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Highlights of SEIA Webinar Coronavirus — Implications for the U.S. Solar Industry

Posted by Allison Ruedig on Mar 26, 2020 8:18:08 PM

On Friday March 20th, SEIA representatives hosted an online meeting for solar professionals with updates on: (1) possible implications of COVID-19 for the solar industry; (2) actions SEIA is currently taking on behalf of the solar industry and its workers; and (3) resources for solar professionals to help their businesses and employees.

Here’s a summary highlighting the main points addressed in each section of the webinar:

1. Keeping People Safe

“It’s really important that we keep the health of our workers at the forefront of our thoughts,” president and CEO of SEIA Abby Hopper stated. She stressed the need to obey all public health orders and mandates during this time of emergency so that solar workers and the general public can remain as safe and healthy as possible.

What You Can Do

SEIA’s next priority is advocating to protect solar workers’ businesses and livelihoods at both the state and federal level.

“We understand that this is critically important to you as business owners, not just as people in the solar industry,” said Erin Duncan, Vice President of Congressional Affairs.

2. Advocating for Solar: Federal Update

SEIA’s next priority is advocating to protect solar workers’ businesses and livelihoods at both the state and federal level. 

“We understand that this is critically important to you as business owners, not just as people in the solar industry,” said Erin Duncan, Vice President of Congressional Affairs. 

Short-Term Federal Advocacy

Erin Duncan, Vice President of Congressional Affairs, and Jeremy Woodrum, Director of Congressional Affairs, summarized the federal actions taken as of March 21, 2020:

  • The President has signed two stimulus packages; both are largely focused on immediate public health concerns.
  • The Families-First Coronavirus Recovery Act includes early relief measures for small businesses.
  • Congress is currently negotiating a third relief package with more economic stimulus measures expected.

While solar businesses have not been specifically named in these packages, SEIA has supported early small business relief measures included in the Families-First Coronavirus Recovery Act such as small business loans and government-subsidized paid leave.

“Since 75% of solar businesses are considered small businesses (under 500 employees), we support all broad-based proposals that will help small businesses,” explained Jeremy Woodrum.

What You Can Do

This survey provides SEIA with invaluable data to help convince members of Congress that action is needed specifically for members of the solar industry.

Long-Term Federal Advocacy: SEIA’s 3 Main Asks

“Due to the disruption of work time and supply chains, many solar companies will not be able to take full advantage of the 26% ITC credit this year,” said Jeremy Woodrum. “One of our top priorities is extending the ITC so that solar companies can make up for that lost opportunity.”

Specifically, SEIA’s three main federal policy proposals are:

1. Launch a program to provide a choice of existing ITC or direct cash payments in lieu of the ITC for all qualified solar energy projects for the length of the ITC period.

2. Pass a multi-year extension of the solar ITC and postpone the corresponding placed-in-service deadlines.

3. Extend the Safe Harbor agreement to accommodate all equipment delivered by the end of 2020 and 2021.

What You Can Do

3. Advocating for Solar: State Affairs Update

Sean Gallagher, SEIA’s Vice President of State Affairs, presented a summary of COVID-19’s impact on solar at the state level:

  • Most state legislatures have suspended operations until further notice.
  • Most regulatory agencies are operating virtually (work-from-home). See SEIA’s guide to, and examples of, virtual solar permitting processes.
  • Most state actions are currently focused on public health rather than economic recovery.
  • SEIA is currently advocating for inclusion of solar businesses in defined groups for relief and special access to financing.
  • The National Conference of State Legislatures provides daily updates on state-level COVID-19 containment measures—check it regularly for all states in which your business operates.

Solar + State Shelter-In-Place Orders

  • More states are moving towards shelter-in-place mandates, which allow only essential services to continue in-person.
  • SEIA is working with state legislators to see if solar projects can be included in essential services.
  • Check SEIA’s page for regular updates on each state-mandated business closure, and how each mandate affects solar business activities in that state.
  • SEIA is currently developing guidance around such orders as they affect non-essential businesses (for example, how to move more solar activities online or over the phone).
  • Currently, SEIA continues to analyze the DHS COVID-19 recommendations (upon which most state orders are based, such as California) before finalizing guidance.
  • The details of shelter-in-place orders vary from state to state, so carefully review those for each state in which you operate.

4. Tax and Legal Implications of Supply Disruptions

John Marciano, partner of Akin Gump Strauss Hauer and Feld LLP, addressed some concerns about the effects of supply disruption on solar projects and contracts.

His response to the main question, “Are disruptions to continuity from COVID-19 covered under the majority of solar contracts?” was a qualified yes.

“Most current solar projects were begun before Dec. 31, 2019, far before the global impact of coronavirus could possibly be predicted by most people,” he explained, “But review the Force Majeure clauses in your solar contracts. In most cases, epidemics such as COVID-19 will be covered, but it’s best to be sure. Also, remember that all solar projects finished before 2024 still count for the ITC credit.”

He pointed out that to be covered by most contracts, the only gap in service must be caused by COVID-19 effects.

Long-Term Optimism for Solar Industry

Solar has become one of the strongest industries in the nation within the last decade, and SEIA is working to keep it strong. Jeremy Woodrum stated, “SEIA, with the help of our survey, will continue to tell the positive story of solar in this country: that strong, clean renewable energy is supported by 90% of Americans, and we have the workforce to show for it. We will keep advocating for the solar industry to recover, maintain, and grow.”

Topics: solar policy, solar industry

Should I Point My Solar Panels West to Optimize for Afternoon Peak TOU Rates?

Posted by Andrew Gong on Mar 13, 2020 6:00:00 AM

Here at Aurora, we like to tackle hard questions. One question we see often is: “Given that electricity rates are higher from 4 - 9 pm in California, should I place my solar panels facing west instead of south to maximize savings?”

In this post we will dive into why west-facing panels might be more advantageous than south-facing ones, and provide recommendations based on your location and how your peak time-of-use (TOU) rate works.

Context: Moving West in California

Aggregate Demand and the Duck Curve

The three main investor-owned utilities in California have been utilizing peak TOU rates 4 - 9 pm since late 2017; customers are charged more for the electricity they use during the late afternoon and evening hours. Prior to this, peak hours in the middle of the day—between 11 am and 6 pm—were most common.

The peak hours shift was driven by aggregate demand on California’s grid. Prior to the early 2010s, homeowners and businesses used the most energy in the middle of the day and early evening. Midday peak-pricing provided the financial incentive to reduce energy usage or shift loads to non-peak hours. Since then, the falling cost of solar has drastically shifted the total demand on the grid as seen in the infamous duck curve, pushing the peak demand, and moving peak-pricing to early evenings.

Source: CAISO. California’s “Duck Curve” shows the low mid-day net demand on the California electricity grid after solar and wind generation is accounted for. The low mid-day trough and steep afternoon ramp are part of why time-of-use rates have peak pricing between 4pm and 9pm. 

Directional Variation

Taking a look at the energy production of a south-facing system in the Los Angeles area, about 87% of its summer energy is produced during off-peak hours and 13% is during peak hours.

 

Chart showing a PV production curve for a south-facing system; only 12.6% of energy is produced during peak TOU hours.

If we take the same system and rotate it to face a different direction, we estimate that you can get up to 20% of that system’s energy produced during peak hours, but the total production (yield) from the system is lower. The tradeoff is having more peak-hour energy at the expense of having less total energy; the peak yield of a system in this location at an azimuth of 190, just slightly west of south.

Chart showing energy yield (kWh produced per W per year) and the percent of production that’s during peak hours. Maximum energy yield is around an azimuth of 190 degrees. The most on-peak kWh production occurs facing west, but the overall yield is substantially lower.

Net Metering Valuation

In standard net metering policies, energy production from the PV system can be assigned a dollar value based on the utility rate at that time*. For example, producing 2 kWh in an hour with a rate of $0.15/kWh provides a credit of $0.30, and producing 2 kWh in an hour with a rate of $0.35/kWh is valued at $0.70. It’s important to understand the time-dependent production profile of a PV system, not just daily total yields.

