that they needed under the state’s renewable portfolio standard, for years in advance.

That, of course, was before the rise of the Community Choice Aggregators (CCAs) – entities formed by local governments to take over procurement of energy in their jurisdictions. In California, CCAs were formed with the express mandate to procure clean energy faster than the state’s mandate, and has exploded across the state.

CCAs are breathing new life into California’s large-scale solar market. As the latest in this trend, today Clean Power Alliance (CPA), which covers communities in Los Angeles and Ventura Counties, opened a solicitation (request for offers or RFO) for both large-scale and distributed renewables.

We aren’t sure exactly how much renewable energy is being sought, but it is at least 400 MW. In the utility-scale track, CPA is looking for “RPS-eligible generation” and “RPS + storage” projects, up to 400 MW in capacity, to go online by the end of 2023.

For the distributed track, CPA seeks RPS + storage and standalone storage projects from 500 kW to 10 MW in capacity in Los Angeles and Ventura Counties, to come online no later than the end of 2024. These must be front-of-the-meter projects, and cannot be aggregated distributed energy resources

While the qualification for both is simply renewables, as previous all-source renewable energy solicitations have shown, solar is likely to dominate.

Incidentally, CPA wants these renewable energy projects to play a larger role in the state’s energy profile. The CCA has argued that instead of extending the lifetimes for “once-through cooling” fossil fuel-fired plants, the state speed up its procurement of other resources.

Details of the solicitation

Qualifying projects will be offered 15-year power contracts. While that is lower than in previous years, it’s actually much longer than the PPAs that we have been seeing in much of the U.S. market. Under these PPAs, CPA will claim all the energy, renewable energy credits, and ancillary services provided by the projects.

Projects will be paid a fixed $/MWh rate, with no escalator. Prices must be offered at the project node. Projects that include storage may include an optional $/kW-month storage capacity cost, but here there will also be no escalator.

Auction administrator Ascend Analytics says projects will be evaluated on a combination of quantitative and qualitative factors, with factors including “development risk, workforce development, environmental stewardship, benefits to disadvantaged communities, and location”.

There are also some interesting requirements for workers. The bid requires that all workers be paid prevailing wages, which is far from unusual in California, and additionally there are requirements around “Targeted Workers”, and a requirement that a minimum of 10% of all hours be performed by disadvantaged workers who are living in LA or Ventura Counties.

Project timelines can be seen on the graphic to the right, and more information is available on the RFO site.

Among large power companies, NextEra Energy is the clear leader in embracing the energy transition. As the long-time owner of the Solar Energy Generating Systems, a solar thermal facility in California, the company has substantial experience in owning and running solar plants, and got in the game earlier than other big power companies.

In its third-quarter results, NextEra’s presence in the solar market is bigger and badder than ever. Development subsidiary NextEra Energy Resources (NER) added 747 MW of solar contracts and 341 MW of battery storage to its backlog, almost all of which is in the post-2020 timeframe.

This brings NextEra’s pipeline of contracted renewable energy projects to more than 12.3 GW overall, including its sizable wind portfolio. And as the company moves forward, there is an ongoing shift from wind to solar. While it has more than 4 GW of wind scheduled to come online in 2019-2020, this falls to only 603 MW in the 2020-2021 timeframe.

Solar does the opposite, going from 1.5 GW in 2019-2020 to more than 2.8 GW in 2021-2022. On the company’s quarterly results call, Chief Financial Officer and VP of Business Management Rebecca Kujawa predicted that while she expects demand for wind to remain steady, that “solar demand will continue to increase through the early part of the next decade.”

More New York, more batteries

The company’s solar projects also show a geographic shift. While NER’s portfolio remains geographically diverse, 2019-2020 projects are led by Georgia, with a number of projects in California and Arizona as well as smaller volumes in New England, Colorado and other states.

In 2021-2022 New York is the largest single location, at 550 MW of the company’s 2.8 GW of contracted projects. NextEra has done well in the state’s solicitations for large-scale clean energy.

But perhaps the biggest change is the rise of battery storage. NER’s pipeline goes from 50 MW of battery storage projects in 2019-2020 to more than 10x that in 2021-2022, with Kujawa noting that “more than 50% of the solar projects we’ve added to our backlog include a battery component”.

Solar in its service area

But while many large power companies are building solar, wind and even battery projects these days, what has made NextEra unique is its willingness to build large volumes of solar in the service area of its subsidiary utility, Florida Power and Light (FPL).

FPL made headlines with its “30 x 30” plan to put 30 millions solar panels (~11-13 GW online by 2030. Recently it also made progress by reaching a settlement with intervenors around its Solar Together program, which will include 10% participation by low-income customers. As can be expected of FPL, Solar Together is the largest community solar program in the nation.

It is important to note that like pretty much all utilities, FPL has remained hostile to customer-owned, distributed solar. FPL is fine with solar, as long as it owns it and/or it doesn’t threaten its investments in its transmission and distribution system.

And along the way, the company is making good money. Not only FPL but NER and NextEra as a whole have remained consistently profitable, with health earnings per share in Q3 and ongoing.

On Friday, U.S. President Donald Trump announced that he has nominated a new head of the U.S. Department of Energy (DOE). The pick was no surprise; since the news that acting Energy Secretary Rick Perry would step down broke on Thursday, many news outlets have speculated that Deputy Secretary Dan Brouillette would replace him.

Brouillette has kept a lower profile domestically than Perry, leading many outlets to publish rather bland descriptions of him as the nominee to head U.S. energy R&D and keep an eye on the nation’s nuclear arsenal.

So who is Dan Brouillette? We’ve compiled a few quick details:

He says he is an “all of the above” guy

In multiple media appearances, Dan Brouillette has presented himself as an advocate for President Trump’s “All of the above” energy policy. This slogan itself was first used by President Obama, but the Trump Administration has attempted to put its own stamp on the phrase. As explained by Brouillette before the International Energy Agency:

For perhaps the fist time, the United States is finally embracing a true, all of the above energy policy. One that does not pick winners and losers, but instead opens the door to innovation.

And in his role at DOE, Brouillette has been an enthusiastic participant the Solar Decathlon. This and DOE’s continuation of solar programs such as SunShot and SolSmart suggests that unlike some of the pro-coal ideologues that President Trump has appointed to the Federal Energy Regulatory Commission (FERC), Brouillette may not be hostile to renewable energy.

Brouillette has also been identified by Politico as being a key player in getting the Energy Policy Act of 2005 passed, which created the Investment Tax Credit (ITC) for solar and the DOE loan guarantee program. And even with solar outgrowing the need for loan guarantees, these two programs have probably been the most significant supports for solar at the federal level.

…but he was part of the effort to get a coal and nuclear bailout

The Deputy Secretary may have a different idea about what not picking winners and losers means, than we do (or than eight former commissioners at FERC), as he was part of Secretary Perry’s attempt to ram a bailout for coal and nuclear power plants through FERC.

Brouillette has defended the coal and nuclear bailout on the claim that coal and nuclear power plants are not being adequately recognized for the value they provide. “One of the main reasons that coal and nuclear are, quote, uneconomic is because they don’t get paid for their services,” Brouillette told the Washington Examiner in a February 2018 interview.

Along with this, Brouillette has shown that he is wedded to the concept of baseload generation, stating that “we want to always ensure that we have a certain amount of baseload available”.

But the alleged “need” for baseload reveals political concerns more than technical ones. Many grids all over the world (California, Costa Rica, Denmark, Uruguay) that have few or no coal or nuclear power plants but high penetrations of renewable energy are operating just fine, relying on either hydropower, gas plants and/or imports) to fill in when wind and solar are not delivering.

He can work across the aisle

Unlike other Trump Administration appointees (Bernard McNamee comes to mind), Dan Brouillette does not hail from right-wing think tanks, and has not spent time as a paid advocate for fossil fuels – unless you count his time as a lobbyist for the auto industry.

Instead, Brouillette has had a background that mixed extensive private sector and government energy experience, including working with members of both parties.

In this, Brouillette’s Louisiana roots may be relevant. Like many in Southern Louisiana his father worked in the oil and gas industry. Brouillette also worked under former Representative Billy Tauzin (R-Louisiana), who served as chair of the House Energy and Commerce Committee. It is notable that Tauzin began his career as a Democrat.

In getting the Energy and Policy Act of 2005, Tauzin and Brouillette had to work across the aisle, and his comments to the press reflect a nuance that is rare in the Trump Administration.

Dan Brouillette is definitely a supporter of the oil and gas industry and President Trump’s Energy Dominance approach. But he’s also more complex and subtle than many of his fellow appointees.

Former Energy Secretary Ernie Moniz is a nuclear physicist and ran the MIT Energy Initiative. Steven Chu won a Nobel Prize in physics. Samuel Bodman has a PhD in chemistry. Spencer Abraham helped found the Harvard Journal of Law and Public Policy while getting his law degree.

And then there was Rick Perry. In keeping with President Trump’s disregard for the norms of public office or technical qualifications, Perry’s main qualification for serving as secretary of energy was his former position as the governor of Texas. He was so removed from energy matters that he vowed to eliminate the Department of Energy during an abortive campaign for president, and then forgot which agencies he had planned to remove.

Tonight Secretary Perry alluded to his departure on Twitter (this was later confirmed by DOE, after denying it earlier in the day), after nearly all major media sources (Reuters, New York Times, etc.) reported that he had announced his resignation amidst the political maelstrom of the Ukraine scandal and President Trump’s impeachment hearings. Perry will leave the agency at an unspecified date later this year.

Serving as Secretary of @ENERGY under @realDonaldTrump has been the honor of a lifetime. Today the U.S. leads the world in energy production, we launched AI & Cyber Security Offices, & made environmental progress unseen for decades cleaning up the legacy of the Manhattan Project. pic.twitter.com/ZWZer3yMHy

— Rick Perry (@SecretaryPerry) October 18, 2019

Looking back on Secretary Perry’s tenure at the U.S. Department of Energy (DOE), it is one that is marked by pandering to coal interests and a brazen attempt to save coal and nuclear power plants from market forces.

The hug & the (failed) bailout

Perhaps the most memorable moment from Rick Perry’s time at DOE was a meeting with coal boss Robert Murray, which was documented by whistleblower and former DOE photographer Simon Edelman. Edelman included a photo wherein Murray, the CEO of troubled coal company Murray Energy, gave Perry a document outlining an “action plan” to create a coal and nuclear bailout.

Edelman lost his job after leaking these photos to the press, but the photo of the bear hug between Perry and Murray lives on.

We at pv magazine extensively covered the resulting Grid Reliability and Resiliency Pricing rulemaking (including here, here and here), which threatened to skew the markets in favor of aging coal and nuclear power plants. The rulemaking was eventually rejected by the Federal Energy Regulatory Commission (FERC) after widespread public outcry – including from former commissioners.

This may have been a lesson for Perry, who abandoned the effort. It may also have been a lesson for the Trump Administration, which has been sure to pack FERC with pro-fossil ideologues, leading to charges that Trump is politicizing a traditionally, technocratic, non-partisan agency.

Since that ruling there have been only minor scandals at DOE, with academics expressing concern over delayed studies and reports removed from the DOE site, but nothing of the caliber of the coal bailout that wasn’t.

Perry did give us a memorable line that expressed his fondness for fossil fuels as a solution to geopolitical problems, dubbing natural gas “molecules of freedom”, and “freedom gas”. It’s an odd name for a substance that has 25x the warming power of CO2 over a 100-year timeframe (per EPA), but has translated into the approval of a number of liquefied natural gas (LNG) export facilities.

The work continues

Given the preference for fossil fuels, there was less drama in renewable energy programs at the agency than might have been expected. Repeated efforts by President Trump to slash the budgets for DOE’s Office of Energy Efficiency and Renewable Energy and the Advanced Research Projects Agency – Energy (ARPA-E), were rejected even when the Republican Party controlled both houses of Congress.

The result is a DOE that continues to fund research, development and certain deployment programs for both solar and other forms of clean energy. Throughout Perry’s term, much of the DOE staff, contractors and staff in the agency’s network of national labs have continued a tradition of excellence in their work and repeatedly produced professional results, despite the scandals at the upper echelons of the organization.

This includes those who leaked information to the press before it could be tampered with by political appointees.

The Brouillette identity

Bloomberg’s reporting suggests that Undersecretary of Energy Dan Brouillette will take the reins after Perry departs. Brouillette is no newcomer to energy roles in the federal government, as he served as chief of staff to the U.S. House Committee on Energy and Commerce and Assistant Secretary of Energy for Congressional and Government Affairs, as well as on an obscure state energy board in his home state of Louisiana.

It’s been said that Brouillette has already taken over much of the approval of natural gas export facilities at DOE, and given his record of adherence to the Trump Administration talking points on fossil fuels there isn’t much likelihood of a sea change in policy.

Assuming that Brouillette gets the job, we’ll be reporting further on his background as we learn more about him.

If Brouillette takes over from Perry and accomplishes the same ends with less bad press and fumbling, this will follow a pattern. The resignation of scandal-ridden EPA Administrator Scott Pruitt led to the appointment of former coal lobbyist Andrew Wheeler, who has followed the same path of dismantling environmental regulations, but more quietly and more effectively.

Update: This article was updated on October 18 at 9:40 AM EST to include details on Secretary Perry’s departure, as well as the status of DOE funding during his tenure.

In Texas’ red-hot solar market, you no longer need a power purchase agreement (PPA) to get financing for your project. In the Lone Star State a new business model of building solar plants to sell power on the wholesale market, with this sale underwritten by hedges, is emerging. What’s more important is that these projects are getting the cash needed to go forward.

But as is often the case with business model developments, the new model of hedges is far from replacing the PPA. As evidence of this, yesterday Cubico Sustainable Investments announced that it has reached financial close on the 162 MW Wagyu solar project in Brazoria County on Texas’ Gulf Coast, which holds both a hedge and a PPA.

Starbucks is buying a portion of the electricity generated by the plant under a 15-year corporate PPA, while BP is supplying a 12-year physical hedge. According to Cubico the PPA will cover 40% of the project’s output and the hedge 60%, meaning that most of the electricity from this project is not covered by a PPA.

And Cubico is wasting no time in getting the project built; engineering, procurement and construction contractor Renewable Energy Systems has already started building Wagyu, and the project is expected to become fully operational in the third quarter of 2020.

Wagyu is the fourth project to reach financial close in a 580 MW portfolio of solar projects that Cubico bought from Cypress Creek Renewables in January, with the other three located in the Carolinas. Cypress Creek is staying on to provide operations & maintenance services to Wagyu, and also built the 106 MWdc Palmetto Plains solar project. Palmetto Plains is one of the three it sold to Cubico and the largest single-site solar plant to go online in South Carolina to date.

Future of hedges?

pv magazine has identified at least three other large solar projects in Texas which hold hedges, including the 200 MW Holstein project in west-central Texas and the 240 MWac Misae project in the Texas Panhandle, and at least one of the projects in the 1.7 GWdc portfolio that Intersect Power is building in the state.

It is less clear how much of a future this business model has. In an interview with pv magazine, Starwood Energy CEO Himanshu Saxena noted that it is more difficult to raise money with a hedge than with a PPA, and has suggested that this model has emerged at least in part due to need to get projects underway to secure the full 30% Investment Tax Credit (ITC) before it steps down.

“Some developers are saying – I’ll take a $20 hedge in order to get tax equity,” says Saxena.

However, merchant solar – plants selling into the wholesale market with no power contract – is emerging as a business model in other nations. This suggests that the future of selling power from solar won’t necessarily look like the past.

Update: This article was updated at 12:37 PM U.S. East Coast time on October 17 to include numbers on how much of the electricity generated by the Wagyu project is covered by a hedge, and how much is covered by a PPA.

-From the pv magazine energy storage special edition-

There are few myths as enduring in American culture as the Great Man Theory, the idea that history is shaped primarily by exceptional individuals who rise, creating themselves like the ancient Egyptian sun god Ra out of primordial chaos, independent of social circumstances, family, collaborators, education, mentorship or overall context.

And there are few places where this fantasy is as prevalent as the worlds of technology and energy. If we haven’t actively participated in perpetuating the cult of Steve Jobs, the legend of Nikolai Tesla, and of course Elon Musk idolatry, then we’ve at least witnessed these.

But as much as we may all fall prey to this delusion from time to time, there is growing awareness of the need for concrete supports to drive the level of innovation that will be necessary to guide the rapid transformation of the global energy space.

This increased attention to the role that support plays in innovation – and the importance of innovation to economies – has led to a proliferation of incubators, accelerators, and even game-showlike contests as cities, states and nations race to see who can host the next Silicon Valley.

But what does it all result in? And for innovation to succeed – particularly in the critical fields that are driving the global energy transition – what kinds of support mechanisms are actually needed?

Different places, different needs 

To answer some of these questions, pv magazine spoke with activist, entrepreneur and innovation mogul Danny Kennedy. Kennedy serves as the chief energy officer at New Energy Nexus (NEN), an organization headquartered in Oakland, California, that supports clean energy entrepreneurs from California to Southeast Asia and East Africa.

New Energy Nexus provides a wide range of services, including everything from arranging co-working spaces to offering funding and providing legal help. Kennedy notes that the kinds of support needed are usually determined by multiple factors. These factors include the stage of the business, with a defining feature being whether or not it has developed a prototype. At a more granular level, the stage of new products can be conceptualized using the Technology Readiness Level (TRL) scale, which was developed by NASA in the 1970s.

The U.S. government provides support for both basic research as well as early-stage technology development, with an emphasis on the lower TRL levels. This includes programs to support the development of energy technologies through the U.S. Department of Energy and the Advanced Research Projects Agency – Energy (ARPA-E).

But this is certainly not the case everywhere. And with work spanning the globe, one of the things that Kennedy stresses is that the needs of entrepreneurs are very different depending not only on the business stage, but on geography. NEN is actively working with entrepreneurs in Uganda and Indonesia, and Kennedy notes that existing supports are very different there.

“In those markets, there is almost nothing to support them,” explains Kennedy. “There is no R&D budget, there is no Department of Energy, there are no national labs and innovation systems and grant programs. That’s the big gap and where we are really trying to fill in that need is to try to build out the incubator and accelerator network globally, and also trying to synergize it.”

He notes that despite these challenges, innovators in those nations are trying to “leapfrog” to distributed energy systems for massive populations “that want and deserve modern electricity and mobility systems.”

Hard and soft supports

Even for industrialized nations, where a variety of actors fund research and development – including governments, universities and corporations – there are still ample needs. And much of the support that Kennedy and his network provide to entrepreneurs – whether in Jakarta or Oakland, California – is concrete: connections to funding, technical assistance, legal help and space to work in.

Kennedy notes that it is particularly important to support innovators in the areas where they do not have expertise. “When you think about the innovators, they are often engineering teams, whether that is hardware or software,” explains Kennedy. “They have no clue about term sheets, lawyering, intellectual property, and all that stuff. You don’t want them at the stage of pre-prototype devices to be spending tens of thousands of dollars of their own capital on legal counsel, but you want legal advice for them to be safe and not do anything stupid.”

Also, such teams may need support in communicating their ideas – including to the people who will ultimately be paying for them. “How does a young team of brainiacs who have invented a better mousetrap relate to the procurements people inside General Electric or Exelon?” asks Kennedy.

California innovation

While New Energy Nexus has supported a number of incubators and accelerators around the world, one of the programs that it has helped to fund operates less than a day’s drive south of the Bay Area – Southern California Energy Innovation Network (SCEIN), which is managed by incubator Cleantech San Diego and operates three other incubators throughout southern California.

SCEIN was initiated by a $5 million, five-year grant from the California Energy Commission (CEC). The agency saw a need to fund innovation in the context of the state’s ambitious clean energy mandate, and that’s what it will take to get to very high portions of renewable energy on the grid.

“CEC realized that business-as-usual was not going to work, and that we needed to come up with an out-of-thebox approach,” explains Alyssa Gutner-Davis, the program manager for Cleantech San Diego.

SCEIN works with companies in the concept stage to early commercialization, including the critical step of customer discovery. It provides a wide range of services, including research and testing, market intelligence, and of course introductions to investors.

Along the way the initiative has attracted funding through the CalSEED program, which has made $25 million available for companies in round A and B grants. But that is just the beginning.

In the three years that SCEIN has been operating, companies that have gone through the program have raised $43 million in private capital and $5.7 million in public capital, as well as filing 193 patents.

The program’s graduates include some real success stories, including EV infrastructure company eMotorWerks, which was acquired by Italian energy giant Enel in 2017.

The social aspect

SCEIN is quite well connected and the initiative’s technical advisory committee includes experts from some of the top companies in the global energy transition. These include DNV GL, Enel Green Power and Engie, as well as law firm Stoel Rives, and even utilities SDG&E and SCE.

As part of the program, startups also receive mentorship. This helps them to assess how program service delivery is going, so they can keep track of progress. Kennedy says that creating a space for all these kinds of different interactions provides a great deal of value unto itself.

“One of the secrets to our success as an organization is just bringing people together,” he observes.

“As crazy as that sounds, I think human or social capital is more valuable than the financial capital. The magic is actually in the creative collisions, and that peer-to-peer learning.”

He also notes that given what they are up against, these energy startups can use all of the help they can get.

“The difference between a startup in clean energy, building out smart grids or better sensor technology, or AI for electricity management or mobility services – [is that] they are up against huge vested interest companies that are basically dug in and trying to protect themselves from change.”

The global energy transition of today is being advanced by challenging the energy structures of yesterday. Overriding systems requires the continuous nurturing of innovation, and the networks that support innovation play a critical role in developing the smart technologies of tomorrow.

There has been some talk of a slowdown in California’s large-scale solar market, following the over-procurement by the state’s large investor-owned utilities to meet their targets under the state’s renewable energy mandate. However, large solar plants are still being developed, deals signed and plants put online.

Today came the news that one of the largest clusters of solar projects in the state has been completed, with Capital Dynamics announcing the completion of the 121 MWdc Springbok 3 solar project. This is the third plant in a 448 MWdc cluster of projects in Kern County, at the southern end of California’s Central Valley.

Like the other two in the series, Springbok 3 is contracted to sell power to the Los Angeles Department of Water and Power (LADWP) and municipal utilities in Southern California through the Southern California Public Power Authority. The plant’s contract lasts for 27 years and runs at 5.2 cents per kilowatt-hour (see pv magazine’s coverage of the power contract in this article).

Exact project details were not available by press time, but previous projects in the group have utilized single-axis trackers by Array Technologies.

On a roll

Capital Dynamics bought a controlling stake in Springbok 3 from developer 8minute Solar last year, as part of sustained series of solar projects acquisitions that have been going on for at least a year and a half. The Swiss asset manager first came to pv magazine’s attention when it acquired yieldco 8point3 from First Solar and Sunpower, and as recently as August the company bought the 180 MW Townsite solar project, part of 1 GW of projects that Tenaska and Switch are developing in Nevada.

According to the Capital Dynamics website the company’s electricity generation portfolio currently covers more than 100 projects totaling 4.7 GW, including at least 1.6 GW of operational large-scale solar. And the company is branching out; in July Capital Dynamics announced a new joint venture with Sol Systems to develop up to 100 MW of commercial and industrial solar annually.

These investments are not just limited to the West Coast. Last November, Capital Dynamics announced a deal with Tenaska to develop solar projects in six Midwestern States, with a portfolio that is larger than the entire installed solar capacity of those states.

These investments suggest that the asset manager is betting on the boom currently underway in the U.S. solar market, a boom which shows no sign of slowing any time soon.

Over the past decade pv magazine staff have seen a number of different business ideas in residential solar. We’ve seen solar leases and power purchase agreements dominate over the market, only to fade (but never go away entirely) as loans got more sophisticated. And of late, we’ve seen a move to selling solar through the internet as a way to eliminate those pesky costs of paying humans to actually sell rooftop solar.

One of the oldest ideas about how to cut costs is advancing, not through a business, but through a non-profit. Solar United Neighbors (SUN) is reporting that it has added 13 “solar co-ops” in ten states over the last six months, which are allowing participating homeowners and small business owners to essentially buy rooftop solar in bulk, 30 roofs at a time.

These new cooperatives span the nation, from Arizona to Maryland, with four in a state that is experiencing a minor boom: Florida. Beaches Business Solar Co-op, Miami Digital Solar Co-op, Orlando Solar Co-op and Pasco County Solar Co-op.

These co-ops work by gathering neighbors together through informative sessions run by SUN, and getting them to sign up more neighbors, often through word of mouth. When the co-op reaches 30 members, these decide on an installer, with installers required to submit RFPs through SUN. Recent installers chosen by co-ops in Arizona, Denver and Pennsylvania including Icon Power, Sunfinity Renewable Energy and EIS Solar.

Reducing sales costs

As for how much homeowners save through this system, this is not entirely clear. The organization has stopped giving estimates of per-customer savings, noting that savings vary depending on location.

SUN provides a figure of $630,000 in private investment per co-op, which translates to $3 per watt. This is below the average costs reported by the larger third-party solar companies but around the average of bids on EnergySage’s online solar marketplace.

If cost reductions through the two forms of sales are similar, this may not be an accident. Both still involve a sales process, but in one case much of this is automated, and in the other 30 systems are being sold at once.

And there are likely to be larger effects. SUN estimates that the 30 households that go solar install an average of 7 kW each, for a total of 210 kW of new distributed solar, meaning that these 13 co-ops together should result in the installation of something around the order of 3 MW of solar.

This is a small portion of the overall residential solar market in the United States, but it is enough to “seed” these communities, as studies have shown that homeowners are much more likely to install solar if they see it on their neighbor’s property.

This effect can be even more pronounced depending who your neighbors are; one of the past solar co-op members at Miami Digital is John Morales, NBC 6’s chief meteorologist.

California has been a clear leader in deployment of solar and other forms of renewable energy. While it has not reached the very high portions of wind that smaller Plains States have boasted, the The Golden State has been a leader in terms of raw deployment, backed by renewable energy mandates for utilities as well as policies to support residential solar and battery deployment.

And those policies are paying off. A new report by non-profit Next 10 not only confirms what the state’s renewable portfolio standard updates have shown, that it is rapidly decarbonizing the electricity sector.

Solar has played a leading role here. Next 10 states that in 2017 solar overcame wind as the state’s largest renewable power source, representing 10% of its total mix. pv magazine’s calculation of raw data provided by the U.S. Department of Energy shows that solar – both large-scale and behind-the-meter – rose to meet 14% of all in-state demand in 2018, however it is not clear if we are using the same methodology.

Either way, solar largely drove total in-state renewable energy growth rates of over 20% from 2013 through 2017, and a stunning 162% increase in renewable energy output over a 10-year period. This has led Next 10 to conclude that at current growth rates California is set to meet its ambitious targets for RPS-compliant renewables to represent 50% of electricity generation in 2026 and 60% in 2030, “with relative ease”.

Battery deployment is also on schedule. California easily the nation’s largest energy storage market, and the roughly 1.5 GW of energy storage to be procured by the state’s large investor-owned utilities is above the 1.325 GW requirement set by AB 2514.

Some of the optimism for the future can come from California’s Community Choice Aggregators, which are taking over procurement for an increasing portion of the state’s electric load from investor-owned utilities under mandates to decarbonize faster than is required by state law.

Cars

That is the good news. The bad news is that even with this progress in the electricity sector, Next 10 says that given current rates of decarbonization California is not on track to meet its 2030 or 2050 goals for greenhouse gas reductions.

And while the report looks at many sectors, one problem stands out as obvious: cars. The transportation sector alone represents 41% of California’s emissions, with passenger vehicles making up the bulk of that. In 2017 the state saw both a record number of vehicles registered at 31 million and also a record number of vehicle miles travelled. This has been accompanied by falling participation in public transit ridership, amid a new boom in ridesharing services.

The net result is that despite nationally leading fuel efficiency standards, greenhouse gas emissions from the transportation sector continue to rise. Nor have electric vehicles (EVs) yet made much of a dent. California has a higher rate of EV sales than the national average, but hybrids and EVs still make up a small portion of the total vehicles on the road.

One challenge is that automobiles don’t turn over every year, but can stay on the road a decade or longer, meaning that emissions from cars sold today are locked in for many years to come. And this leads to debate over the path forward. While some are calling for a more rapid electrification of automobiles, the California Air Resources Board and others have framed the problem in terms of a need to reduce vehicle miles travelled.

The solution is likely to be a combination of both. Either way, the report serves as a stark warning that for deep emissions reductions, decarbonizing electricity is only the beginning.

One argument that we at pv magazine hear made over and over against rooftop solar – by utilities, advocates for conventional power and even sometimes by those companies in the business of large-scale solar – is that distributed generation (DG) is simply too expensive.

Why put up solar that can cost 3-4x as much per watt, they argue, when you can have large-scale solar at  less than three U.S. cents per kilowatt-hour in some places?

Such oversimplified comparisons inevitably miss a host of values added and costs that are avoided when you generate at or near the point of demand, instead of hundreds of miles away. But the value of a power system based in part on DG got a lot more clear to residents of Northern California yesterday when Pacific Gas & Electric Company (PG&E) shut off the power of around 750,000 residents in three waves.

The Public Safety Power Shutoffs (PSPS) are being implemented to keep PG&E’s power lines from causing wildfires, a very real concern in light of the utility’s massive liability for the catastrophic fires in the state over the last few years.

Advocates pv magazine spoke with say that while a system with more distributed generation wouldn’t entirely eliminate the need for public safety shutoffs, they can lessen the need for these, and that the combination of microgrids and distributed generation can keep critical loads online. They also say the biggest problem is that the resiliency that distributed energy resources offer simply isn’t being valued.

Another grid is possible

The idea that rooftop solar and other distributed resources could avoid the need for new power lines isn’t theory. In its 2017-2018 transmission plan, California’s grid operator cancelled 20 new transmission projects and revised 21 more due to energy efficiency and residential solar power altering load forecasts, with a projected savings of $2.6 billion.

There is clearly room to grow. According to U.S. Department of Energy (DOE) data, as of the first half of 2019 California only met 6% of its total electricity needs with what it deems small-scale solar (defined as plants smaller than 1 MW, including residential and commercial rooftop systems).