Taking our south-facing production curve from above, about 12.6% of energy is produced during peak hours, but that energy is valued at nearly double that of off-peak energy. As a result, 21.2% of the value of the energy from the PV system comes from on-peak production.

Chart showing how the on-peak energy produces a greater value to the homeowner than off-peak energy, thanks to the peak TOU rate.

Back when the evening-peak rates were newly implemented, we reviewed several hundred San Diego projects that had been designed in Aurora and found that the rate change would substantially increase bills for customers who were still large net-consumers after going solar, but that solar was still a solid investment even with the less favorable TOU periods.

Solar software from Aurora makes it easy to model your customer's energy usage and create an optimal solar design and proposal. See how in a live demo! 

Is It Worth Pointing Panels to the West?

After simulating production profiles for systems with various orientations and combining it with residential TOU rates, we created an “energy value” of the PV systems. We calculated energy value by taking the kWh created by a system during each hour of the year and multiplying it by the current retail rate, and then tabulating the sum of all hours. The data is presented in gauge charts below. The wheel color indicates the system yield similar to the irradiance maps in Aurora. The sunshine icon indicates the optimal azimuth with the maximum energy production, and the needle showing which orientation achieves the most “energy value” throughout the course of the year.

The example below is for a customer in Southern California Edison territory near Los Angeles, using the TOU-D-4-9-PM rate. The ideal orientation for energy production is around 190 degrees azimuth, and because of the late peak hours, the ideal orientation for solar value is slightly further west at 200 degrees azimuth.Screen Shot 2020-03-12 at 5.46.13 PM

In other locations, this trend still holds true. The optimal orientation for system production value is slightly west of the optimal orientation for overall energy production, but not substantially so. Nearly all sites studied (see below) have an optimal orientation of 190 or 200 degrees azimuth, just slightly west of south. The rate that favors the furthest west-facing panels is San Diego Gas & Electric’s TOU-DR-SES for solar energy systems, which features an extraordinarily high peak price and lower off-peak rates.

What Happens If…

In the previous scenarios, there aren’t strong arguments to face your panels west when you have a choice to point them south. However, west-facing panels might be the way to go in some situations, e.g., a return to 3 - 8 pm peak pricing or a higher on-peak price. We will look at a couple of these what-if cases next.

Higher Peak Pricing

In some of the current TOU rates, the peak rate is roughly double that of the off-peak rate ($0.16 vs $0.31 per kWh in the SCE example). Adjusting this ratio from 2:1 to 3:1 or 4:1 by either increasing the peak rate or reducing the off-peak rate will provide more relative values to the on-peak energy production. We tested this out with the SCE rate, and got the following results:Increasing the difference between on-peak and off-peak prices to such an extreme level is not expected, but doing so would favor southwest-facing systems.

The energy production (color scale) remains the same, but the needle shifts west indicating that there’s an advantage for southwest-facing systems when there is an extreme difference between on-peak and off-peak pricing. We don’t expect rates like this to show up frequently, but an off-peak to on-peak price difference of $0.15 vs $0.45 would be enough to favor systems that face more west.

Earlier Peak Pricing Hours

For most PV systems, whether they face south or west, there is more energy production between 3 - 4 pm than 4 - 5 pm. What if peak TOU hours began at 3 pm, would there be an advantage to face further west?

Yes, if the rate is E-TOU-A in PG&E territory, which has a 3 - 8 pm peak pricing period. E-TOU-B is similar to E-TOU-A, but features a 4 - 9 pm peak rate. Shown side-by-side here, there’s no change in the optimal orientation.

Non-Standard NEM Scenarios

The above analysis applies to utilities that have standard NEM policies, or have export rules that are still very close to retail rate. In markets such as Nevada or Hawaii, in which the gap between the purchase rate and the credit for excess energy is substantial,, there is additional value in designing PV production to coincide with home loads (i.e., self-consumed energy offsets the bill at the retail rate while exported energy is credited at a lower amount, or not at all). To correctly model these scenarios, it’s important to have a good measure of the customer’s home energy usage (such as Green Button Data) and to make sure your modeling tools support advanced NEM rules.

Conclusions

If you are planning a ground-mount system or have a flat roof surface, you might be able to boost the value of your solar PV system by pointing it slightly to the west. If your roof is south-facing, the actual difference in produced energy value between due south and the optimal azimuth was between 0.3% and 0.7% in all the cases we looked at. Other factors, such as shade on the site, which roof surfaces are available for solar, and even the efficiency of the inverter, can have a much larger impact on the value of the system than picking between south and slightly southwest.

A choice with greater consequence is picking between a southeast-facing (135 degrees azimuth) and a southwest-facing (215 degrees azimuth) roof face. The southwest-facing surfaces typically have about 99% of the maximum energy value while southeast surfaces were around 95% across the board. Both are great, but if all other aspects were equal, the southwest surface would be the better choice.

Note

Our data models here ignore non-bypassable charges, which are 1.5-3 cents per kWh depending on the utility company and rate. Models also simplify non-peak costs to be an average of off-peak and shoulder-peak prices, since these typically only differ by a few cents. We used 4pm-9pm hours for TOU, and used May, June, July, and August as the summer-pricing months. Production profiles were simulated using unshaded panels sloped at 20 degrees. Actual energy yield and optimal orientation will depend on site conditions including shading, and the actual optimal-value orientation may vary by tilt, shade conditions, and the customer’s load profile. You can complete a more in-depth analysis of system performance and utility bill savings using Aurora’s tools.

Topics: pv installation, solar policy

Module-Level Rapid Shutdown: New Requirements for Fire Safety

Posted by Lisa Cohn on Jan 28, 2020 11:07:22 PM

Working in the solar industry, you’ve likely heard about rapid shutdown requirements. But what are they, do they apply to you, and do you know how to comply?

Several states including California adopted newer rapid shutdown requirements starting in 2020, and many others had already adopted them prior to that point, so it’s important to understand what these requirements mean for your business.

In this article, we tackle this topic and what you need to know to design safe and legal PV systems in areas with these requirements. Specifically, we look at the requirements for module-level rapid shutdown in the U.S.

What Is Rapid Shutdown?

With the increased popularity of solar PV—especially on homes—the National Fire Protection Association (NFPA) wanted to find a way to ensure firefighters could be safer when responding to fires on buildings with solar PV.

In response, the NFPA, which publishes the National Electric Code (NEC)—standards for electrical wiring that are adopted by states and municipalities in the U.S., introduced rapid shutdown.

Rapid shutdown requirements aim to provide a simple method for firefighters to de-energize the DC conductors in a solar system and ensure safe conditions on a roof if there’s a fire, explained Edward Harner, Chief Operating Officer of Green Solar Technologies.

In the 2017 NEC, NEC Section 690.12 was updated to reflect new rapid shutdown rules. The update calls for module-level rapid shutdown instead of the array-level rapid shutdown required in the NEC 2014 code. States and municipalities adopt different versions of the NEC over time, but as of January 1, 2020, the NFPA reports that 31 states have adopted the 2017 NEC.

To meet these module-level regulations, smart modules, microinverters, or other module-level power electronics are needed.

Protecting Firefighters From Live Wires

“On a typical string inverter system, even after the inverter is switched off, the DC conductors remain live as long as the sun is shining. To protect our firefighters from hacking any live wires while ventilating the roof during a fire, rapid shutdown was introduced to kill any power in the system conductors,” Harner said.

Rapid shutdown devices are designed to lower the voltage in the DC system conductors to 30 volts within 10 seconds after the inverter is disconnected, he said.

For standard string inverter systems, the NEC requirements also call for a rapid shutdown device for every section of the conduit run that is more than one foot from the array, he said.

MLPE Needed

That means that all buildings subject to the NEC 2014 or 2017 codes will need module-level power electronics (MLPE) such as microinverters and optimizers to enable the rapid shutdown, said Sean White, the author of several books about solar energy and the 2014 Interstate Renewable Energy Council Trainer of the Year.