Of course, there are limits to how much solar can be installed on existing roofs. According to a 2016 study by DOE’s National Renewable Energy Laboratories (NREL), California’s buildings have the technical potential to generate a volume of electricity equivalent to 74% of its annual electricity demand using rooftop solar – the highest portion of any state.

But not only is technical potential an upper bound that will never be reached, but this ignores the daily and seasonal variations in the output of solar, and the impractically massive amount of batteries that would be needed to accomplish this.

Another factor is that such a re-write of the rules would require similarly massive upgrades to distribution system infrastructures. When putting all of this together, advocacy organization Clean Coalition has settled on a goal for 25% of electricity demand to be met with local, distributed power.

It is also important to note that in replacing large centralized generation, what is often used is not rooftop solar in isolation, but what Clean Coalition describes as a “basket of solutions”. Regulators are finding that what is most effective to meet grid needs in a cost-effective manner is usually a combination of distribution grid upgrades, distributed rooftop solar, batteries and demand-side management solutions.

Grid isolation

As many owners of rooftop PV systems across California are realizing, simply installing solar isn’t going to give you power in the event of a system-wide shutoff. Most PV systems are wired such that they need power from the grid to function (not all are – see our other article this morning on grid-isolating inverters and battery storage).

A future of higher penetrations of distributed energy means fewer power lines and less power moving on those lines, but Clean Coalition notes that there are still solutions for keeping the grid stable, even now. the organization has been working with a number of cities to implement community microgrids, which allows local distribution systems – and individual facilities – to disconnect from the larger grid.

There typically isn’t enough local power on these systems to power an entire community at normal levels of consumption indefinitely, but it can allow critical facilities like hospitals, fire stations and schools to continue to operate indefinitely.

At a smaller level, properly configured solar and storage systems can allow homeowners to “island” their homes and run on solar and batteries. This also may not allow normal consumption levels, but can keep prioritized loads like refrigerators, cell phone charging and other services running.

Clean Coalition notes that cell phone charging is particularly critical in disasters. “A lot of people are really concerned about communications if the power goes down,” stated Clean Coalition Founder and Executive Director Craig Lewis. “They are asking how this is going to keep us safer if we can’t communicate?”

Getting from here to there

Lewis calls his organization’s goal of 25% of total energy consumed coming from local renewables “achievable and reasonable”, but this is still roughly 4x the level that California has reached.

And while batteries are advancing, this market is still in its early stages. Sunrun, the largest residential solar company in the United States, estimates that 25% of its new customers in California are going with the company’s BrightBox system, which pairs battery storage with solar and provides power during outages.

And in order to get to a more resilient system quickly, it is clear that more than net metering is needed. First, given the relatively high cost of batteries incentives such as the state’s Self Generation Incentive Program (SGIP) have been cited by advocates as a critical tool to build the market. The California Public Utilities Commission (CPUC) announced last month that it will expand support under SGIP to fire-prone areas in California, a move which Sunrun VP of Energy Services Audrey Lee cites as an important development for resilience.

Clean Coalition also argues that net metering alone has not been effective in addressing the market for commercial and industrial solar, which faces unique barriers. One of the organization’s key campaigns has been to change the way that transmission costs are metered and assessed in California through the Transmission Access Charge, which it calls a “massive market distortion” that unfairly disadvantages distributed generation.

Clean Coalition is also a long-time advocate for feed-in tariffs (FiT), the system that Germany used to kick-start the global solar market. But even when these policies are implemented, this doesn’t always solve the problem.

Despite implementing a FiT in 2013, it took Los Angeles six years to reach 150 MW through the program, which Clean Coalition’s Lewis blames on interconnection delays and a program design which made it attractive for companies occupying large commercial and industrial buildings, but not building owners.

The value of keeping the lights on

Ultimately, what both Sunrun and Clean Coalition agree on is that the current system does not properly value the resilience that distributed generation, battery storage and microgrids can supply.

This may be a natural result of our habits – why pay attention to resilience when the power system is running fine? But it looks much different right now to the hundreds of thousands in California without electricity. And even when the resilience of critical facilities like hospitals is recognized, it can be hard to compare its worth to America’s fundamental source of valuation: the dollar.

Both NREL and Clean Coalition are working on programs to set a dollar value for resilience that can be used by regulators, utilities and governments to properly value the benefits that resilience can offer.

And while it may not yet have a number associated with it, the value of the ability to keep the power on is something that Californians are increasingly aware of.

At the Renewable Energy Finance Forum (REFF) – Wall Street conference held in New York City this June, Starwood Energy CEO Himanshu Saxena shocked the room with a statement about five to seven year contracts for solar projects. He further went on to explain that this was translating to longer and longer “merchant tails”, or periods where uncontracted energy will be sold on the wholesale market.

Only one month later Duke Energy revealed that it was buying a 200 MW solar project under construction in Texas which holds a 12-year hedge with a subsidiary of Goldman Sachs. The Holstein plant is one of many projects in Texas that are proceeding without any power purchase agreement (PPA).

These moves towards shorter contract lengths, longer “tails” and alternative contract structures all suggest a move in the direction of merchant power. However, these developments also bring up many questions. Chiefly, is the use of hedges in place of PPAs part of a larger trend, or merely a quirk of the market driven by the expiring Investment Tax Credit (ITC)? And ultimately, can merchant solar emerge as a viable business model?

Shorter contract lengths

Sexana’s comment at REFF-Wall Street spoke to a documented trend: over the past two years PPA terms have plummeted. A list of project PPAs supplied by Bloomberg New Energy Finance (BNEF) shows typical contract lengths falling from 20-25 years in 2017 to 12-15 years in 2019, with a 10- or 12-year term being the lower bound for PPAs reported by the analysts who pv magazine spoke with.

These shorter PPAs are driven by a number of factors, but chief among these is that corporate off-takers are demanding them. Colin Smith, a solar analyst at Wood Mackenzie, describes a “tremendous amount of pressure” from Google, Facebook and Microsoft for shorter terms.

“They want to secure low-cost contracts, but don’t want to be stuck with something 10 years long,” Smith told pv magazine. “Facebook hasn’t been around for 20 years – it’s hard for them to sign a contract that is longer than they’ve been around.”

There are also novel deal structures emerging, and BNEF reports one PPA where Adobe buys the first five years of output from a solar project, and Facebook takes over on year six.

The balance of power

Utilities are also calling for shorter PPAs, and are in a better position to do so than in previous years. Many utilities have already fulfilled their responsibilities under state-level renewable energy mandates, and now are voluntarily procuring renewables. This means they are under less pressure to sign deals.

“There is the possibility that tomorrow they are going to secure a longer-term contract at a lower price,” notes Smith. “The solution to that is securing shorter contracts.”

Adding to this, the utility-scale solar market is starting to grow in states like Florida where utilities are vertically integrated. This means that utilities can build their own solar, and state regulators are increasingly allowing them to pass the up-front costs on to their customers through a process called rate-basing. So when utilities do choose to contract with outside developers, the availability of other options further tilts the balance of power in contract negotiations.

Kyle Harrison, senior associate of corporate sustainability at BNEF, says that these dynamics end up pushing more risk onto developers. “[Offtakers] want developers to take the risk,” explains Harrison. “They don’t want weather risk and they want shorter contract lengths.”

And to build any solar plant you first have to fund it, so the dynamics on the investor side are also shifting the balance of power. As investors get more and more comfortable with solar as an asset class, the “wall of money” looking for solar projects to invest in grows. And with more investors looking to put money into fewer projects, investors can’t afford to be too particular about contract lengths, so they are also taking more risks.

Hedges and other models

Beyond shorter contracts, there are changes to the kinds of contracts that solar projects are securing. Specifically, hedges are increasingly becoming a substitute for PPAs in the Texas solar market, with not only Duke’s Holstein project but also the 240 MWac Misae solar project in Childress County holding hedges instead of PPAs.

These hedges provide some level of security for investors, by providing a floor for prices. But while this is not the same as a PPA, in that sales into the wholesale market form the basis for revenues for asset owners, it is also not the same as pure merchant risk.

Starwood’s Saxena estimates that there are a few gigawatts of projects with hedges in the Texas market, but also says that there are limitations. “There are challenges as to whether these deals are going to get done or not,” Saxena told pv magazine. “It’s not like there is an unlimited market for financial hedges. Each hedge needs to be pricing a little bit lower than the one before.”

Saxena says that while there are a lot of developers in the advanced stages of planning projects backed by hedges, many of them are having a hard time securing capital. “The challenge comes when you are looking at hedge prices in the low 20-dollar range,” explains Saxena. “A lot of investors like us who are evaluating these projects are having a hard-time making the numbers work.”

He also notes that for all the projects under development in Texas with hedges, few have actually begun construction.

But while hedges have become a popular substitute for PPAs in Texas, they are not the only potential form of alternative contract structure. BNEF’s Harrison notes the emergence of proxy revenue swaps in the wind market, where an insurance company takes the risk on the volume of electricity generation and thus the weather, and the settlement unit is the revenue.

“Insurers are more willing to take a gamble on weather risk for wind projects, as they have more insight into historic generation,” says Harrison. “The main differentiator is that you are locking in some portion of your revenue, and it is a lot easier to secure funding.”

While proxy revenue swaps have not yet caught on in solar, there are many ways to guarantee a certain amount of revenue, and to allocate risk between the various parties.

South of the border

There have been merchant solar projects both in the United States and Latin America, but the first wave of these projects largely ended in disaster. Solar projects which took advantage of high hourly prices at certain nodes in northern Chile were later unable to repay their lenders when more solar came online and power prices fell. This led to a scandal in the United States as they were backed by loans from the Export-Import Bank and Overseas Private Investment Corporation (OPIC).

Additionally, First Solar had to write down losses on its Barilla project in Texas, which it built to test merchant solar; since then the project has secured a PPA. And merchant solar projects have also re-emerged in Australia and Brazil, Chile and Mexico. This has been going on for several years in Chile and Mexico, but the projects in Australia and Brazil appear to be more recent.

Saxena says that the turn to merchant solar in Mexico is the result of policy changes, and the difficulty in securing even 10-15 year PPAs in that nation. “It seems like people will build it now, and try to sell the power over time,” he observes.

The ITC

Beyond the compelling dynamics of mid-day power pricing, there is another reason that so many projects are moving forward in Texas, PPA or no: the ITC. This federal incentive falls from 30% to 26% at the end of this year, to 22% at the end of 2020 and 10% at the end of 2021. This means there is a big financial incentive to get steel in the ground in order to claim as much of the ITC as possible.

Both developers and financiers are able to take more risk if they can secure the tax equity portion of the financing. “Some developers are saying – I’ll take a $20 hedge in order to get tax equity,” says Saxena.

He goes on to note that these are risky bets, but also expects the use of hedges in the Texas solar market to be a temporary phenomenon. “The market is acting because of the transient nature of the tax credits,” he states. “If the tax credits go away these short hedges should go away with it.”

Future of merchant?

The analysts who pv magazine spoke with agree that it would be very difficult to move to a market where projects are built on a merchant basis in the United States, and don’t expect solar projects to be built without PPAs in the near term in states other than Texas. However, the shorter length of contracts means that unless they can secure additional contracts or extensions, asset owners are going to have merchant projects on their hands after PPAs expire.

This will often be after much or all of the financing has been paid off, but still the use of hedges means that both project developers and financiers are getting a taste of using models other than long-term PPAs to get solar projects off the ground.

None of this is happening in a vacuum; as the price of solar continues its historic fall and as financiers get more and more comfortable with solar as an asset class, hedges and other models may end up spreading. But while we aren’t sure what exactly will replace long-term PPAs, the era when a 20-year power contract was needed to build a solar plant is over, and it isn’t coming back.

Concord NH City Council to decide on maximum size of PV arrays – The city council of Concord, New Hampshire is considering a proposal to raise the maximum size of a solar installation in the city to 50 acres, up from the current max of 25. Additionally up for debate is the percentage of any parcel that can include solar panels, which currently sits at 40% and proponents are aimed at raising to 60%. There is a vested interest in raising this maximum, as the city has a stated goal of 100% renewable energy by 2030. Source: Concord Monitor

Funding for battery start-up – Battery management company Titan Advanced Energy Solutions has closed on $10 million in a Series A financing round. According to the company, the funds will be used for product development, launching new solutions and hiring top engineering talent. The funding round was co-led by Schneider Electric Ventures (SEV) and Energy Innovation Capital (EIC). Source: Renewables Now

SEPA’s releases 2019 Utility Demand Response Market Snapshot – “Based on data collected from 190 utilities, representing 64% of total U.S. customer accounts, the Smart Electric Power Alliance (SEPA) found that utilities enrolled 20.8 GW of demand response (DR) capacity, and dispatched 12.3 GW of DR capacity (59.2% of enrolled capacity) in 2018. The commercial and industrial (C&I) segment contributed over half of total reported DR capacity, 13.3GW. The 2019 Demand Response Utility Market Snapshot details the phasing out of older programs, the introduction of advanced technologies and smart device.” Source: Smart Electric Power Alliance

Solar applications surge under New York program – According to coverage from Politico, seven new applications for utility-scale solar projects have been submitted under New York’s siting law in the past month, three of which would be the largest in the state if completed. The whole gauntlet of applications totals 1.75 GW in capacity. Source: Politico

Some time over the last 72 hours, the prediction made by Roth Capital came true: The Office of the U.S. Trade Representative (USTR) has reversed its position and removed an exemption for bifacial modules from the Section 201 tariffs.

We’re not sure exactly when this happened, as there is no date on the document buried on the USTR website, and no press release. USTR filed the change in the Federal Register this morning at 8:45 AM EST, after the removal of the exemption was reported by multiple media outlets.

Regardless, the exemption will now end on October 28 “effective with respect to articles entered for consumption, or withdrawn from a warehouse for consumption”. Given the long lead times for ordering modules, this means that few bifacial panels that are not already on container ships are likely to slip through tariff-free.

“Surge” of bifacial predicted

The six-page note on the USTR site does shed some light on the thoughts behind the trade officials’ decision, with the office determining that the exclusion would “likely result in significant increases in imports of bifacial solar panels”, and warning that “such a surge is imminent”.

USTR further notes that “such panels will likely compete with domestically produced monofacial and bifacial solar crystalline silicon solar photovoltaic products in the U.S. market”.

Neither statement matches our understanding of the U.S. market. As noted by Roth Capital in its research note warning of the end of the exemption, given the current boom in solar construction and the backlog of module imports, the removal of the exemption is unlikely to affect import volumes in 2020. Simply put, orders have already been placed through the end of 2020.

It is also a dubious claim that an exemption for bifacial threatens U.S. manufacturing. USTR reports that contract manufacturer Auxin Solar is dedicating a significant portion of its manufacturing capacity to bifacial products, but at last check Auxin had a total of only 100-120 MW of annual manufacturing capacity – less than 1% of the total demand in the U.S. market.

In the bigger picture, per pv magazine’s calculation even when the four large U.S. factories which have come in the wake of the tariffs come online there will only be around 5 GW of U.S. PV module capacity. This is not even half enough to meet the demand this year, so multiple gigawatts of modules are and will continue to be imported, mostly from Asia – tariffs or no.

Given all of the uncertainty that the Trump Administration has introduced regarding trade, the reaction from the U.S. solar industry at times is simply frustration. On LinkedIn John Williamson, the founder and CEO of engineering consulting and software company KiloNewton described the removal as “a nonsense reaction to a nonsense exemption to a nonsense policy.”

As for bifacial technology, Wood Mackenzie Senior Research Analyst Xiaojing Sun says that bifacial modules will be cost-competitive again in 2021, even with the Section 201 tariffs. She describes this as a “temporary setback” for the technology, noting that “long-term growth is still expected.”

Update: This article was updated at 11:46 AM EST on October 8 to feature a link to the unpublished entry by the U.S. Trade Representative in the Federal Register, and additionally to include USTR’s statements regarding Auxin Solar’s bifacial manufacturing and related analysis.

Concentrating Solar Power (CSP) has had a rough decade. Ten years ago, the technology, which uses concentrated sunlight to create steam and drive turbines, was all the rage, with multiple gigawatts of solar projects planned in the Mojave Desert following on major industry success in Spain.

But over the next few years CSP, like many other emerging technologies, fell prey to the falling costs of crystalline silicon solar. The fact that the plants operate optimally when located in areas with particularly intense sunlight didn’t help, as many of the locations chosen by developers led to lawsuits with conservationists and Native American groups.

And now, the developer which built one of the few large CSP plants to go online in the United States has a new concern. Last week SolarReserve filed suit against the LLC which owns Crescent Dunes and the U.S. Department of Energy. The lawsuit claims that DOE, which provided a loan guarantee for Crescent Dunes, is stacking the board and trying to push out its sole director.

According to the lawsuit filed last week (and put online by Bloomberg Law), SolarReserve says that DOE is replacing new director which it appointed, via a “notice of default” that the agency sent last month. According to SolarReserve:

The DOE’s actions interfere with SolarReserve’s right to participate in the management of Tonopah; and they result in a forfeiture of SolarReserve’s property rights in a $1 billion project which SolarReserve started in 2008, without an opportunity to contest that forfeiture.

SolarReserve also states that the “independent” managers which DOE has chosen now give it the ability to “exert substantial control” over the Tonopah project, and SolarReserve specifically mentions the ability to file for bankruptcy.

Operational issues

The alleged DOE takeover comes in light of other problems at the Crescent Dunes project. According to reporting by the lawsuit, NV Energy has terminated its power purchase agreement with Crescent Dunes after the project failed to generate the required amount of electricity.

Crescent Dunes appears to have struggled for some time; despite signing an engineering, procurement and construction agreement in 2011, the plant only “commenced commercial operations” in 2015. It appears that there is still a debate as to what went wrong with the molten salt storage system, which SolarReserve blames on the construction contractor.

This is not the first U.S. CSP plant that has had problems. This author has documented problems during the ramp up at the Ivanpah Concentrating Solar Power (CSP) plant, which like Crescent Dunes utilizes a “power tower” design instead of the more common parabolic trough design.

Either way, without a power contract and with DOE running the board, SolarReserve is warning that bankruptcy could be the next step:

Upon information and belief, SolarReserve believes that in connection with DOE’s purported takeover of Tonopah, on or before October 3, 2019, Tonopah now exposes SolarReserve’s equity to the uncertainly of a Tonopah bankruptcy filing

But whatever happens, this isn’t a good day for a technology that held so much promise.

If there is one certainty about the trade actions that have been undertaken by the Trump Administration, it is that they are uncertain and hard to predict.

In June both U.S. solar developers and Asian cell & module makers celebrated when federal trade authorities announced that they would exclude bifacial solar cells & modules from the Section 201 tariffs imposed a year and a half prior.

The prospect of importing tariff-free bifacial modules, which are not significantly more expensive than their mono-facial counterparts and offer additional output, leads to potentially lower costs for PV systems. This affect is particularly acute for large ground-mounted projects where the price of solar panels makes up a more significant portion of total system costs.

And, in response, large Chinese PV makers with factories in Southeast Asia soon began converting a larger portion of their factories to produce bifacial products. However, this activity may slow down if the claim made by Roth Capital is true: that the Trump Administration has decided to reverse this policy.

In a research note issued yesterday, Roth Analyst Philip Shen stating that its investigations suggest that the Trump Administration has decided to reverse the exemption for bifacial products under Section 201. As of press time the office of the U.S. Trade Representative had not responded to the claim.

Manufacturing implications

Roth notes that whether or not the exemption goes away won’t matter too much for 2020, as most of the volume under order to be shipped into the United States is based on standard monocrystalline silicon cells with passivated emitter and rear cell (PERC) technology. This is supported by pv magazine’s discussions with PV makers who say that they have been sold out for more than a year in advance, meaning that contracts being filled for at least the next nine months were signed before the exemption.

The investment bank also states that this is not as good of news for bifacial going forward, although it can be argued that the technology is likely to mature on the advantages that bifacial offers.

However, there is one likely winner in this situation: First Solar. Roth describes this as an “incremental positive” for the thin film PV maker and its Series 6 technology, which competes against inexpensive Asian crystalline silicon solar for large solar projects. Roth has reiterated its “buy” advice.

However, it is important to note that First Solar is already in an enviable position. The company’s products are sold out years in advance, as it continues to build and ramp more factories in Ohio and Vietnam.

The bigger picture

As for the larger U.S. market, the removal of the exemption could make some projects with marginal economics no longer pencil, but it is likely to not be a big deal either way. The Section 201 tariffs fell to 25% in February of this year and will fall to 20% in February 2020, after which time most orders being made now will be filled.

These tariffs – and the uncertainty created by the Section 201 process – definitely hit the U.S. market in 2018. However the market is back on its growth path this year, with Wood Mackenzie reporting a record 8.7 GWdc of large-scale solar under construction at the end of July.

Wood Mackenzie estimates that the United States will install 12.6 GWdc of solar this year, and with total U.S. module manufacturing capacity at less than half of that, it is clear that module imports will continue, Section 201 or no, and tariff exemptions or no.

This is supported by module shipment data published by the U.S. Department of Energy. The agency’s latest report found more than 1 GW of module imports in both June and July, with imports making up the bulk of shipments.

When we think of hot solar markets, the area covered by PJM Interconnection does not usually come to mind. The 14 states in the Mid-Atlantic and Midwest do not have the sunlight that California and the Southwest have. Additionally – New Jersey aside – they do not have the high electricity prices and supportive policy environment for solar seen in states like New York and Massachusetts.

The same could be said of the Midcontinent System Operator (MISO), the grid that covers the heart of the Midwest and stretches in a narrow band south to Louisiana. While MISO has some wind resources, none of the states that it covers have been leading solar markets.

All of this is changing. As of the end of July, pv magazine counted 47 GW of active solar projects in PJM’s interconnection queue, and 57 GW in MISO’s queue.

How many of those projects will actually get built is another matter, and some of this is dependent on the structure of the market. Last November, the Wind Solar Alliance published a report which laid out a set of market reforms to facilitate greater participation of these services, which it also says will make the market more free, fair and flexible.

This list of reforms was not small, with 29 individual recommendations, broken in energy market reforms, reliability services reforms, and capacity market reforms. Fortunately for laypersons and those with shorter attention spans, the report broke this down into four themes:

• Attract flexible resources including demand response and storage through open participation and efficient market pricing
• Reduce inappropriate compensation and commitment of inflexible units
• Allow resources to participate in all reliability services markets
• Respect resource choices by states without mitigation.

Saving dollars as well as CO2

Last week Wind Solar Alliance took a further step and quantified the benefits of these reforms to consumers in a follow-up report, which found aggregate benefits of $2.5 to $6.9 billion for consumers. This was mostly through making markets more flexible, with minor contributions from linking up “seams” in the transmission system and ending self-scheduling of generators.

On the individual ratepayer level, this translates to $24-$48 in savings each year for PJM customers, and $10-$49 annually for customers in MISO—or around $1-$4 on each monthly electric bill.

The range of values depended on rates of renewable energy deployment, and the report’s authors described this as a “good preliminary estimate” which can be built on with more detailed analysis and modeling.

These dollar estimates are actually conservative, as the report assumed only the highest value from the various flexibility reforms. However, it does note that if multiple flexibility policies were enacted, that the total savings were likely to be much larger.

The MOPR

This series of reports can be seen in part as a response to proposals by grid operators that favor conventional resources. These include PJM Interconnection’s Minimum Offer Price Rule (MOPR) proposal, which the initial report describes as “active interference” in state markets. Wind Solar Alliance alleges that it would affect consumers, as stated in the November report:

These restrictions do not lead to just and reasonable rates for customers if some resources on the system are excluded from the market when determining prices, or prices are artificially raised through minimum bid requirements. We recommend that the application of MOPR to state Renewable Portfolio Standards (RPS) be minimized or avoided altogether, at least in the case where the resources were developed through competitive processes.

MOPR is currently being considered by FERC, which is hamstrung by the lack of a quorum following the retirement of Commissioner Cheryl LaFleur (D). This week President Trump appointed a new commissioner, James Danly, however Danly must be approved by the Senate before he can bring FERC to a quorum.

pv magazine: You’ve been working with Trina for 15 years. You’ve certainly had a very long view of what’s gone on in the U.S. market. Can you tell me a little bit about what you’ve seen over this time and what you think the big picture is?

Zhu: The overall U.S. market – the way I’m looking at it is that it is very sustainable very strong and the economy is very good. Renewable energy does have a lot of support from all the different perspectives: from investors, from EPC, and the United States always focuses on the new technology and the most advanced technology also. The U.S. is the biggest tracker used for all the utility projects. It has very broad usage for the commercial or residential rooftops. So all of these actually make the U.S. market very strong, very sustainable.

For the U.S. market you have to stay in here, build up a long history and contacts in order to win this market. You don’t expect the same kind of thing could happen in other markets, even the Chinese market. So although the size of the Chinese market is bigger than the United States, sometimes the policy changes very drastically. And compared with the European market, there are a lot of a smaller countries, and each one has individual policies. It’s not like the United States, that has both the size and the stability and the sustainability.

pv magazine: So this is interesting, especially right now given that we have 25% tariffs under Section 201, and this escalating trade war with China. When you look at situations like the trade war do you see these as major problems for the U.S. market or just another road bump? How do you think these will be viewed in the longer picture?

Zhu: In the longer picture, there’s no doubt the U.S. and Chinese relationship will recover and will move on. It’s certainly a bumpy area right now. People are trying to figure it out; how we’d be able to keep possibly reducing the cost for the total system and help the solar to be broadly used in the U.S. market.

Trina deployed capacity outside China five years ago. So we supply U.S. orders from Thailand and Vietnam. That is all the preparation work that we are doing. Like I said; the United States is a long-term market. You have to keep on doing things a little bit here and a little bit there, in order to make the final result very sustainable – matching up with the U.S. market overall.

There’s no doubt that China has the biggest solar investment and the capacity also. But on the other hand the United States is very healthy on the renewable energy portfolio requirements/policies. It has very stable policies, very stable economies. I believe the market in the United States is one of the best in the world.

pv magazine: So to get to individual market segments: When you look at the residential market the commercial and industrial market and the big utility scale market for the large ground mounted plants, which of these to you and to Trina is most interesting the United States? And why?

Zhu: Currently we sell most of our product into the utility-scale market. Although we started the deployment on the distribution side and the residential market. Almost from the beginning, eight years ago, 10 years ago we began supplying the residential and the commercial side.

We work with distributors, most of the time as the major suppliers to them. Now with our solution business we’re gradually providing some system integration solutions to some of the commercial projects to help them to get the project easier to take off, lower the cost and raise the returns. The utility sector is still one of the major sectors and we are helping developers and investors to get the project settled down from year to year. Let them see the roadmaps of our technology like we mentioned before. We are not only focusing on modules as a single individual component. We are trying to put modules, trackers and inverters all together in order to contribute more to the industry.

pv magazine: So should we expect a distinct branded product from Trina the way that SunPower has its Equinox and its Oasis power plant solution? Should we expect something that’s a that’s branded like that that’s a distinct product?

Zhu: Yes, absolutely.

But we are not going to tapping to the EPC business mostly focusing on the procurement side of the EPC. U.S. EPC companies are very strong at the engineering design, at the construction resources. So we are going to partner with them but we are very good at the procurement side on the supply chain side; we have owned a tracker company since last year, as you know. And we own the module capacity, 2 gigawatt and still going up.

And so we have the chance to put all those things together and design as a whole package for the system instead of individual components because as you know the market situation sometimes is not exactly what you want when you try to buy things, to get the best from the market.

pv magazine: So is this the Trina Pro that you’re talking about.

Zhu: Yes, exactly. That’s the solution business we’re talking about. Trina Pro is one of the solution for the utility-sector projects and we do have commercial C&I teams currently working on the smaller system integration – also to help the commercial side. But Trina Pro is the major one.

pv magazine: So this is interesting because what I’ve been seeing in the industry is I’ve been seeing more of these complete solutions but also move away from EPC; for instance for solar just got out of EPC – even a lot of the developers are withdrawing from EPC. Do you see this trend as well and why do you think this is happening?

Zhu: A lot of investors and developers gradually start to be stronger and stronger so that they have the ability to do the preliminary design. Therefore a lot of equipment requirements can be settled down at the beginning stage of the project instead of the last stage of the procurement.

So back to the old times, it used to be EPC’s job to do all the designs and then buy the stuff at the end. But now people are seeing with the project to be more mature and more standardized, they are able to work with the supplier directly at the beginning to have a long term roadmap.

Because normally the design phase stars almost a year ahead of the final commissioning. So you have to know the technology one year down the road, what’s going to happen with the solar growth speed, these kind of factors have to be taking into account, when you bid the project and when you commit.

So Trina Pro is exactly for that purpose to group all the major components together, link them better, do the engineering for the compatibility issues and do the streamlining of the supply chain management so you don’t have to get the module first and then the racking arriving later to shorten your construction time.

The way we are looking at it it really helps EPC a lot also; To reduce their total EPC costs and maintain the same margin and make their work easier and less risky. So to help the project itself also.

pv magazine: This is interesting because it almost seems as the E&P are going over to the developer and EPCs are becoming more simply construction companies. Is that fair or is this something else?

Zhu: Well there’s still a lot of work that EPC Company has to do you know regarding the layout regarding the commissioning regarding the great design transformer column and all these kind of things we are trying to help from the hardware side of it.

Because a lot of time EPC company, traditionally EPC companies don’t control the supply chains. They don’t own the manufacturer. They don’t know the roadmaps down the way. They don’t know the cost trend, supply and demand situation. So by the time at the end, when they try to buy this stuff a lot of times it’s already too late.

This year is a good example. We are in an extreme shortage situation and a lot of people cannot find modules anymore. So that’s going to cost the project with a lot of risk and commission delays and put an extra cost into the project. So that’s why we are seeing these kind of costs between the major suppliers if they have a solution business together with the EPC.