One of the drawbacks of requiring module-level rapid shutdown—as opposed to array-level shutdown—can be the additional cost, said Harner.

Considerations for Systems with MLPE

Another consideration to be aware of is the maintenance required for MLPE. “You need things to be replaced more often,” said White, who has solar PV on his roof at home. “I have 53 microinverters on my roof. There’s almost always one I need to replace. The microinverters have a monitoring system and tell me when they need to be replaced,” he said.

In addition, the rapid shutdown requirements limit a designer’s product choices.

Before the rapid shutdown requirement, designers could wire modules and put control devices outside the arrays, which was easy to do. The only way to meet the new requirement is to install an electronic device at each module, and there are limited options for achieving this goal.

One way to avoid installing electronic devices at each module is to use smart modules, such as those from SolarEdge or Enphase, which have rapid shutdown equipment built into their systems. While solar systems with these kinds of components don’t require additional gear, most others do—with a few exceptions, White noted.

Wildfires Boost Need for Rapid Shutdown

The need for rapid shutdown has increased because wildfires are being sparked more often by climate change, especially in California and Australia.

Without the rapid shutdown requirements, firefighting in the age of wildfires and climate change would be more complex—and dangerous to firefighters who are already grappling with the challenges of bigger and more frequent fires, said Harner.

Supporting Firefighter Safety

“There have been many reports in the news about firefighters needing to change their tactics at the last minute when, upon arrival to the scene, they find solar on a building,” he said.

Firefighters are safer due to rapid shutdown requirements. More and more, they’re also safer because they’re taking precautionary steps such as maintaining a database of buildings with solar. And fire officials are providing special training on fighting fires in buildings with solar.

For example, the city of Portland, Oregon is providing training to firefighters about how to respond to fires in buildings that have microgrids consisting of solar and storage.

“Structures with solar only add more complexity to the challenge of firefighting,” said Harner. “We want our firefighters to be safe, and we want to also promote and accelerate the adoption of solar technology.”

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Topics: solar policy

How Solar Easements Provide PV Peace of Mind

Posted by Lisa Cohn on Jan 17, 2020 2:46:18 PM

A solar installation is a significant investment for your customers—and the last thing they want is to have that investment threatened. However, in some cases, future changes on surrounding property—such as a new building on their neighbor’s property or the growth of vegetation on adjacent land—could jeopardize the amount of irradiance their PV system receives, and thus how much energy it produces.

There are options for solar customers to avoid these kinds of unpleasant surprises, however. Solar easements give solar system owners the right to negotiate with neighbors for access to unobstructed sunlight on their solar systems, according to the Solar Energy Industries Association (SEIA).

In today’s article, we delve into what solar easements are, how they work, and some of the considerations that solar customers should be aware of if they are interested in pursuing easements. If this question comes up, whether in the sales process or in your post-sale relationship with customers, you’ll be well prepared to help.

Protecting Against Shading of Solar Systems

“Solar easements are important in ensuring that a homeowner’s solar panel system is producing optimal levels of electricity. Shade plays a large role in solar electricity production, and easements protect [homeowners] against that happening,” says Ken Pedotto, CEO of Solar Simplified.

Specifically, solar easements restrict what your neighbors can build or grow on their property; they prevent neighbors from blocking sunlight to your solar panels, he says.

Solar Access Laws vs. Solar Easements

Easements differ from solar access laws. Solar access laws limit private restrictions on solar energy projects, says SEIA. For example, rules from homeowners’ associations are a common challenge that restrict how solar systems on homes or businesses are installed. Such rules are generally created to uphold a community’s aesthetic standard.

When a solar system owner is grappling with solar access challenges from neighbors or homeowners’ associations, it’s important to ensure that the owner’s rights are protected. “To put it simply, a solar easement allows homeowners to legally protect their access to sunlight,” says Pedotto.

There are two types of easements: affirmative easements, the right to use land owned by another entity; or a negative easement, which restricts a property owner’s use of land.

A solar easement is viewed as a negative easement because it prohibits property owners from using their property in a way that prevents sun from reaching a solar energy system on a neighboring property.

Potential Challenges of Obtaining Solar Easements

It’s not necessarily easy to obtain a solar easement. That’s because the easement must be granted by a neighboring property owner—and the property owner can refuse to negotiate or grant the easement.

It’s also important to recognize that negotiating easements can sometimes be costly. “Legal costs could exceed the cost savings of the system if neighbors are not willing to grant the easement for free,” says EPIC. “Depending on the density of houses in a neighborhood, a prospective solar energy system owner might have to negotiate with several neighbors to ensure access to sunlight.”

Different states have different policies and protections regarding solar easements. For instance, the California Solar Rights Act gives local governments the ability to require solar easements in subdivision developments under certain circumstances, according to the Energy Policy Initiatives Center (EPIC). We delve into a few key state-level policies below.

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New York State and Montana Laws

New York State is one of many states that protect a solar system owner’s right to ensure enough sun reaches the system. The state’s law states that solar easements should be created in writing. The document should include vertical and horizontal angles, provided in degrees, that identify the area that is the subject of the easement.

In addition, the law calls for terms and conditions under which the easement would be granted or terminated. New York State also expects the document to include any provisions for compensating the solar system owner if the other party interferes with access to solar.

Montana's law is similar to New York State’s, calling for a written document that includes the location of the easement.

California Solar Protection Laws

In California, two laws protect solar system owners: The Solar Rights Act and the Solar Shade Act, according to Go Solar.

The Solar Rights Act, AB 3250, passed in 1978, includes measures giving consumers access to sunlight and preventing shading. It also restricts efforts by homeowner associations and local governments to prevent solar system installations. The act gives citizens a legal right to a solar easement.

“Even though the law is more than 30 years old, the Solar Rights Act contributes significantly to California's strong policy commitment to solar energy, and the policy rationale for the Act is relevant today and continues to support California's solar energy policy initiatives,” says Go Solar.

California’s Solar Shade Act

While the Solar Shade Act (AB 2321) doesn’t create solar easements, it does provide some protection to solar system owners from shade created by trees on neighboring properties.

When trying to decide whether it makes sense to pursue a solar easement, it’s a good idea to look to the court system to uncover how such laws are implemented.

For example, one California court, in an unpublished portion of its opinion, held that a solar easement is only enforceable if it is in writing, according to EPIC.

A document that creates a solar easement should identify the location of the easement in “measurable terms,” the court said. It should also include “restrictions that would impair or obstruct the passage of sunlight through the easement” as well as “the terms or conditions, if any, under which the easement may be revised or terminated,” according to EPIC.

See how Aurora helps solar companies grow revenue, cut costs, and impress their  customers!

Local Governments in California Can Establish Solar Protection Ordinances

An ordinance could establish solar easements designed to ensure that each parcel has access to sunlight, especially across adjacent parcels or units in a subdivision. In most cases, it’s critical that the parties create a written document.

In the unpublished portion of its opinion in the Zipperer v. County of Santa Clara (California) case, the court specifically discusses the need for written documentation of solar easements, says EPIC.

“The Zipperers built a home with solar heating and cooling systems in the mid-1980s. In 1991, the County of Santa Clara purchased an adjacent property containing a small grove of trees,” says EPIC. The trees grew “significantly,” and began to shade the Zipperer home, which hurt the solar system’s output.

“In 1997, the Zipperers requested that the County trim or remove the offending shading trees.The County did not respond to the Zipperer’s request, and instead passed an ordinance exempting itself from California’s Solar Shade Control Act.”

The Zipperers sued the county, arguing a breach of contract associated with an “implicit” right to a solar easement. The Zipperers argued that the county had implicitly entered into a contract to provide a solar easement because the county allowed the homeowners to build a home according to county requirements.

However, the court said that a written, not “implicit” solar easement was needed. “Therefore, because the Zipperers did not have an express, written instrument, the court held that no solar easement existed.” The Zipperer case highlights how important it is that a solar easement be in writing.

Deciding If a Solar Easement Makes Sense

A written solar easement can offer assurance that a solar installation will continue to produce electricity at its full potential—particularly valuable in cases where there is potential for changes on surrounding property that could affect the system’s irradiance.