Obviously we are not getting into the EPC business. It requires like you know a strong enduring force of very good construction resources – all of these kind of capabilities. It took a long time to build this also. So we are willing to work with EPC companies on the Trina Pro solutions.

pv magazine: So the ITC is stepping down after 2022, 2023 there is no more ITC or it remains at 10%. And what we’re seeing by the market forecasters is they’re expecting the U.S. market to dip after that, and Wood Mackenzie is predicting a very slow growth following this. They’re not the only market analyst which is suggesting the market will slow with the ITC at 10%. Do you see this same thing, or do you expect the market to grow more quickly? What do you see after the ITC expires?

Zhu: Well the U.S. market is a free market right now so it has a lot of healing powers. Even the policy has changed; as a matter of fact, you know as we look at the project cost that a major portion 25% is going to Section 201 tariffs. So right now the ITC is stepping down. At the same pace as the tariff. The tariff is dropping from 25%, 20%, 15% and eventually will be gone.

So that’s matching the pace of the ITC stepping down. So from the system cost point of view I don’t see a major drop. It’s going to be a major drop in matching up with the drop of the ITC. So the project returns will relatively stay the same.

On the other hand, from the demand side the renewable energy portfolio requirements are still dragging all of the investment, all the attention, all the technology towards expand the solar market. So I have strong confidence that this market will be one of the best and promising markets in the world.

pv magazine: With or without the ITC?

Zhu: With or without the ITC. Like I said; If people are interested they could extend the ITC or they could even come up with a new solution to help the project or help the market going faster.

Without the ITC we know the costs for solar came down more than 95% in the last 20 years. Right now is the way I’m looking at it, solar is cheaper than the traditional energy already, if we calculate all of the pollutions and environmental recovery cost. So energy demand is rising and solar will meet a bigger and bigger portion of demand. Right now the portion is still very small, so there is a lot of room to grow. With energy storage coming online later that will make that renewable energy even more robust and will help to fit the current requirements to meet energy demand.

Interview conducted by pv magazine U.S. Editor Christian Roselund

For a state of its size, there isn’t a lot of solar installed in Texas. In fact, according to the state’s grid operator there was only 1.9 GW of utility-scale solar online in May, when the state was getting ready to go into the season of highest temperatures and peak demand.

However, that solar played a minor yet important role in keeping air conditioning units humming across the state, according to a set of reports by the Electric Reliability Council of Texas (ERCOT) which came out yesterday.

Outlined in ERCOT’s Summer 2019 Operational and Market Review, the state’s large solar plants connected to its transmission grid supplied 1.394 GW of power during the peak on August 12. This is when the state hit its highest electric demand to date at 74.7 GW, with temperatures hitting 105 in Austin and San Antonio.

This was within 1% of what ERCOT had predicted, suggesting that the grid operator is getting quite good at estimating just how much solar will be online during peak demand. It also means that, despite the highest demand to date and nearly 4 GW of outages, the system still had 1.5 GW of capacity available for operating reserves.

This and over-production of wind meant that, despite tight reserve margins, Texas only had to declare Energy Emergency Alerts twice – neither of which was on the day of highest demand – despite the 2nd hottest August on record.

It also meant that Texas’ notoriously erratic electricity prices were kept more stable than the previous summer. As documented in ERCOT’s Independent Market Monitor Report, the system hit its peak pricing of $9,000 per megawatt-hour on August 13 and August 15, although average prices for these afternoons were below $3,000 per megawatt-hour.

Wind over-performs

Texas has a lot more capacity in wind turbines than it does in solar panels, and the real story of how Texas avoided forced outages was that wind supplied more power than expected. During the afternoon of record peak demand on August 12, the system’s wind turbines generated 50% more than the assessment in ERCOT’s resource adequacy proposals, which allowed for 2.5 GW of extra power output.

As compared to the previous summer, Texas wind produced more later in the afternoon during the summer of 2019. This means that it was better able to help meet peak demand, a phenomenon which means that peak net load frequently occurred earlier in the day than peak demand.

ERCOT’s resource forecasts give small values to most land-based wind in the West, North, South and Central parts of the state, as it is hard to rely on wind in these regions during hot summer afternoons. Coastal wind tends to blow stronger in the afternoon, so its contributions towards meeting peak demand are given a higher value.

This reliance on land-based wind could be seen in the price peaks and emergency alerts on August 13 and 15, and ERCOT has concluded that net load – defined as load minus wind and solar – is a better predictor of higher prices than peak demand.

In general ERCOT gives solar a higher capacity value and, despite hotter summers, the flood of solar projects that have secured interconnection agreements, signed contracts with off-takers and begun construction in the region are a more predictable way to meet peak demand. So while wind may have played the biggest role in saving this summer for Texas, solar played its part, and next summer is likely to have a bigger role.

A move to a new energy system based on solar, wind and batteries brings many benefits, including potentially cheaper electricity, greater reliability (via distributed generation & storage), and of course reduction of greenhouse gas emissions. But there are inevitably downsides and risks to any major change. And some of the risks we are just now learning about.

As anyone who has tried to board a plane with a Samsung Galaxy Note 7 phone knows, lithium ion batteries can be subject to a phenomenon known as “thermal runaway”, whereby they enter a self-reinforcing heating cycle that can end in a fire. This fire can’t be put out with water, which only makes the situation worse.

And unfortunately, such fires are also not limited to smartphones. On April 19, a 2 MW battery at an APS facility in Arizona exploded, injuring four firefighters and leading one Arizona regulator to state that lithium-ion creates “unacceptable risks,” and to call for a look at other energy storage technologies.

As reported by the Arizona Republic, in the aftermath of this fire, the cities of Phoenix, Peoria and Surprise have passed laws that, for the first time, require special permits and certain safety features when lithium-ion batteries are installed. These represent the first implementation of federal fire safety standards.

But industry is not waiting for the next fire. Today Energy Storage Association (ESA) launched a 43-page draft emergency response plan for energy storage facilities. This document is intended to provide model language for individual site plans to deal with everything from fires to floods and earthquakes.

But fires are the first danger mentioned. ESA notes that battery systems represent “a unique challenge” for firefighters. The document further explains that energy storage systems do not have a single point of disconnect, and that while there are disconnects that de-energize certain parts of the system, that batteries will remain energized.

This leads to multiple dangers if water is used. Not only does ESA identify the danger of a shock or arcing hazards if fire is present, but also notes that water can “react” with the chemistries present – which is true of some of the most common types of lithium-ion batteries that are currently deployed.

Ultimately, the document stresses preparation and education. As noted by ESA, local fire departments need to be informed of appropriate fire suppression methods for each energy storage site, and that if “unconventional fire extinguishers” are required, that local first responders need to be alerted to this and trained to use them.

Like fires as solar plants, fires at battery facilities remain rare. But they can still happen, and for the industry to move forward, safety needs to come first.

Utilities are feeling the heat. With concerns about the climate crisis increasing in the public consciousness, as manifested most recently by children around the world walking out of school en masse to demand action, utilities are among the companies seeking to improve the public perception of the pollution that they produce.

Over the past year, the trend has been to issue targets to reach carbon neutrality by specific dates – usually around mid-century. This began with Xcel Energy’s pledge last December to decarbonize its fleet by 2050, and was followed by pledges by Public Service Company of New Mexico and Avista in April and then Duke Energy earlier this month.

The latest to do so is DTE Energy, which last week pledged to reach “net-zero” carbon emissions by 2050 for its electric utility. However, there are several questionable details in the Michigan utility’s pledge to reduce emissions, including setting a 2005 baseline and relying on technologies which have not yet been commercialized to achieve deeper reductions.

Additionally, this pledge follows on DTE issuing a long-term plan which solar advocates say cooked the books to allow it to choose a tiny fraction of the optimal amount of solar over the next few years. Finally, the company recently pushed regulators to allow it to build a new gas plant – despite evidence that clean energy resources would be far cheaper.

All of this raises serious questions about whether DTE’s plan reflects a serious attempt to decarbonize, or an attempt to put a positive spin and conceal ongoing tactics to delay the energy transition in its service territory.

Setting of goalposts

The first questionable aspect of DTE’s pledge to reduce emissions is its choice of dates to base reductions against. Like Duke before it, DTE is choosing 2005 as its baseline. This means that in its plans to reduce emissions 50% by 2030 and 80% by 2040, it is planning to take credit for the reductions that have already happened.

According to DTE VP of Environmental Management and Resources Skiles Boyd, DTE has already reduced emissions 19% from 2005 levels, meaning that it only has 31% of the 2005 level to go do reach its 2030 goals.

However, what is even more questionable is that DTE is relying on technologies that have either not yet been commercialized or have proven to be very expensive to reach deeper emissions reductions. DTE has identified carbon capture and storage, large-scale energy storage, and modular nuclear reactors as technologies will will be “required” to reach the zero-carbon target, however it also released a chart which shows that it does not even plan to get to 60% emissions reductions (from 2005 levels) without these technologies.

This is despite a wealth of scholarship that shows that the United States can reach 80% or more wind and solar by either building extensive transmission and/or deploying large amounts of battery storage, and can do so at costs similar to what consumers pay for electricity today.

The last large carbon capture and storage project for a coal plant, the Kemper project in Mississippi, was such an economic disaster that the plant’s owner abandoned the CCS portion and switched the plant to gas.

As for small modular reactors (SMRs), Oregon’s NuScale completed the first phase in its federal design certification in 2018, but there are still five more phases in this process. As SMRs have not yet been commercially deployed, it’s not clear what they will cost or whether or not their operating characteristics will match the claims made by advocates.

Short-term versus long-term

DTE has stated that it plans to triple its renewable energy capacity over the next decade, from 1 GW of wind and solar this year to 3 GW in 2030. Additionally, CEO Jerry Norcia has stated that the utility is “doing as much as we can, as fast as we can, to provide our customers and the state of Michigan with clean energy that is affordable and reliable.”

However, in practice the utility has favored gas over renewables. Last year DTE gained approval by Michigan regulators to build a new 1.1 GW gas plant, with regulators admitting that they did not seriously consider other options. This is despite an analysis by Union of Concerned Scientists which shows that the utility’s customers could have saved $340 million if the company deployed a combination of renewable energy, energy efficiency and demand response.

And while DTE is building substantial wind capacity, solar is another matter. In August Solar Energy Industries Association (SEIA) testified that DTE Energy had “hard-coded” its preferences for resources into its models, instead of allowing the model to choose which resources would be best for its customers.

Overall, SEIA documented 16 questionable modeling assumptions, including over-estimating the cost of solar, which it says explains why DTE has chosen to build 11 MW of solar over the next five years, not the 2 GW that SEIA says would give the most cost benefit to its customers.

It is particularly notable that DTE has insisted that it will not change its near-term plans as a result of this carbon pledge, which suggests that even if it keeps to the letter of its reductions pledges, it will take its own sweet time to do so.

Many are skeptical. Energy and Policy Institute has questioned if the utility can reach these targets at all, given the choices it continues to make. Utility analyst Ben Inskeep of EQ Research has also eloquently stated that all of this pushes the bounds of credibility.

It is impossible to square the resource plans filed by utilities like Duke Energy, Southern Company, and DTE Electric with their announced goals.

You can believe their PR announcements, or you can believe the plans filed with regulators, but you can't realistically believe both

— Ben Inskeep (@Ben_Inskeep) September 26, 2019

It’s odd to be writing about an active feed-in tariff (FiT) in 2019. The policy which accelerated Germany into a 7 GW+ market annually and kick-started the global solar market had its heyday nearly a decade ago, with feed-in tariffs being introduced across Europe and Asia. This led to spectacular market growth but also dramatic crashes when the ambition of the market created exceeded these policies’ political support.

What is even more strange is to be writing about a FiT in the United States. Despite the Public Utilities Regulatory Policies act of 1978 (PURPA) serving as a model for Germany’s FiT, the U.S. market has instead been driven by the Investment Tax Credit (ITC), net metering and renewable energy mandates. The few feed-in tariffs in the United States have typically been small, regional affairs.

Among these, Los Angeles has had the largest FiT program, which was started under Mayor Eric Garcetti (D) in 2013 and which earlier this week was approved by the board of the Los Angeles Department of Water and Power (LADWP) for expansion from 150 MW to 450 MW.

Like other feed-in tariffs, LA’s FiT pays a fixed price under long-term contracts to owners of PV systems, one which is typically set at a price to incentivize building such systems. For Los Angeles these prices are generous; under the latest pricing adjustment the program will pay between 13.5 and 14.5 cents per kilowatt-hour for projects in the Los Angeles basin.

These changes now go do the City Council for final approval, and this expansion appears to be building on the momentum of a revamp of the program in 2017.

Mid-sized DG

Unlike net metering, which is typically focused on residential systems, FiTs often have their greatest impact on the market for systems larger than those on residential rooftops but smaller than the large solar farms in deserts, fields and forests.

This sector, often described as the commercial and industrial market, has struggled in recent years in the United States. Wood Mackenzie reported recently that this sector had the lowest volume of installations in Q2 2019 since the third quarter of 2016, with only 426 MWdc installed, including community solar.

Los Angeles’ FiT has supported projects from 30 kW to 3 MW in capacity, but under the changes approved this week, projects up to 10 MW will be eligible. This means that if developers want to build solar on large warehouses or industrial buildings, they won’t be limited by how big they can go.

And while the price for these projects under LA’s FiT is much higher than that of larger-scale solar or wholesale market prices, these mid-sized installations also offer unique benefits. Many of these projects are located in strategic locations to meet electricity demand locally, thus reducing the need for transmission and distribution infrastructure. This means that while the price is high, so are the potential benefits and savings for utility customers.

LADWP referenced the potential savings from deferred transmission investments in its news release, and this may explain why the program is limited to projects in the Los Angeles basin, with only a small volume set aside for communities in the Owens Valley.

Solar + storage future

It’s no accident that the feed-in tariff is being revamped at this time, as it follows on the launch of the City of Los Angeles’ 2019 Sustainable pLAn, which seeks to reach 100% renewable energy by 2045.

Even with imports and exports from rest of California, it is going to take more than solar to get to the higher levels envisioned in this plan. LADWP says that in 2020 it plans to introduce an expansion of the program to support local solar + storage projects. These can help meet the city’s evening peak demand, and LADWP has mentioned that these projects can also provide voltage control support for the grid.

However, there is still a long way to go. Despite Mayor Garcetti’s controversial order to to set a schedule for decommissioning local gas plants, LADWP has a lower portion of rooftop solar per customer when compared with the state’s three big investor-owned utilities, and it’s going to take a lot of power – both during the day and at night – to meet the city’s needs with clean energy.

Between the staff of PV Evolution Labs (PVEL) and Heliolytics, they’ve seen it all: Fires, hurricanes, tornadoes, earthquakes, and a lot of plants that have seen damage from much more mundane causes, but have suffered losses as well.

Heliolytics is a specialist in piloted aerial inspection services for solar plants, which by its own estimate has flown over 29 GW of utility-scale solar in the United States – between 1/2 and 1/3 of the large-scale solar currently online – using thermal imaging to learn more about what is going on with these systems. This includes problems that are not visible to the naked eye.

And while PVEL may be more widely known for its work testing modules, inverters and batteries, the company says that its services have been increasingly sought to investigate damage at existing power plants. And as the two provide different but often complementary services, it seems a partnership was inevitable.

“By working together, we are able to provide a more comprehensive solution for plant operators,” Heliolytics CEO Rob Andrews told pv magazine. “We have a data set, and they have a data set.”

Unseen damage

The two companies note that a main reason for their new Incident Response service is that much of the damage that solar power plants experience goes unseen. In pv magazine’s Quality Roundtable event, we’ve explored cases supplied by both companies where damage to projects is not obvious at the time of an initial inspection.

This includes “microcracking” from wind and hail damage. “Together with PVEL, we have observed widespread microcracking from hail and wind even when less than 5% of modules have broken glass,” explains Dr. Andrews.

“While months or even a few years may pass before cell cracks become hot spots and reduce system performance, it is only a matter of time before this happens,” notes PVEL CEO Jenya Meydbray.

And this sets up a big potential problem for plant operators, as insurance claims are filed once and then they are done, which can lead to significant uncompensated damages.

However, such microcracks can be detected using advanced thermography and electroluminescent (EL) imaging, such as is offered by the two companies. This can allow the companies to provide more full information, particularly in insurance claims.

And while the companies’ main clients for this work will be asset owners, PVEL’s Meydbray also notes that his company has done work for insurance companies, and that they are potential clients as well.

In fact, the service has already been endorsed by a major insurer of solar projects. “Natural disasters are on the rise as our climate changes – and so are claims for adversely affected solar projects,” notes George Schulz, Vice President – Clean Energy of Argo Group US. “To empirically assess the real impact of storms on operating assets and process claims, insurance providers need new tools like Incident Response.”

Solar Power International is easily the largest trade show in the United States. This year it came to Salt Lake City, Utah, with more than 10,000 solar professionals congregating at the Salt Palace Convention Center.

It’s not clear exactly how many people are showing up this week, but last week SEIA estimated that this year’s show would have 19,000 attendees and 700 exhibitors. With much of the 515,000 square foot-show floor occupied by crews assembling booths an forklifts moving crates yesterday this did not seem impossible.

The opening session was also well attended, with hundreds filling the auditorium. And this year the Opening Session did not feature a panel of utility CEOs as it did last year, but instead Solar Energy Industries Association (SEIA) leaders pushing a political mobilization which they say could enable solar to reach 20% of our electricity supply by 2030.

Extend the ITC

The big call by SEIA CEO Abigail Hopper and Board Chair Tom Starrs involves extending the Solar Investment Tax Credit (ITC), which is scheduled to step down at the end of this year from 30% to 26%, and decline to 10% at the beginning of 2022, while ending for individual taxpayers entirely.

This would not be the first extension of the ITC; most recently the ITC was set to step down at the end of 2016, and its extension at the end of 2015 created a runway for the industry.

However, this time SEIA is pushing for an ITC extension with a Republican trifecta in Congress and the presidency. And while the ITC has enjoyed greater support from Republicans in Congress than other renewable energy policies, it is not clear whether the inclusion of an ITC extension would trigger a veto by President Trump.

SEIA CEO Hopper noted that while the organization supports an existing bill by Senator Ron Wyden (D-Oregon) calling for technology-neutral clean energy tax credits, she indicated that a standalone ITC extension has better odds.

SEIA CEO also noted that the organization is “fighting like Hell for good policy all across the country”. And while SEIA is active in policy in most states that pv magazine has covered, beyond a significant legislative win in South Carolina it is not clear where SEIA is having significant victories.

And while Hopper has overseen a shift in strategy towards the states, it is not clear how much of the organization’s staff and budget are now going to state-level work versus the federal policy where it has traditionally focused.

20% by 2030

SEIA says that with an ITC extension and other policy changes solar could reach 20% of total electricity generation by 2030, which it describes as ambitious but achievable. We’ve taken issue with the description of this as ambitious, and yesterday got more clues as to how SEIA came up with these numbers.

During her presentation Abby Hopper showed a slide by Wood Mackenzie that shows the impact of an ITC extension, which she says would add dozens of gigawatts of solar over the next decade. However, Wood Mackenzie’s base case shows a dip in solar installations after 17 GW annually in 2020 and 2021, and for the annual market to not reach 20 GW until 2027.

No one is really sure what the market will look like if the ITC is not extended; the last year that we didn’t have an ITC for solar more was than a decade ago, when the industry was very different. Furthermore, given the rapid developments in the U.S. solar market and power market writ large, forecasting installation volumes more than a few years out is very difficult.

However, we at pv magazine find Wood Mackenzie’s forecast to be pessimistic given the falling costs of solar and solar plus storage. When you include the increased geographic presence of large-scale solar, with massive pipelines developing in Texas, Florida, the Midwest and the South, we suspect that solar and storage are going to continue to displace conventional power, ITC or no.

The political climate

SEIA has repeatedly noted that it is fighting an uphill battle, with SEIA Chair Tom Starrs noting that the political influence of the coal and nuclear industries are “disproportionate to their growth potential.” Hopper expanded on that theme, stating that solar must “fend off well-funded challenges from energy sources that are heading towards obsolescence”.

However, the political discourse on how the United States could act on decarbonization is changing. Two of the three top polling candidates for the Democratic nomination (Bernie Sanders and Elizabeth Warren) are calling for a full decarbonization of the electricity sector by 2030 or 2035, and most of the Democratic candidates have endorsed rates of decarbonization that would be unthinkable a few years ago.

In contrast to these platforms SEIA’s 20% by 2030 is not ambitious, nor would it allow solar to play the leading role in reducing carbon emissions to the level that scientists say that we need to in order to avoid a 2 degree Celsius rise in global average temperatures.

When confronted with both this disparity and that SEIA’s rate of market growth under its “ambitious” program is below historical levels, Hopper told pv magazine that the primary challenge is “taking market share from incumbents”. She also noted that “if there is additional federal support, we will welcome that.”

The subtext here appears to be that SEIA is by no means counting on a more favorable political environment. And these are the forces that SEIA is caught between – a push for rapid decarbonization on the left, but the reality of dealing with Republican dominance of a Congress awash in fossil fuel money – not to mention the Trump Administration.

We look at the past to help us prepare for the future. We study the patterns not only to attempt to predict where things are going, but to inform what actions we need to take to achieve certain outcomes.

This is particularly true of renewable energy. The U.S. solar market has grown year-over-year in eight of the past 10 years, and every year the capacity of solar on the grid and its contribution to our electricity system has grown.

And yet, after a decade of this rapid growth solar only contributed 2.4% of the electricity supply in the United States in 2018. When you add wind, the total was nearly 9%, but we will have to increase that many times over by 2030 if solar and wind are to supplant fossil fuels and decarbonize the electric grid to the degree that scientists say is necessary to keep global average temperature increases below 2 degrees Celsius.

It is natural here to ask how fast solar (and wind) – and their contribution to the electric grid – are growing. But an even more important question is what the pattern of this growth is. In this article I focus on solar, as wind has a different pattern in the United States.

Linear vs. exponential growth

Here two concepts are key: linear and exponential growth. In linear growth, a number increases by the same portion over time, as shown in the pattern: 2,3,4,5,6. In exponential growth, the number increases as a multiple of the previous number, as shown in the pattern: 2,4,8,16,32.

When talking about the contribution of renewable energy to the electric grid, there are a few key facts to keep in mind. As the capacity factor of solar is relatively stable from year to year, the volume of electricity it generates is fairly directly related to how much is installed – as long as you are installing it in (roughly) the same places. And as electricity demand is flat to declining in the United States the increase in the generation corresponds roughly to the portion of demand met.

Therefore if you double the amount of solar on the grid, you (roughly) double the electricity generation from solar, and you (roughly) double the portion of demand it meets. If you do this year after year, or even every two years, that is exponential growth.

Another important point is that growth of the market is not the same as growth of cumulatively installed capacity. If the same amount of solar were installed every year, with no market growth from year to year (flat growth), cumulative capacity – and electricity generation – would grow on a linear basis (1,2,3,4,5). But if the market grows every year, then the cumulative capacity and the electricity generated are not growing on a linear basis. They are growing faster than that.

In fact, they could be growing exponentially.

Exponential, or accelerating growth?

When pv magazine conducted its most recent long-term analysis of the increase in generation from solar and the portion of U.S. electricity demand that it met, we found that it had gone from 2 TWh to 96 TWh from 2008 to 2019 – a 48x increase over 11 years. Another way to look at this is that it was doubling roughly every two years.

This is exponential growth. But a deeper look at the numbers has us questioning what is going on. Data collected by Wood Mackenzie and Solar Energy Industries Association (SEIA) shows only around 385 MW of solar being installed in 2009, which rises to 7.5 GW in 2015. The market is clearly growing from year to year – in fact, from 2009 to 2010 it more than doubles, and more than doubles again from 2010 to 2011. But from 2011 through 2015, the market increases by the same amount – around 1.3 GW each year.

This means that cumulative capacity was growing, and was growing by an increasing amount every year. But this was not enough for exponential growth in installed capacity, because the market would have to be growing every year by an increasing amount for that to happen. Instead, while the cumulative capacity was growing every year, it was growing at a decreasing percentage over the previous year.

We at pv magazine are not sure of the exact mathematical term for this, but on the advice of Kees van der Leun of Navigant Consulting, we are calling this “accelerating” growth. And it appears that for the longest period in the past decade where we had relatively stable policy in the United States, growth of cumulative installed capacity was accelerating, but not exponential.

So for now, we at pv magazine are describing the growth in capacity/generation as “accelerating”, because of the clear pattern from 2011 to 2015. Also if given a choice of otherwise equally valid descriptions, we’re going to go with the one that is most easily supported. But whether you decide that installed solar capacity in the United States and its contribution to the electricity system are growing at an exponential or accelerating rate is really dependent on which date range you look at.

Policy matters

You may have noticed by now that we are not looking at the years 2016 through 2018, despite having data for these years. The reason for this is the markets during these years were strongly affected by national policy, in ways that we have covered exhaustively at pv magazine.

In 2016, the pending step-down of the federal Investment Tax Credit (ITC) drove a massive boom in project construction, leading to another doubling of the market – from 7.5 GW in 2015 to around 16 GW in 2016. This led to something of a “hangover” in 2017, with only around 10 GW installed. And in 2018, the process of imposing Section 201 tariffs on cells and modules at a minimum delayed large-scale project development for six months, and also caused some projects to never get built – meaning another 10 GW year.

As such, these years simply aren’t good indicators of long-term trends. But they do illustrate an essential point: solar deployment is strongly affected by policy and policy changes. In all of those years from 2009 through 2015, policy was also affecting the market – not only the 30% ITC, but also state-level renewable energy mandates, the availability (or not) of net metering, state and local incentives – even the structure of electric rates.

Looking to the future

If we are serious about decarbonizing the electricity system using solar and wind, it is important for policymakers, advocates and the solar industry to understand where the market is going. In other words, it is important to understand not only the rate of growth of the solar industry but also the nature of this growth – whether it is linear, accelerating or exponential.

If we overestimate the nature of growth – such as assuming exponential growth where it does not exist – there is a danger that we won’t implement the necessary policies to do what it takes to rapidly decarbonize. But if we underestimate the nature of growth – such as describing it as linear when it is accelerating or exponential – then we not only undermine reasonable expectations, but we are in danger of creating a self-fulfilling prophecy, as warned by the World Economic Forum in a recent report.

The data clearly shows that “hangover” years and tariffs aside, the installed base of solar in the United States is at least accelerating, if not growing at an exponential rate. As such, we should expect it to get larger in the future. That means that while it has taken a decade for solar to go from 0.1% to 2.4% of the electricity system, we shouldn’t expect it to grow an average of .23% per year for the next decade (assuming no major policy changes).

From 2017 to 2018 the portion of U.S. generation from solar grew roughly 0.5%. We should expect it to grow more than this in the future, every year. And while some may point to the phase-out of the ITC, there are many counterbalancing factors, including the increase in state-level renewable energy and clean energy mandates, the emergence of large-scale solar markets in the U.S. South, Texas, Florida and the Midwest, and the truly awesome amount of projects being planned.

However, it is also important to note that even if solar grows at an accelerating or even exponential rate every year, this does not mean that it will necessarily reach the levels needed to decarbonize our electricity system by 2030. If the portion of solar on the grid doubles every four years instead of two (still exponential growth, but slower than 2009-2018), we’ll still only be getting around 18-19% of our electricity from solar by 2030.

That is considered “ambitious” by the standards of the Solar Energy Industries Association (SEIA), but the youth of this world are rightfully demanding more than that.

The electricity sector is highly regulated and there is no free market here. Solar will continue to need a fair policy environment, but what it takes to keep deployment strong changes over time as prices fall, capital gets more comfortable with solar and developers and off-takers gain experience.

But to start, we need to be clear about what it is that we are seeing.

Friday was a big day for U.S. module manufacturing. Hanwha Q-Cells, the Korean PV maker which acquired Germany’s Q-Cells seven years ago, has officially opened the biggest solar panel factory in the Western Hemisphere, with 300,000 square feet of floor space and 650 workers.

Of course opening is always a relative term. Friday was the big ribbon cutting with officials from Korea, Georgia Governor Brian Kemp (R) and even a token presence from the Trump Administration, but the factory has been churning out modules for months; every solar factory must go through a lengthy process of equipment tests and calibration, and then will be slowly producing more and more modules (ramping) until it hits its full production volume.

Hanwha Q Cells executives report that the factory began production in January and started shipments in February, and that all three production lines are currently running. “The factory is currently producing over 10,000 modules per day and very close to the full 12,000 module per day capacity,” Hanwha Q Cells Director of Strategy and Market Intelligence Scott Moskowitz told pv magazine. “We expect to be running at full capacity by the end of the year.”

The factory will make modules with 120 half-cut mono-PERC cells in the company’s Q.PEAK DUO BLK-G6 line. These have six busbars, around 19% module efficiency and a wattage of 330-345 watts, which is not bad for what would be a 60-cell module in full-cell terms.

These modules are being sold into both the rooftop and large-scale ground-mounted solar markets. While 72-cell modules are more popular for large PV plants, some of the projects that will utilize these modules are Facebook’s new data center in Georgia.

Trump, tariffs and taxes

Greentech Media has cast this as a win for Trump’s trade policies, but there is a lot of nuance here. Four large solar factories are either under construction, ramping or have opened in the United States since Trump imposed the Section 201 tariffs: Hanwha’s 1.7 GW factory in Georgia, LG’s 500 MW factory in Alabama, Jinko Solar’s 400 MW factory in Florida, and First Solar’s 1.2 GW factory in Lake Township, Ohio – which is currently under construction.

It’s a safe bet to say that these would not have happened without the Section 201 tariffs giving a relative edge to product made in the United States. But as every one of these companies has told pv magazine, they also probably would not have happened without the changes to the U.S. tax code under the tax reform rammed through by Republican majorities in Congress in late 2017.

Also, while these factories and a the smaller ones that had held or or started back up total around 5 GW of capacity, the United States is expected to install more than 12 GW of solar this year – more than double the nation’s entire module capacity.

Also, the cell sector is almost completely missing in the United States. There are no merchant cell factories in the United States, and all of the crystalline silicon factories that have recently ramped up import cells from overseas. In fact, the one big integrated cell and module factory in the United States – the Tesla/Panasonic Gigafactory in Upstate New York – does not appear to be producing much.