However, the ease of getting one of these agreements in place is an important consideration. As Pedotto says, “Not only can solar easements be costly, but they can cause conflict with neighbors.”

Pedotto suggests that an alternative to pursuing a solar easement in these cases is for homeowners consider community solar projects, which help bring neighbors together with shared access to local solar farms.

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Topics: shading losses, solar policy

Key State Policy Changes in the Second Half of 2019

Posted by Sunny Wang on Dec 18, 2019 8:00:00 AM

In our latest state policy round-up, we highlight the key changes relevant to solar energy in states around the U.S. that have occurred in the second half of 2019 (building upon our round-up for the first half of 2019 and our 2018 round-up).

The most exciting news (perhaps maybe even for the entire year) comes from New York! In one bill, New York committed to 100% carbon-free energy and set impressive targets for solar and wind development, renewable energy sources, emissions reduction, storage, and mandatory fund allocation for disadvantaged communities.

Three other states joined New York in committing to 100% carbon-free energy; Connecticut, Virginia, and Wisconsin all did so with an executive order. This brings the collective total of U.S. states and territories who have formally committed to 100% clean or renewable energy targets to 16!

California, Delaware, New Hampshire, and Oregon also passed solar-friendly bills, with wins for storage, tax and rebate incentives, and low- and moderate-income communities.

Not all developments were positive though. Louisiana rolled back net metering, and in one bill, Ohio reduced its renewable portfolio standards, abandoned its energy efficiency programs, and bailed out multiple coal and nuclear power plants.

These solar policy developments close out 2019, but we’re looking forward to what comes next in 2020.

California

In addition to California’s commitment to 100% clean energy and requiring all new homes to have rooftop solar starting January 1, 2020, the state also extended the prohibition of taxing energy generated by rooftop solar panels for another seven years with AB 1208.

Back in 2013, AB 792 clarified and provided tax certainty for Californians going solar through third-party power purchase agreements (PPA) or any other financial model. The bill specified that all site-generated electricity is exempt from local “utility user’s tax,” and it was set to expire at the end of this year.

To learn more about what CA's 100% clean energy target means for solar,  watch our GTM webinar with the California Energy Commission and  the California Solar and Storage Association!

Connecticut

Connecticut joins a growing list of states that have committed to 100% clean energy with Governor Ned Lamont’s Executive Order No. 3. Among other climate change matters, the order directs the Department of Energy and Environmental Protection to “analyze pathways and recommend strategies for achieving a 100% zero carbon target for the electric sector by 2040.”

Additionally, An Act Concerning a Green Economy and Environmental Protection (HB 5002) extends net metering for two years (halting the dismantling of net metering from the passage of SB 9 last year, which we covered last year, and absorbing a related bill—HB 7251), expands commercial and residential solar incentive programs, increases virtual net metering caps from $10M to $20M, and allows electric utilities to own energy storage and recover the cost from ratepayers.

Delaware

In August, Delaware Governor John Carney signed HB 65 that amends Title 25 of the Delaware Code to bar unreasonable restrictions on residential property owners from installing rooftop solar, changes the 2/3 vote to a majority vote required to amend existing restrictions by homeowners associations (HOAs) or maintenance corporations, and provides legal funds for the prevailing party should litigation arise over HB 65’s language.

(For related coverage on solar and HOAs, including some of the protected rights homeowners have to solar, see this blog post.)

Louisiana

Louisiana rolled back net metering for new systems starting January 2020. In September, the Louisiana Public Service Commission made changes to net metering (R-33929) requiring rooftop solar customers to “buy-all, sell-all”—purchase all their electricity consumption at retail price, and be credited at the avoided cost rate for all electricity fed back to the grid. There is a 15-year grandfathering period for all systems connected before the end of this year to continue receiving the full retail rate.

The thin silver lining to R-33929 is the elimination of how many customers can participate in net metering.

New Hampshire

Governor Chris Sununu signed into law the Low Moderate Income Community Net Energy Metering Act (SB 165) in July, requiring utilities to build at least two new community solar projects each year in low to moderate income communities with favorable net metering rates for residents starting January 2020. The bill also provides an additional incentive payment of 3 cents per kWh from July 1, 2019 through July 1, 2021, then drops to 2.5 cents per kWh.

On the storage front, local municipalities are now allowed to extend property tax breaks for solar storage systems with the passage of HB 464.

New York

The New York Climate Leadership and Community Protection Act (SB 6599), also referred to as the CLCPA, is one of the most ambitious pieces of clean energy legislation passed in the U.S. Its major provisions include 100% carbon-free energy by 2040 (excluding new hydropower) with 70% from renewable energy sources by 2030, net zero emissions by 2025, ambitious offshore wind and solar energy development targets, as well as 3,000 MW of energy storage capacity installed by 2030.

The CLCPA creates two groups: the Climate Action Council and the Climate Justice Working Group. The Climate Action Council will be responsible for creating a scoping plan with recommendations to reduce emissions with consultation from various groups. The Climate Justice Working Group will define “disadvantaged communities” and be a representative voice for these communities to the Climate Action Council.

SB 6599 also mandates 35-40% of all state climate and clean energy spending funds (plus any future related initiatives) go to disadvantaged communities. The amount allocated to disadvantaged communities can increase over time as more funds are provided, i.e., this isn’t a one-time contribution.

Ohio

The contentious HB 6 was signed by Governor Mike DeWine back in July. In one bill, Ohio guts its renewable portfolio standards (RPS), allows utilities to abandon its energy efficiency programs, and bails out two of FirstEnergy Solutions’ nuclear plants and two coal plants owned by Ohio Valley Electric Corporation through ratepayer surcharges.

HB 6 reduces Ohio’s current RPS from 12.5% by 2027 to 8.5% by 2026, then waives the standard after 2026. Instead of the existing goal of reducing customers’ energy use by 22% from 2008 levels by 2027 through energy efficiency programs, utilities are allowed to abandon those programs after achieving a 17.5% reduction. Roughly $1B will be paid out to FirstEnergy over a span of seven years from the $0.85 surcharge on utility customers’ bills, with an additional $2.50 monthly surcharge to be redirected to the Ohio Valley Electric Corporation.

An effort to overturn the bill through a voter referendum for next year’s ballot has gone through a District Court and the Ohio Supreme Court; the Supreme Court declined to hear the case.

Oregon

In early August, Governor Kate Brown signed HB 2618 creating a new solar plus storage rebate program with a budget of $2M. The bill allocates at least 25% of the rebate budget for low- and moderate-income households and low-income service providers, along with a higher net cost coverage of up to 60%.

Virginia

Virginia joins a growing list of states that have committed to 100% carbon-free or renewable energy with Executive Order 43. Governor Ralph Northam set a goal of 100% carbon-free by 2050, with a goal of producing 30% of its electricity from renewable sources by 2030. This is in addition to other efforts aimed to support Virginia’s clean energy transition, help climate change mitigation, and reduce the burden on low-income communities.

Wisconsin

Wisconsin also committed to 100% carbon-free energy by 2050 through an executive order—#38. The newly created Office of Sustainability and Clean Energy will lead this effort. It will ensure that the state fulfills the 2015 Paris Climate Accord carbon reduction goals, develop a plan to help with climate change adaptation and mitigation, promote clean energy workforce training, and create various standards for existing and future state buildings.


Despite some setbacks for solar in Louisiana and Ohio, there were many positive state actions in the second half of 2019. In this round of policy updates, we see several more states join the commitment to transition to clean energy—a sign that states are recognizing the importance of the clean energy transition and how clean energy sources like solar benefit their residents, the economy, and the environment. 

States have also included storage, friendly solar tax and/or rebate incentives, and low- and moderate-income communities in their legislation. Many of these commitments will help counteract changes like the step-down of the federal Investment Tax Credit starting in 2020.