As such, the minor revival of U.S module manufacturing that these factories represent does not change the fundamental nature of trade flows or manufacturing in the solar industry; the United States still overwhelmingly installs imported solar products, mostly from Asia.

Update: This article was updated at 10:12 AM EST on September 23 to include more information on the ramping of the factory.

Today the nation’s smallest state has its biggest climate protest yet. Hundreds of Rhode Island residents, including students from more than a dozen elementary, junior high and high schools met in a park and marched to an office of National Grid before holding a protest in front of the Rhode Island State House to call for greater action on the Climate Crisis.

As with any protest individual perspectives and the way they were expressed varied, but one unifying thread was the call for a Green New Deal, and in general steps to reduce greenhouse gas emissions.

“We are here organizing in Providence with people from all over the state to demand real action on climate change on the scale that climate and justice demand,” Ilan Upfal, an organizer with Sunrise Rhode Island, told pv magazine.

If our country mobilized quickly on the scale that we did after the Great Depression and Second World War, we could fully decarbonize in 10 years. Even if we don’t meet that goal, if that’s what we are fighting and organizing for and that’s what we are demanding, we can make serious cuts to emissions, and it will be day and night between that and what we are doing now.

The crowd was a mix of ages, with elderly protestors all the way down to elementary school children. This included teenagers from St. Mary Academy – Bay View, a Catholic School in Riverside, Rhode Island, whose students were given permission from the school to attend the strike and were accompanied by teachers.

“It’s something I’ve been passionate about for a long time,” 17-year old Emma Simias told pv magazine. “Climate justice is the ability for us to have a future to look forward to.”

Lagging action at the state level

Rhode Island is the state most dependent upon out-of-state natural gas – much of it extracted via fracking from the Marcellus Shale in Pennsylvania, West Virginia and Ohio. It is also the state that has seen the greatest temperature increase due to Climate Change, with temperatures rising more than two degrees Celsius.

However, the state’s actions to reduce emissions are slow. Rhode Island has an unambitious renewable energy mandate, and while Governor Gina Raimondo (D) has set a target to deploy 1 GW of renewables by the end of 2020, that includes projects under contract but not yet built. Specifically, it will include 400 MW from Ørsted’s Revolution Wind project, which is not expected to come online until 2023.

In 2018, Rhode Island got less than 4% of its electricity from in-state wind and solar – less than half the national average. And while generation from solar is growing rapidly, local installers have expressed concerns about both reductions to the rate paid under the state’s Renewable Energy Growth program, and the way that maximum system sizes are being calculated under net metering.

The state’s transportation sector is even more deeply mired in anachronism. The Rhode Island Public Transit Authority (RIPTA) has deployed only three electric buses under a pilot program, and plans to purchase a meager 16-20 more in 2021. Meanwhile, the Rhode Island Department of Transportation (RIDOT) is in the process of raiding funds from bike projects, while the state issues $200 million in bonds to rebuild a freeway in downtown Providence including adding lanes.

It is also unclear if the rather vague demands of protestors will be translated into actions to reduce emissions. But what is clear is that there is a rising movement in the state, with Sunrise Rhode Island estimating that is has around 100 members coming to meetings at three hubs.

Note: The author is a board member of the Rhode Island Bicycle Coalition

The administration of Donald Trump has made several efforts to tilt energy markets in favor of coal and nuclear power, not the least of which was an attempt to ram a coal and nuclear bailout through the Federal Energy Regulatory Commission (FERC). However, yesterday Trump’s appointees on FERC took this a step further and moved to gut a law that has spurred substantial renewable energy development.

Yesterday FERC moved to adopt a proposed rule that would make several changes to the Public Utilities Regulatory Policies Act of 1978 (PURPA), which taken together would greatly weaken the law. The biggest changes would remove the fixed-price nature of PURPA contracts, by giving states one of several options.

1. Voiding the fixed-price nature of energy payments in PURPA contracts, and instead setting payments to market prices under one of two options
2. Allowing states to alternatively keep a fixed-price contract, but set it to what they think the energy price will be when the power is actually delivered, not a utility’s current “avoided costs”.
3. Allowing states to set prices for PURPA contracts based on competitive solicitations

The proposed rule would also shrink the size of projects that utilities must buy power from under PURPA contracts from 20 MW to 1 MW, and make other changes. The proposal will now be published in the Federal Register, which will initiate a 60-day comment period.

Administration over-reach?

Richard Glick, the one Democrat on FERC, issued a partial dissent. Glick described this as the administration moving to “gut” PURPA and primarily argued that as PURPA is a federal law, changes to it should be made by Congress.

Whether PURPA’s goals remain relevant is a decision for Congress, not an administrative agency. The Commission should not be seizing the reins from Congress in order to isolate an important debate about national energy policy within an independent regulatory agency.

However, Glick’s concerns about process do not appeared to be shared by his fellow commissioners, one of whom, Bernard McNamee, was an outspoken advocate for fossil fuels before being appointed by President Trump to FERC.

However, this move by a federal agency to make substantial changes to a federal law could open up the ruling to legal challenges. “We are currently reviewing the NOPR FERC released to ensure that FERC continues to support the development of renewables, as required by law,” stated Alex Hobson, the VP of communications at American Council on Renewable Energy.

Market impacts?

Solar Energy Industries Association (SEIA) was among those who condemned the ruling, stating that it gives too much power to utilities. Per the statement by VP of Regulatory Affairs Katherine Gensler:

Rather than focusing on PURPA’s goal of ensuring competition, this proposal would have the effect of dampening competition and allowing utilities to strengthen their monopoly status, to the detriment of customers… the proposed rule is a move away from competition and we hope FERC rethinks the most harmful portions of this proposal. 

However this proposal also comes as PURPA is on the wane as a driver of solar deployment. Wood Mackenzie estimates that 1.7 GWdc of solar was put online through PURPA in 2016 and 1.6 GW in 2017, but only around 700 MW in 2018.

This was largely the result of state-level policy changes. PURPA gives a lot of leeway for state-level implementation, and in many states where the policy was driving significant solar market growth utilities pushed state regulators to make changes to slow the deployment of solar.

Among the states where PURPA underwent significant changes is North Carolina. There a compromise between the solar industry and the state’s utilities, including Duke, led to the adoption of a system based on competitive solicitation. And while this kept the utilities from entirely killing the law, under this system the state’s large-scale solar market is much smaller than it was before.

Colin Smith, a solar analyst at Wood Mackenzie, says that most of the remaining PURPA development for solar is in states like South Carolina and Michigan where regulators are compelling utilities to let “lingering” projects come online, and that this could total around 700 MWdc annually through 2023.

Since FERC’s proposed ruling will take time to complete and implement at the state level, a lot of those projects could end up being built before any federal changes take effect.

Update: This article was updated at 1:15 PM EST on September 20 to include more recent figures on solar deployment under PURPA by Wood Mackenzie, which increased the total MW in 2018, as well as analysis.  

A number of academics and energy writers are expressing concern about the disappearance of data and the slow rates of publication of reports on websites run by the federal government under the Trump Administration.

First it was the SEAMS project by the U.S. Department of Energy’s (DOE) National Renewable Energy Laboratory (NREL), which has not yet been published, which energy writer Peter Fairley says was due to it being “blocked” by political appointees at DOE. DOE has denied this, and says that the publication is still being developed.

Then it was the dataset for a paper on high levels of renewable energy which got pulled from the National Oceanic and Atmospheric Administration (NOAA) site. And today, pv magazine has discovered that The Open PV Project, a site which had real-time tracking of costs for distributed solar, is offline.

This appears to be the continuation of a slow decline. Solar Energy Industries Association (SEIA), which helped to found Open PV, says that Lawrence Berkeley National Lab was supplying most of the information for Open PV, and that it hasn’t been uploading data recently.

SEIA also says that the site “never really worked out”. “It was a great resource for many years that provided great visualizations,” reads a statement by SEIA. “Unfortunately, the crowdsource strategy never really panned out and OpenPV never had anything close to complete information on PV deployment.”

NREL says that the project had been discontinued since June. “NREL discontinued the OpenPV project in June because OpenPV wasn’t able to keep up with the rapid pace of the PV market and continue to provide good, timely information and data,” explains Wayne Hicks, a public affairs specialist at NREL.

Hicks also says that the design of the site as a Wiki didn’t really work out.

As the market developed and the project evolved, we found we were able to get more complete data by collaborating with Lawrence Berkeley National Laboratory (LBNL) under their Tracking the Sun effort. During the past couple of years the rationale for maintaining OpenPV as a separate application became difficult to justify due to parallel and superior data collection efforts being conducted by staff at LBNL.

Also, while the removal of the site was a surprise, NREL and SEIA note that the LBNL data is still available on the Tracking the Sun site. 

However, this doesn’t help independent researchers like Dr. Christopher Clack of Vibrant Clean Energy, who says that he is among the researchers that were using Open PV data for his work:

It is important for us to keep up to date with installation rates and prices of solar across the USA to calibrate the modeling we do in WIS:dom for the evolution of the grid as renewables are integrated. This is integral as a complement to the EIA, FERC and other data sources for corroboration and validation.

Update: This article was updated to include a statement by NREL and modified to reflect this information at 10:15 AM EST on September 20.

EnergySage’s Solar Marketplace Intel Reports provide yet another view into the evolution of the rooftop solar industry. As the company’s online marketplace is only a small portion of the overall behind-the-meter market, this report does not provide as definitive of data as those by the U.S. Department of Energy’s network of national laboratories. However it complements these, data from the state of California and quarterly reports from large publicly held companies in giving a more full understanding of market trends.

The latest Solar Marketplace Intel Report starts with a shocking number: the average price for PV systems quoted through the EnergySage online solar marketplace in the first half of 2019 had fallen to $2.99 per watt-dc. This is a decline of more than 4% versus a year ago, and 23% less than four and a half years ago, when EnergySage began counting.

And, if you look at the distribution of costs, this shows that the due to the data being skewed somewhat by more expensive systems, many systems were substantially less expensive than this.

This trend matches that shown in Lawrence Berkley National Laboratory’s Tracking the Sun series. The latest version of Tracking The Sun, published earlier this month, shows a median system price of $3.70 per watt-dc across the United States in 2018. While this is 24% higher than EnergySage’s quotes, it shows a 5% decline from 2017 to 2018.

The third-party exception

However, neither the Solar Marketplace Intel report nor Tracking the Sun show all solar installations; chiefly Tracking the Sun excludes all solar sold under lease or power purchase agreement arrangements, dubbed “third-party-owned” solar. Likewise, EnergySage excludes data from Sunrun, Vivint and Tesla, which are the three largest third-party solar providers, and, with the exception of SunPower and its dealer network, the three largest companies in the residential space.

Tracking the Sun shows prices third-party systems tracking closely to “host-owned” systems, but Berkeley Lab’s data stops at 2018. In 2019, costs have been increasing at both Sunrun and Vivint, which are the only solar companies that provide system price data as part of their quarterly results. And it is unclear how much these costs are being passed on to customers.

System costs at Sunrun increased 6% in the first quarter of 2019 and 2% in the second quarter over full year 2018 levels. Vivint saw an even higher increase in costs, with prices growing 7% year-over-year in the first quarter and 10% in the second quarter, to rise to $3.56 per watt. In both cases, rising sales, general and administrative costs were the main driver.

These rising costs are likely to have inspired Tesla’s move to online sales, which has allowed it to slash costs to below $2 per watt for residential systems. However, it remains to be seen if this move will turn around the fortunes of Tesla’s share of the rooftop solar market, which has plummeted.

And despite rising costs the market share of both Sunrun and Vivint  are increasing. This is happening even as the total share of third-party solar has fallen sharply due to the contraction in Tesla’s sales.

Falling costs

It’s important not to read too much into EnergySage’s data, as the prices listed are the prices of quotes, not the final systems installed, and it is possible that these prices were higher. However, the trend from both EnergySage and Berkeley Lab is clear: residential solar continues to get cheaper.

There remains a big question mark around the third-party solar model, and whether or not companies in this space can contain the rising costs that have been seen so far this year, which is particularly important given the trend of ongoing assaults against net metering. The basic model of third-party solar companies, which is dependent on long-term financing, may insulate them somewhat from short-term trends. But eventually even they have to turn a profit.

Meanwhile, the online solar marketplace model continues to grow. EnergySage estimates that 3-4% of all of the residential solar in this United States installed last year was sold through its site, and the company says that it is seeing “near triple-digit growth” from year to year.

It’s all in the numbers and the context for those numbers.

In the zero-carbon plan that Duke released yesterday, the nation’s largest owner of power plants and electricity sector emitter of CO2 also set a near-term goal to reduce its carbon emissions 50% by 2030.

However, the fine print shows that this is a reduction from 2005 levels. Duke, by its own count, has already reduced emissions 31%. So this is actually a pledge to reduce emissions a further 19% by 2030, which was noted by a prominent energy writer on Twitter.

It also means that Duke is about halfway to its 2030 goal already.

If you're judging from today, it's more like they're cutting a quarter of their carbon emissions by 2030.

— Gavin Bade (@GavinBade) September 17, 2019

This is but one of many of the details that suggests that Duke’s much-touted pledge could be an attempt to put a glossy shine on the foot-dragging that it has engaged in regarding renewables in the service area of its subsidiary utilities in the Carolinas, Florida and Indiana. This is definitely how the plan has been greeted by some advocates.

While the American Council on Renewable Energy (ACORE) welcomed the pledge, local group NC WARN described it as “a scandalous deception foisted upon the news media, the public and public officials such as Governor Cooper.”

“Pathetic commitment to renewable energy”

Duke has pledged to “at least double our portfolio of solar, wind and other renewables by 2025”, but this includes its competitive generation arm. Duke estimates that this business, which includes Duke Energy Renewables, had about 3 GW of wind, solar and other renewable energy generation at the beginning of 2018. The company plans to double this by 2025.

The service areas of its subsidiary utilities look different. By the end of 2019, Duke expects its subsidiary utilities to own around 500 MW of non-hydro renewables, and to double this to 1 GW by 2025. In addition the utility says that it expects to have contracts with another 4 GW of renewable generation by the end of this year, and to grow this as well.

The totals provided by Duke are not clear, but there is a lot more information in the long-term plans of its utility subsidiaries, which are spread across four states. And these look very different from utility to utility.

Duke Energy Florida, like all other large utilities in the state, has followed the lead set by NextEra-owned Florida Power and Light and is building a significant amount of solar in its service areas.

The Carolinas are another matter. In its latest long-term plan, Duke is planning to build 4.8 GW of solar and solar plus storage in North Carolina, but this is spread over 15 years and would only get Duke’s two North Carolina utilities to 8% wind, solar and other non-hydro renewables by 2034 – less than the national average in 2018.

Meanwhile, in Indiana, Duke is planning to add no solar until 2023 – which means that it would not be taking advantage of the federal Investment Tax Credit (ITC) for nearly all of the solar that it plans to deploy. This all adds up to what NC WARN is calling a “pathetic commitment to renewable energy and battery storage”.

CH4 vs. CO2

What Duke is planning to build to meet its relatively unambitious 2030 target is gas, and lots of it. Energy and Policy Institute has calculated that Duke’s latest long-term plans for its utilities in the Carolinas and Indiana feature nearly 15 GW of new gas-fired power plants, with plans coming online as late as 2034.