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Topics: solar policy

What Is the Cost of Section 201 Solar Tariffs? New Data from SEIA

Posted by Gwen Brown on Dec 5, 2019 2:45:59 PM

In a young industry like solar, policies can have a critical impact on growth. Those impacts may be positive—for example, net metering has been a key policy for making solar cost-competitive in the U.S. (as have feed-in tariffs in other areas)—but that's certainly not always the case.

Over the last couple of years, one of the biggest policy shake-ups in the U.S. market has been the imposition of Section 201 solar tariffs on imported solar cells and modules. The solar tariffs made imported modules more expensive, counteracting years of dramatic cost declines.

New research from the Solar Energy Industries Association (SEIA) quantifies the impact of the Section 201 solar tariffs. The report, The Adverse Impacts of Section 201 Tariffs, assesses the market impacts from 2017 (when the solar tariffs came under consideration) through 2021.

SEIA finds that the solar tariffs, which have made U.S. solar module prices among the highest in the world, significantly slowed the pace of solar adoption—costing $19 billion in private sector investment, 10.5 GW of solar capacity, and 62,000 jobs!

While broader market reports are optimistic for the future of our industry—projecting that total installed PV capacity in the U.S. will more than double over the next five years—these striking numbers underscore how much faster solar industry growth could have been. In today’s article, we take a look at the details of SEIA’s analysis.

Section 201 Solar Tariff Background

In January 2018, the U.S. government imposed a 30% tariff on all imported crystalline silicon PV (c-Si PV) modules, under Section 201 of the Trade Act of 1974. This followed significant industry uncertainty starting in early 2017 as a result of the pending trade case brought by two module manufacturers. The tariff which started at 30% in 2018, gradually drops down by 5% per year, dropping to 15% in 2021.

These solar tariffs resulted in prices “43 - 57% higher than the global average, leading to higher prices for customers and reducing overall demand,” reports SEIA.

Comparison of global solar module prices vs. U.S. solar module prices due to Section 201 solar tariffsA comparison of U.S. (blue) vs. global prices (red) for monocrystalline and polycrystalline silicon modules. Source: SEIA, The Adverse Impacts of Section 201 Tariffs.

Higher Prices, Slower Market Growth

One of the key findings in the new data from SEIA is how these higher prices have impacted solar adoption. One of the easiest ways of understanding this is to look at how the solar tariffs have changed the Levelized Cost of Energy (LCOE) of solar. If you’re not familiar with LCOE, it is a common metric used to compare the per-unit cost of different types of energy.

Solar competes against other energy types; higher component prices “reduce the size of the addressable market by pushing economics in favor of substitutes (existing generation, gas and wind) in marginal markets.” In areas where there is a thin margin of price difference between solar and other energy types, these price increases can make the difference in whether a solar purchase makes economic sense, as illustrated in the chart below.

LCOE by installed PV price + "hurdle rate" (cost solar must be below to work financially), per SEIA solar tariff data “LCOE by Installed PV Price and Residential Hurdle Rate for Select Cities and Installed Costs.” The two curved lines represent different LCOE values. The vertical position of the horizontal lines indicate the LCOE that a solar installation would need to be below in order to be installed in different cities, and the horizontal distance of these lines represents the range of possible energy yields in that location. Points on horizontal lines that are above the LCOE Curve are financially feasible projects. As you can see, in some areas the price increases from the solar tariffs may push the cost of solar out of reach. Source: SEIA, The Adverse Impacts of Section 201 Tariffs.

Ultimately, as a result of these tariff effects, the market for new projects between 2019 and 2021 has been reduced by 7.5 GW and, in total, more than 10.5 GW of solar installations will not be deployed. SEIA reports that this translates to enough electricity to power 1.8 million homes.

Solar deployment in the U.S. between 2017 and 2021 with and without the impacts of Section 201 solar tariffsA comparison of estimated solar deployment levels in the U.S. between 2017 and 2021 with and without the impacts of Section 201 solar tariffs. Source: SEIA, The Adverse Impacts of Section 201 Tariffs.

Lost Jobs

As a result of this decreased solar demand, SEIA estimates that between 2017 and 2021 there will be 62,000 fewer solar jobs than under a business-as-usual scenario.

Solar jobs in the U.S. with and without the impacts of Section 201 solar tariffs, per SEIAA comparison of estimated solar jobs in the U.S. with and without the impacts of Section 201 solar tariffs. Source: SEIA, The Adverse Impacts of Section 201 Tariffs.
 
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Lost Investments

Similarly, cost increases from the Section 201 solar tariffs resulted in reduced investment in the solar industry. In total, SEIA estimates that $19 billion in investment opportunities was lost as a result of the policy changes.

Lost investment in the U.S. solar industry due to Section 201 solar tariffs, per SEIA.
Annual investment in the solar industry and estimated lost investments resulting from the Section 201 solar tariffs. Source: SEIA, The Adverse Impacts of Section 201 Tariffs.

The solar tariffs applied under Section 201 could have been worse; the industry has continued to make progress and forecasts point to a bright future ahead. (Stay tuned next week for a round-up of new state policy developments, many of which are positive for solar.)

However, these figures put into context the impacts of this national policy change on our industry at a macro level. Beyond the economic impacts, the slowed pace of solar growth had other significant effects as well. SEIA reports that CO2 emissions will increase by more than 26 million metric tons, equal to emissions from 5.5 million cars or 7 coal plants.

As a solar contractor, you’re on the front lines of bringing about a new, cleaner energy future. We’re thankful for the work you’re doing and aim to give you the tools to succeed—from lowering soft costs to sharing solar sales tips and interviews with industry leaders.

Let us know in the comments below what new articles would help you, or how your company has coped with the ups and downs of the industry!

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Topics: solar policy

What to Know About the Solar ITC Step Down

Posted by Gwen Brown on Oct 16, 2019 9:00:00 AM

Whether you’ve been working in the U.S. solar industry for a decade or a week, chances are you’re familiar with the solar Investment Tax Credit (ITC), one of the most important incentives for solar customers. This federal policy, which allows owners to deduct 30% of the cost of a solar installation from their taxes, has been a cornerstone in the growth of the solar industry.

Stakeholders breathed a sigh of relief in December 2015 when the solar ITC–previously set to expire at the end of 2016–was extended for an additional five years. But starting in 2020, the value of the tax credit will drop down to 26% of the system cost as part of a multi-year phase-out.

In this article, we break down what solar contractors need to know to understand whether the full 30% ITC will apply to their customer's project depending on the timeline for the project's completion. Clarity on this point is essential to accurate modeling of the finances of the project and setting the right expectations for your customer.

[Note: This blog post is provided for informational purposes only and does not constitute legal advice. Consult an attorney for guidance on your particular situation.]

The Solar ITC will be phased out from 2020 - 2022.The solar ITC will begin to be phased out starting in 2020. The phase-out will end in 2022 when the ITC drops to zero for residential projects and a permanent 10% for commercial projects. 

Differences the ITC Step Down Between Residential and Commercial Projects 

It is important to understand that there are differences in the cut-off for when residential solar projects and commercial solar projects may claim the full 30% solar ITC (as the Solar Energy Industries Association, SEIA, explains here). 

This is because the tax credits for these two types of projects are designated in different parts of the U.S. tax code. Although both residential and commercial PV systems have been eligible for the 30% solar ITC, the tax credit for businesses who invest in solar energy systems credits is established in Section 48. The residential solar energy credit for individuals who purchase a solar energy system is found in Section 25D.

A major difference between the residential and commercial solar ITC is that commercial projects that "commence construction" before the ITC step down date of January 1, 2020 and are completed before 2024 can still receive the full 30% tax credit. In contrast, residential systems do not have this "safe harbor" period. They must be completed (that is "placed in service") before January 1, 2020 or else the lower 26% tax credit will apply. 

Understanding the Solar ITC Step Down for Residential Projects 

As SEIA explains, "To receive the full 30% residential solar tax credit, the system must be 'placed in service; before the end of the day December 31, 2019. It is not enough to have signed a contract, or to have made a down payment or even to have begun construction. There is no bright-line test from the IRS on what constitutes 'placed in service,' but the IRS has equated this with completed installation in a Private Letter Ruling."

In the case of newly built homes with solar PV systems, where the customer is the owner of the PV system, SEIA clarifies that eligibility for the solar ITC is established based on when the customer moves into the home. This is only the case for solar installation purchased in connection with the construction of a new home. In the case of solar installations on existing homes, eligibility is based on the time of completion of the PV system.

Understanding the Solar ITC Step Down for Commercial Projects 

Solar ITC eligibility is a little less black and white for commercial solar projects. If construction on the project has not started before January 1, 2020, the lower tax credit will apply.

But what qualifies as starting construction? Solar contractors need to have a firm grasp on the “commence construction” policy to know whether a commercial project that may extend into 2020 will qualify for the 30% ITC. In June 2018, the IRS released guidance which answers this question.

 

Understanding the “Commence Construction” Clause

According to the IRS, there are two ways to establish that construction on a commercial solar project has started for the purposes of claiming the solar ITC:

  1. passing the “Physical Work Test” by starting “physical work of a significant nature,” or
  2. passing the “Five Percent Safe Harbor test” by “spending five percent or more of the total cost of the facility in the year that construction begins.”

In either case, the system owner will need to show continuous progress on the project after that point in order (the “Continuity Requirement”) in order to qualify.

Let’s delve into each of these cases a little more closely:

The Physical Work Test

The physical work test establishes that construction has commenced on a project when “physical work of a significant nature” has begun on the project. The IRS states that whether the work is considered “significant” is based on the nature of the work, rather than the amount or cost of that work. In the case of a solar installation, one example of qualifying work that the IRS provides in their guidance document is the installation of racking to affix solar panels to a site. 

System owners can qualify for the solar ITC by starting significant physical construction before it expiresA PV system owner can establish the start of a project for the purpose of claiming the solar ITC by starting physical work of a significant nature (what the IRS calls "the Physical Work Test"). 

The qualifying work may be undertaken by the taxpayer (i.e., the PV system owner) or a contractor working under binding written contract entered into prior to the start of work (i.e., your solar installation company). Technically, this work may take place on-site or off-site, however, in the case of a residential or commercial solar PV installation off-site work is less likely to apply. Off-site work does not include work “to produce components of energy property that are either in existing inventory or are normally held in inventory by a vendor”–as would typically be the case for solar equipment.

“Preliminary activities” do not qualify for the Physical Work Test. Some examples of preliminary activities include planning or designing the project, securing financing, researching, obtaining permits and licenses, clearing a site, or removing existing solar panels or other components that will no longer be part of the energy property.

Again, once construction has commenced on the project for the purposes of qualifying for the solar ITC, continuous work must be done on the project until it is completed.

The Five Percent Safe Harbor Test

An alternative way that a solar system owner may establish that construction has started on a project for the sake of qualifying for the 30% ITC prior to the end of 2019, is by having paid or incurred five percent or more of the total cost of the energy property. In the case of a solar PV installation, this refers to the cost of the PV system. This does not include the cost of land or any property not integral to the energy system. 

System owners can qualify for the solar ITC by incurring five percent or more of the cost of the project before it expiresA PV system owner can also establish the start of a project for the purpose of claiming the solar ITC by incurring five percent or more of the cost of the project (what the IRS calls the "Five Percent Safe Harbor Test").

There is an important caveat to this method of establishing the start of the project. If the project cost exceeds what was anticipated, so that the amount the system owner paid to satisfy the five percent Safe Harbor later falls short of five percent of the total cost, they will be found not to have met the requirement.

As with the physical work test, the system owner must also show continuous progress after this point in order to continue to qualify for the Safe Harbor. The IRS notes that this could include “(a) paying or incurring additional amounts included in the total cost of the energy property; (b) entering into binding written contracts for the manufacture, construction, or production of components of property or for future work to construct the energy property; (c) obtaining necessary permits; and (d) performing physical work of a significant nature.”

Combination of Methods

If a PV system owner meets both methods of establishing the commencement of construction, whichever method occurs first will be used as the date in which construction began for the purposes of the solar ITC.


Guidance from the IRS provides solar customers, contractors, project developers and others the clarity they need to determine whether and at what level the solar ITC will apply to a given project. With this information, your solar company can better advise prospective customers on how this key federal incentive will reduce the cost of their project.

At the time of writing SEIA is working hard to build support for an extension of the solar ITC. You can find out how to get involved in this initiative here.   

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Editor's Note: A version of this article was originally published on July 25, 2018. It was updated and republished on October 16, 2019 to clarify how the step down of the ITC applies to residential projects and reflect that the commence construction clause applies only to commercial projects.

Topics: solar policy

How Community Choice Aggregation (CCA) Growth Can Boost Solar

Posted by Lisa Cohn on Sep 11, 2019 5:12:50 PM

Community Choice Aggregation (CCA) can create demand for renewable energy, presenting opportunities for solar developers. We explore what CCAs are, how they’re growing, and what that might mean for solar companies.

What Are CCAs and How Does Solar Fit In?

Community Choice Aggregation (CCA), also called Community Choice Energy, provides customers with an alternative power provider than traditional utilities.

The presence of CCAs is growing, especially in California, and—because they often offer more renewable energy than the incumbent utility, according to a National Renewable Energy Laboratory (NREL) report—CCAs present opportunities for solar developers to help provide that power.

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How Do CCAs Work?

Generally administered by local governments—cities or counties—or sometimes third parties, CCAs acquire electricity for retail customers in a specific geographic area.

CCAs partner with local investor-owned utilities that provide billing, transmission, and distribution of the electricity the CCA provides. They can aggregate fairly large groups of customers, which provides economies of scale.

Scale (and Potential) of the CCA Market

About 750 CCAs acquired 42 million MWh of electricity for 5 million customers in 2017 in eight states where legislation allows for their existence—California, Illinois, Massachusetts, New Jersey, New York, Ohio, Rhode Island, and Virginia, said the NREL report.

Additional states are expected to pass legislation that allows for CAAs, according to NREL. In addition to the eight states that have CCAs, at least seven states have considered allowing CCAs—Colorado, Connecticut, New Hampshire, New Mexico, Nevada, Oregon, and Utah, said NREL. Other states with restructured electricity markets could pass legislation allowing for CCAs.

California and New York CCAs Focus on Renewable Energy

California and New York are two states where CCAs currently source a lot of their energy from renewable sources.

California CCAs concentrate on acquiring in-state renewable energy more than other CCAs. In California, CCAs in 2017 offered electricity with renewable energy content ranging from 37 percent to 100 percent, with an average of 52 percent. Their rates are generally .1 percent to 2.1 percent lower than the incumbent utility’s rates.

In New York, about half the sales of the active CCAs are “voluntary” green power programs, which go above and beyond state renewable energy mandates. In these cases, the CCA offers green power to willing customers.

A solar power plant. Some CCAs are sourcing power from new solar projects.

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CCAs Present Opportunities for New Solar Development

Although, as of 2017, CCAs had largely acquired renewable energy from existing generators, that’s beginning to change as CCAs grow in numbers and size, presenting new business opportunities for solar developers.

One recent example is a 3-MW solar array in Napa County, California which solar developer Renewable Properties broke ground on in April 2019. The state’s first CCA, Marin Clean Energy (MCE), will purchase the power from the project through a 20-year power purchase contract. MCE’s feed-in tariff, called FIT Plus Projects, offers $80 per MWh for peak, baseload, and intermittent energy.

NREL’s report highlights the potential for CCAs to increase the supply of renewable energy from new projects. In regulated or partially restructured markets, CCAs may be required to acquire renewable energy from new projects, NREL said, adding that more research is needed about this topic.

Projects such a Renewable Properties’ solar plant are expected to become more common because CCAs generally have significantly higher percentages of renewable energy in their mix.

With higher renewable energy content and typically lower prices, CCAs are here to stay. For solar developers, that offers opportunities to provide the energy that CCA customers are demanding from these new, green alternatives to utilities.