And while Duke could merely switch its coal-fired fleet over to gas and achieve its relatively unambitious 2030 target of a further 19% reduction in CO2 emissions from 2005 levels, CO2 is not the only greenhouse gas. In its statement, NC WARN addressed emissions from methane (CH4).

Duke’s continuing (and successful) deception seeks to confuse people by referring to “carbon” emissions when they mean “carbon dioxide.”  Since burning gas emits less CO2 than coal, Duke claims it’s a climate leader because it is replacing coal with gas, conveniently ignoring the massive emissions of methane from every stage of the natural gas lifecycle.

The U.S. Environmental Protection Agency (EPA) identifies methane as being 25x as powerful a greenhouse gas as compared to CO2, and it is even more powerful on a shorter timeframe. And as noted by NC WARN, fugitive methane emissions could make it such that there is limited climate benefit from switching from coal to gas, which was highlighted in a recent report by Brown University looking at emissions in Rhode Island.

Holding on to nukes & coal

In addition to Duke claiming climate benefits by only looking at CO2 and not CH4, the utility’s long-term plans have made it clear that it plans to keep some of its coal and nuclear plants online for unheard-of-timelines.

Duke has held on to its coal plants with a particular stubbornness, with plans to run some of these until 2048. The power company has referenced its 11 GW of nuclear generation in the Carolinas as being “central to our ability to meet these goals,” and in the past has planned to run its nukes as long as 90 years – several decades longer than any nuclear power plant has ever operated.

In announcing its carbon reduction goal, Duke has simultaneously made the excuse that the delayed phase out of its coal fleet is dictated by the need to “to protect customer rates and reliability”.

It’s hard to find a justification for either claim. Duke has failed to even model retirement of coal units in North Carolina that are clearly no longer economic, and was recently ordered to do so by state regulators. In terms of reliability, a wide variety of studies have found that the United States could be served by at least 80% zero-carbon electricity sources without any decline in quality of service.

Overall, it appears that Duke has been successful in defining the terms of its commitment in such a way as to make limited progress on renewable energy, delay closure of coal plants, make questionable assumptions about nuclear plant lifetimes, and invest heavily in gas while ignoring the methane issue. As such, there is a big question as to whether or not this is progress in any terms except those of public relations.

Update: This article was updated on September 19 at 1:08 PM EST to include additional information provided by Duke on its renewable energy plans.

Alabama Power is about to join the big leagues for solar + storage. Earlier this month the Souther Company subsidiary asked state regulators for permission to procure power from 400 MW of solar and energy storage, along with plans to add new gas turbines to existing plants, acquire a new plant and enter into a new contract for more gas.

The five new solar projects would be located in Calhoun, Chambers, Dallas, Houston and Talladega Counties, and the power contracts that Alabama Power is seeking approval of would bundle the solar and battery costs into a single payment structure.

These projects are the result of a renewable energy solicitation that Alabama Power filed earlier. It is not clear when these projects will actually be built; however it is possible that this information is buried somewhere in the 342 page-filing and that we at pv magazine simply missed it.

These five projects would more than double the amount of solar installed in the state, which Solar Energy Industries Association (SEIA) put at 283 MW as of the second quarter of this year.

This request from Alabama Power comes at the same time that it has put out a long-term plan which is so heavily redacted that it is barely readable, and which was openly mocked on Twitter.

What a waste of ink. #badIRP #energytwitter pic.twitter.com/kS5e8J59nX

— Simon Mahan (@SimonMahan) September 16, 2019

SunSystem Technology acquires fellow solar O&M provider, Power Overhaul – “SunSystem Technology (SST), a California based solar O&M and asset management company  has acquired fellow solar O&M provider from New Jersey, Power Overhaul for an undisclosed amount. This deal, says SST, solidifies its position as the country’s third party residential service provider as both the companies together have serviced more than 160,000 residential and commercial systems across 20 US states. With Power Overhaul as part of the company, SST will expand its presence in the US solar O&M market. It will also help the companies unify their operations and field technicians of both the entities which will provide additional resources to partners, solar site owners, and portfolio owners.” Source: Tai Yang News

NYSERDA announces completion of New York’s largest battery – Key Capture Energy’s new battery system is complete, and it, in all of its 20 MW glory now takes the cake as the largest battery in the state. The battery is likely 80 MWh, though that figure was not shared. Key Capture Energy’s project will help balance electric load and generation by storing and discharging power based upon the changing needs of the grid. This project represents a respectable dent in the 1,500 MW of energy storage mandated by Governor Andrew Cuomo (D) by 2025. Source: NYSERDA

Frank DeRosa joins 8minuterenewables – “8minute Solar Energy announced today that solar energy development veteran Frank DeRosa has joined the Company as Senior Policy Advisor. A founder and former CEO of NextLight Renewable Power, DeRosa was also General Manager for the Americas at First Solar, where he and his team developed over 5,000 MW of utility-scale solar energy power plants… DeRosa’s onboarding comes at a critical inflection point—both for 8minute Solar Energy, and for the solar industry in general. “With solar energy prices finally dipping below the cost of natural gas and coal,” DeRosa says, “we no longer have to choose between affordability and sustainability. It’s an exciting time for change-makers, and I’m thrilled to be joining the best in the business.” Source: 8minute Solar Energy

Kentucky PSC allows more time for comments on new net metering rates for electric utilities – “The Kentucky Public Service Commission (PSC) said this week it will allow more time for comments on implementing a recently passed law that would change how electric utilities bill net metering customers for their services. Earlier this year Kentucky Gov. Matthew Bevin signed into law Senate Bill 100, legislation that alters the way utilities will credit retail customers who generate electricity from renewable resources like solar panels. The law goes into effect on Jan. 1, 2020. The original net metering statute provided credits at the full retail rate, using a bi-directional meter that reflected whether a customer was producing more or less electricity than was being used, the PSC said. The customer bill reflected the net usage. Utility companies have argued that non-solar customers have been essentially subsidizing net metering customers.” Source: Daily Energy Insider

Green Mountain Power and Tesla partner for cheap home solar + storage deal – “Vermont homeowners with Green Mountain Power can now buy solar and Powerwall together at an incredibly low price. A financed 6 kW Tesla solar system, two Powerwalls and utility fees are all fixed as low as $150 per month – the best value for clean and predictable energy for years to come. Complete the sustainable lifestyle with a rebate of $1,500 off a new Model 3 and complimentary home charging equipment.” Source: Tesla

Tesla removes solar removal cost for September – Via a thread of tweets dating all the way back to mid-August, CEO of Tesla, Elon Musk, announced that the company has waived the $1500 solar removal fee requirement for customers wishing to rid themselves of their system. The fee is waived for the rest of the month of September. Source: Elon Musk

We’ve been expecting this for some time. At the beginning of the year, pv magazine reported an unprecedented volume of solar projects in the interconnection queues of six grid operators, totaling 139 GWac. We’d missed one (Southwest Power Pool), which would have brought this total to 154 GWac.

And now, it appears that these projects and others in the South and Mountain West – areas which do not have independent grid operators – are beginning to move forward with power contracts and even steel in the ground.

According to the latest U.S. Solar Market Insight report from Wood Mackenzie and Solar Energy Industries Association (SEIA), at the end of the second quarter the volume of large-scale solar projects under contract across the United States had ballooned to 37.9 GWdc, with 8.7 GWdc of these currently under construction. This is in part the result of 11.2 GWdc of new projects that have won contracts in the first half of this year.

These numbers are also supported by data from the U.S. Department of Energy’s Energy Information Administration (EIA). EIA is reporting 1.4 GW of PV module shipments in June and 1.1 GW in July – the highest monthly volumes since November 2018, when developers were frantically importing modules to avoid the pending tariffs under Section 201.

A slow Q2

But just as the sea before a large wave can be calm, Q2 2019 installation numbers were unimpressive. The United States only installed 2.1 GWdc of solar during the quarter, a 7% year-over-year contraction.

This was highly uneven from sector to sector. The non-residential sector – where Wood Mackenzie lumps together commercial and industrial, non-profit, government and even community solar arrays – looks to fall for the second straight year. Only 426 MWdc was installed during Q2, less than Q1. Wood Mackenzie blames policy changes in California, Massachusetts and Minnesota for this decline.

However, the utility-scale sector is relatively strong, with more than 1 GW installed during the second quarter. And residential solar installations are showing the continuing rebound of that sector after the crash in 2016 and 2017. Overall, residential solar installations were up a cheerful 8% year-over-year, despite continued contraction at Tesla/SolarCity, which was at its height responsible for 1/3 of the total residential market.

Geographically, there were no big surprises. California led again, with Florida coming in second (by a wide margin) and North Carolina third. However, later in the year we can expect higher installation volumes in Florida and perhaps Texas, where project development is booming.

Looking forward

Of the massive wave of utility-scale solar, many of these solar projects are not expected to be completed this year. The federal Investment Tax Credit (ITC) steps down from 30% to 26% from 2019 to 2020, however if contractors have begun construction by the end of 2019 they can still claim the full 30% credit. Wood Mackenzie is forecasting that a total 12.6 GWdc of solar will be installed this year, and has reduced its utility-scale forecast due to completion of many projects being pushed out to 2020 or later.

However, Wood Mackenzie is increasing its 2020 and 2021 forecasts, with 17.6 GW expected in 2021 and nearly that volume in 2020, as projects come online for the final hurrah of the 30% ITC.

Wood Mackenzie is expecting a slight dip again in 2022, but it is important to note that the further out that projections get, the more uncertain they are. And if one thing is true of the forecasts of market analysts, it is that they tend to go up over time more than they go down.

It’s no secret that the Trump Administration “digs coal.” The evidence that this administration is trying to stack the deck in favor of fossil fuels (and nuclear power) is overwhelming; from the appointee of a former coal lobbyist to run the Environmental Protection Agency (EPA), to the ham-fisted attempt by Energy Secretary Perry to ram a coal and nuclear bailout through the Federal Energy Regulatory Commission (FERC), to the appointment of a former propagandist for the fossil fuel industry to a seat at FERC.

The Trump Administration has also attempted to suppress information on the Climate Crisis, including removing the page on climate science from the EPA website and removal of references to climate change on other parts of the EPA website and documents.

However, the Trump Administration now appears to have taken this another step further, and removed a study showing that the United States can get the large majority of its electricity from renewable energy from the website of the National Oceanic and Atmospheric Administration (NOAA).

Dr. Christopher Clack is a “joint first author” of Future cost-competitive electricity systems and their impact on U.S. CO2 emissions, which finds that the United States can get 79% of its electricity from non-emitting sources (wind, solar, nuclear and hydroelectric power) at a lower cost to consumers than today, without deploying batteries. This feat would be accomplished primarily through the buildout of a nation-wide high voltage DC (HVDC) network.

Note that our #NEWS study data has been removed from the @NOAA website. Luckily the paper is still free and available on our website or @NatureClimate! https://t.co/rX8ZBMnV5V

— Christopher Clack (@DrChrisClack) September 13, 2019

Dr. Clack and every other author of the paper were affiliated with NOAA’s Earth System Research Laboratory at the time of publication. He says that he noticed that the study was not at its URL on the NOAA site around a month ago. The paper was published in 2016, and internet archives indicate that the study was last accessed on August 2017.

However, NOAA has not removed all references to Future cost-competitive electricity systems, as there is a press release on the site dated January 2016 which discusses the work. However, all links on that page that go to the study or further discussion of the work are dead.

In an email to Dr. Clack, NOAA noted that the work was no longer funded and suggested that it had been removed to “free up resources” – including erasing three years of weather data and scenario results that Dr. Clack says other scientists were trying to access for their research.

Fortunately, Future cost-competitive electricity systems is still available for free on the website of Dr. Clack’s energy forecasting company, Vibrant Clean Energy.

“Blocking” SEAMs?

One energy writer says that this is not the first time that the Trump Administration has blocked science on the move to a future powered by renewable energy. Peter Fairley, writing for IEEE Spectrum, alleges that “political appointees” at the U.S. Department of Energy blocked publication of a study by its National Renewable Energy Laboratory (NREL) that looked at potential integration of the Eastern and Western U.S. grids via high-voltage DC lines.

Plenty of references to the SEAMs study can be found online, but no final report, and the fate of these two studies is generating a great deal of concern in the energy community.

To state the obvious: This is not how federally funded science is supposed to work.

8/

— russell gold (@russellgold) September 16, 2019

Several days after the publication of this article, DOE responded to pv magazine’s request for comment on Fairley’s allegation, stating that SEAMS had not been blocked, but instead expanded, and that it expects to publish initial results in 2020 and the full report in 2022. Per the statement by DOE:

DOE career staff reviewed preliminary results and saw an opportunity to strengthen the study by expanding the project to model and analyze additional scenarios. This includes refining methods and data parameterization for improved modeling of transmission congestion within capacity planning tools and grid operations models. The improved characterization of congestion through this strengthened scope will model how this transmission expansion can contribute to reliability and resilience in the future grid.

Update: This article was updated at 4:30 PM EST on September 16 to cite an explanation from NOAA emailed to Dr. Clack as to why his study and years worth of data had been erased from the site. It was further updated at 10:25 AM on September 20 to feature the response by DOE.

As industries mature, companies consolidate. Little businesses get bought up by big ones, and sometimes two smaller companies join forces to build on each other’s strengths. In clean energy, this process has included acquisitions of promising companies by oil, gas and utility companies, such as Shell buying up Silicon Ranch and Total buying SunPower.

Software is no exception, and this morning Energy Toolbase and Pason Power announced that they are combining their business to offer a more complete suite of solutions that they say will allow solar and energy storage developers to more efficiently develop and deploy projects.

But similar to the trend in progressive married couples, the new entity will retain both the Energy Toolbase and Pason Power brands, while filing taxes jointly.

As niche companies in a nascent industry, neither of these companies are particularly large, and the combined workforce is only 45 employees. However, there is a much larger entity in this picture: Pason Power’s parent company, Pason Systems, a Canadian supplier of data management systems for oil and gas drilling which brought in around $230 million in revenues last year.

This week, Pason announced a $20 million investment to gain a majority interest in Energy Toolbase, and this appears to be part of a larger strategy of diversification for Pason Systems. “With the combined capabilities of Pason Power and the Company, and building on Pason’s deep data management expertise, we are positioning ourselves for meaningful growth and presence in the solar and energy storage market,” notes Pason Systems President and CEO Marcel Kessler.

Pason Systems will also provide manpower to the new team, with Pason Power Managing Director Enrico Ladendorf estimating that they will leverage an additional 20 employees from the parent company, as well as being able to leverage Pason Systems’ service network and help desk teams of roughly 355 people, and R&D department numbering around 160 employees.

The end goal here will be to offer better, more complete software, and a joint press release speaks of a “shared vision” to simplify the complex project estimating and asset control workflows that developers and asset owners have to deal with.

Both companies will be exhibiting at the Solar Power International Trade show September 23-26 in Salt Lake City.

Correction: This article was corrected at 11:15 AM EST on September 13. We originally stated that Shell had bought SunPower, when in fact it was Total. The change has been made and we regret the error.