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Topics: trends, solar policy, Solar Business Tips

What to Know About DTE’s Net Metering Replacement in Michigan

Posted by Andrew Gong on Aug 26, 2019 7:26:53 PM

For residential solar customers in the U.S., net metering policies—which traditionally pay the owners of solar PV systems the retail electricity price for the energy their solar installation sends to the grid—have been crucial in making solar a good investment.

Increasingly, however, utilities are changing their net metering policies (also called net energy metering or NEM). These changes often mean reduced savings for solar customers–and potentially a harder sale for solar installers. Michigan’s DTE Energy recently made such a change—which has a significant detrimental impact on Michigan solar customers’ savings and payback periods.

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In today’s article, we quantify the impacts of DTE’s net metering replacement policy, with a case study of a typical home, as well as an analysis of impacts for customers at different levels of energy usage and solar offset (percentage of the customer’s usage that their solar installation offsets). We conclude with some solar design guidance to help you maximize the value for your solar customers in DTE territory.

What’s Changing with Net Metering in Michigan?

As PV Magazine reports, this new policy from DTE Energy has been anticipated for nearly three years following bills passed by the Michigan legislature requiring the Michigan Public Service Commission (PSC) to phase out net metering for solar in Michigan and create a new replacement program.

After rejecting a prior proposal from DTE which would have paid solar customers only the wholesale rate for the solar energy they sent to the grid, the PSC approved DTE’s new proposal on May 2, 2019 that some have called a middle ground.

The new program took effect on May 9 for new solar customers; existing solar customers will be grandfathered into the program over 10 years. This policy may provide a model for other Michigan utilities when they submit their proposed net metering replacement programs.

Affected service area: DTE serves southeastern Michigan/greater Detroit area with electric service.DTE serves southeastern Michigan/greater Detroit area with electric service.
The dark blue and gray indicates the area affected by this change.

DTE’s new Distributed Generation Program (Rider #18) replaces its Solar Net Metering rules (Standard Contract Rider #16). The core of the new Distributed Generation program is called an “Inflow - Outflow Mechanism,” which requires a smart meter that measures and sums power flows both to the grid and from the grid.

In the current implementation, inflow and outflow are measured in netted hour intervals; in the future they may be instantaneous (or second-long netting) which will generally be worse for the customer.

DTE’s NEM Replacement: Structurally Similar to California’s NEM 2.0

The structure of DTE Energy’s Distributed Generation rider is similar in many respects to California’s NEM 2.0 plan. Let’s look at a breakdown of how these policies compare:

A comparison of California's NEM 2.0 rate to the solar net metering successor program from DTE in Michigan.

DTE’s rider also stipulates that credits from excess generation can’t be used to pay off accrued generation charges, just like California’s NEM 2.0 rules don’t allow export credits to pay off accrued non-bypassable charges.

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Modeling DTE’s DG Rate in Aurora

Aurora Solar software allows solar contractors to precisely model the finances of solar installations under different utility rates, so we used Aurora's financial analysis platform to understand the impacts of this rate. Here's how you can model the finances of your DTE customer's solar project.

(Want to jump ahead to our findings? Skip to the next section here.)

Because DTE is effectively labeling the distribution component of its rate as a “non-bypassable charge,” users of Aurora’s Utility Bill Savings calculator can model this rate by selecting an export rule of “Fixed Reduction” and setting the reduction to the value. Looking at DTE’s latest ratebook, that value is $0.07024/kWh for the D1 Residential Rate, and approximately $0.06886/kWh for the D1.2 TOU rate

A screenshot showing how to model this rate in Aurora solar software as of August 2019.

Cost to the Solar Customer

Let’s look at how this change can impact an example house near Ann Arbor. Our model house consumes 9,000 kWh per year, the state average, and we fit a 5 kW system that offsets about 55% of the home energy usage, after losing 13% of sunlight to shade. We assigned this customer to Rate D1, which is the standard tiered residential rate for DTE Electric Co.

We used this example house in Ann Arbor to model the financial impacts of DTE's net metering changes for solar customers in Michigan. A house with solar near Ann Arbor, Michigan modeled in Aurora. With Aurora, we were able to run an accurate financial analysis of the changes to DTE’s net metering program.
 
Modeling DTE's old net metering policy in Michigan to compare against its new successor program, with Aurora solar software.

Under DTE Energy’s old NEM rules (Rider 16), the system would have saved the customer 63% of their annual electric bill, or about $71 per month. The bill-offset percentage is higher than the energy-offset percentage because the system offsets the energy usage of higher-cost tiers first.

Modeling DTE's net metering successor program in Michigan with Aurora solar software

 

When we change the advanced rules to include an export reduction of $0.07024 per kWh, based on Rider 18 in the latest DTE rule book, we found that the customer’s bill savings fell to only $55 per month, or 49% of their bill offset. The chart also shows that the customer’s bill is above the fixed fee of $7.50 each month; this is due to the customer paying their distribution charges.

Of course, to fully understand the impacts of this policy changes we need to understand how it impacts all types of systems, not just this one scenario. In the subsequent section, we share findings on the financial impact of these changes based on our analysis of billing impacts for customers across a range of energy usage levels (6000 kWh to 18000 kWh per year) and a range of energy offset levels (30% to 110% per year), an approach we’ve used in other studies.

Design Considerations: Design for the Optimal Energy Offset Percentage

Let's take a look at how to design PV systems to optimize value for your customers under these new net metering rules. While California's NEM 2.0 provides a handy analogy for understanding how these rules work, the design rules of thumb for Michigan solar designs under this policy are very different than for designs under California's NEM 2.0.

In California’s NEM 2.0 setup, the small size of the non-bypassable charge (less than 3 cents per kWh, with overall rates above 20 cents per kWh) coupled with the functionality of minimum monthly bills meant that installers could slightly oversize a PV system to maximize a customer’s net present value, even though the customer would be paying a larger post-solar bill compared customers whose solar installations were installed under NEM 1.0.

DTE’s change is much more significant than California’s NEM 2.0. Distribution accounts for nearly half of the rate for a full-service customer on the D1 rate schedule, and represents a majority of the off-peak charges for the D1.2 time-of-day rate. In addition, DTE has a monthly service fee that can’t be offset by solar credits, but also doesn’t act as a mechanism to absorb some of the distribution costs.

As a result, a customer’s Net Present Value is maximized at a much smaller system offset level than the original net metering tariff: around 85% for a D1 customer and around 65% for a Time-of-Day customer. The charts of Net Present Value below also paint a bleak picture about the value of systems—the value falls nearly 50% and in some cases is now worse than investing the money at 3% somewhere else.

relationship between Net Present Value and percent of energy consumption offset by solar under DTE Energy's net metering replacement in Michigan compared to old rulesComparisons of the relationship between Net Present Value and percent of energy consumption offset by solar for customers of DTE's D1 rate and D1.2 Time of Use Rate respectively. The asterisk icon represents the maximized NPV under the old net metering rules called Rider 16 (grey) and the new net metering replacement called Rider 18 (colored) lines.

As a note, our model assumed that the customer doesn’t use electric for heating or hot water based on EIA data, but when we ran the analysis with those appliances included in the energy profile, we found that the customer had a lot less self-consumption of solar energy, resulting in higher distribution charges and an overall worse financial outcome. Customers who have a consumption profile that doesn’t align well with solar production will need special consideration when looking at their bill savings.

Model Assumptions: 3% discount rate for NPV; $3/W pricing. Load profiles were generated with the Aurora consumption profile estimator, and production profiles were for a generic unshaded pv system facing south and tilted at 20 degrees.

Conclusions

Revisions to net metering policies can have significant effects on solar customers and DTE’s changes in Michigan are no exception. The impact of this new DTE structure on solar customers is quite severe, because the non-bypassable distribution portion of the rate makes up a large proportion of the overall electric tariff. Solar installers in DTE service territory will need to be careful to not overpromise customers on savings, because unwary residents would find it a shock that a 90% energy offset system will actually only save them 60% of their bill.

Installers and other groups will also want to be wary of upcoming rulemaking and new policies that are working their way through state legislatures and public utilities commissions. Unlike California’s NEM 2.0 policy or Nevada’s NMR-405 policy (barring the temporary rescinding of NEM programs), the DTE rate case is not a smooth transition away from standard net metering policy.

Here at the Aurora Blog keeping tabs on major solar policy and utility changes is one of the ways we try to help you excel at your solar career. Are there other major utility changes that you’re curious about? Let us know in the comments below!

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Topics: net energy metering, solar policy

SF Commercial Clean Energy Requirement Is a Boon for Solar

Posted by Lisa Cohn on Aug 14, 2019 8:30:00 AM

San Francisco—the first major city in the nation to require solar panels on the roofs of new buildings—now is requiring large commercial building owners to source 100 percent of their electricity from renewable energy by 2030.

That’s expected to be good news for solar contractors because it will expand the use of solar in the city and possibly nationally.

The San Francisco plan will be implemented in phases, requiring owners of the biggest buildings—500,000 square feet or larger—to take action first, by 2022. Buildings between 250,000 and 499,000 square feet must switch by 2024, and structures 50,000 square feet to 250,000 must source 100 percent renewable energy by 2030.

Other Cities Expected to Follow, Increasing Solar Demand Nationally

The solar industry nationwide is sure to get a boost from the initiative, said Tony Clifford, chief development officer, Standard Solar, and a member of the Solar Energy Industries Association (SEIA)’s executive board.

“Such mandates are becoming ever-more common across the country, and we believe San Francisco will set the standard for commercial solar expansion that other cities will soon follow,” he said.

Sean White, a certified solar PV master trainer and the author of several books about solar, said that in San Francisco, there isn’t enough roof space on most commercial buildings to offset 100 percent of their usage.

“They will need to purchase clean electricity through their Community Choice Aggregation (CCA) program or utility for a good part of their energy,” he said.

This will create opportunities for solar contractors to help meet the growing demand for solar in San Francisco, however. Much of the demand will be met with utility-scale projects, said White.

Expect an uptick in projects from Pacific Gas and Electric Co.’s (PG&E) Solar Choice options, which are available to the large building owners.

Under the program, part of a statewide initiative, investor-owned utilities must procure their renewable energy following guidelines from the California Public Utilities Commission. PG&E provides details on its website about how it sources renewable energy for the program.

The city of San Francisco also gives businesses and residents the option of buying "SuperGreen" power.

San Francisco Aims to be Carbon Neutral

The initiative for large buildings is part of the city’s effort to use only renewable electricity by 2030 across the city and to become carbon neutral by 2050.

About 44 percent of San Francisco’s greenhouse gas emissions are released by buildings, and about 50 percent come from commercial structures. While the transportation sector produces higher amounts of greenhouse gases, it’s expected that it will be easier to focus first on buildings, because owners can switch to their utility’s green power options.

As Clifford says, with such efforts to reduce cities’ carbon footprints becoming more commonplace across the country, the solar industry is sure to benefit.

“The opportunity for the solar community – from contractors to financiers – is immense and it is up to them to meet this challenge head-on to build and fund these new projects,” he said.

 

Topics: solar policy, solar industry

How to Optimize Your Solar Designs for New Net Metering Rules

Posted by Andrew Gong on Jul 24, 2019 7:30:00 AM

If you’re a solar salesperson or contractor in the U.S., you know that net energy metering (NEM) policies—which traditionally pay solar system owners the retail electricity rate for the solar energy they produce—play a key role in providing a strong return on a solar investment.

But you may also have observed the trend of utilities around the country, modifying and scaling back their net metering rules. We took a close look at this a phenomenon in our recent white paper, Analysis of U.S. Net Metering Policy Changes in the United States, so we could tell you the impact of specific policy changes and how to adapt to them.

In our previous article, we shared our findings on how some of these common net metering changes impact solar customers’ solar savings and utility bills. This follow-up blog post provides a quick visual summary of how those rules result in new design rules of thumb to maximize your customers’ solar savings. (In our white paper we provide more detailed recommendations for maximizing NPV under specific utility's policies.) 

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Designing Around Export Rules

NEM rules that reduce the value of exported solar energy will impact all customers who export energy to the grid. One bright side is that customers who self-consume all of the energy their PV system produces won’t be bothered by the change.

Here’s a convenient way to look at the customer’s annual utility bill against their energy offset level, for a household with moderate energy consumption:

solar customers' annual bills by energy offset percentage under traditional and new net metering

The important points on this graph are where the chart “bottoms out”—this represents where a customer’s bill is comprised only of minimum or fixed charges. Adding more PV panels after this point won’t increase the customer’s solar savings any further. While some customers might see a small amount of cash credit from net surplus compensation, it doesn’t justify the additional cost to increase the system size.

A second important takeaway is that the reduction in exported value—whether it be from a non-bypassable charge, fixed export rate, or percentage reduction—results in needing a larger system (read: greater energy offset) to reach that level.

If we look at the Net Present Value of a PV system (essentially the equivalent cash value of all of the costs and savings for the project) it tends to get maximized at the point which the customer’s bill is minimized.

NPV of solar PV systems at different energy offset percentages under traditional and new net metering policies

Looking at the curves, it’s clear that these value-reduction rules reduce NPV; however, in many cases, they also move the peak of that curve further to the right: customers need a larger system to maximize their NPV. Installers could use this to try to upsize systems creating a win-win for both themselves and customers, but they should also be careful to not exceed sizing limitations of the customer’s utility. For example, NV Energy has a fairly strict 100% offset limit which puts the target 105% out of reach, but other areas do offer the option to go larger.

What to learn more about the impacts of these solar net metering changes? Watch  a recording of our webinar with Utility Dive!  

Finding the Best Payback Period

The payback period of the system is how long it takes for a customer to recoup their investment, in terms of nominal dollars. An interesting case with a tiered rate structure is that a partial-offset system, say around 50%, might offer the minimum payback period because it offsets the more expensive energy in higher price tiers. Adding on more PV after this point is still advantageous in terms of NPV, but it will increase the payback period by a few months to a year.

However, in the case of utilities that have implemented a flat export rate for solar customers instead of pricing their exported energy based on their current usage tier, you lose this effect. There’s no longer an incentive to sit at the midpoint of energy offset to reduce payback time.

Payback periods for solar installations under net metering policies with different flat export rates

Sizing Guidelines Under Disadvantageous Expiration Policies

There are several states and utilities that have established expiration times for accrued solar energy credits that are disadvantageous for the solar customer. The seasonal nature of solar makes it so that a credit expiration cycle at the end of summer or early winter forces the homeowner to buy energy in the winter months without the option to offset these costs with credits from their prior solar energy production.

We found that customers whose utilities do not allow them to carry net metering credits from one month to the next (or who only get wholesale avoided cost compensation) will start to lose credits if their system offset is greater than 70%. That might be a reasonable threshold to target when designing in regions that have this ruleset.

For customers with a specified annual credit expiration cycle, the decision is a little more complex. Customers with an expiration month in June, July, and August will often see credit loss above a 75% offset threshold. If the cycle ends in April, May, September, or October the threshold is around 85%, and November, December, and January expirations might see losses at a threshold of 90%. February and March expiration months are almost equivalent to a utility policy where the credits aren’t reset every year.

How many net metering credits are lost for solar customers depending on their utility's credit expiration month

Finding the optimal solar design for your customer can be challenging and utility changes to net metering rules add additional complexity. However, having a solid grounding in these best practices can help.

To see our full findings on this topic, including specific recommendations for how much of your customer’s energy consumption to offset in different utility regions, download the complete white paper.

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Topics: solar design, net energy metering, solar policy

Solar Policy Round-up: 9 Wins in the First Half of 2019

Posted by Sunny Wang on Jul 11, 2019 1:53:38 PM

There have been a number of positive developments for the solar industry in the U.S. in 2019 to date. The biggest news so far has to be the movement toward 100% renewable energy. Maine, Maryland, Nevada, New Mexico, Puerto Rico, Washington, and Washington, D.C. all codified their commitment to 100% renewable energy earlier this year—that’s a total of seven states and U.S. territories! They join California, Hawaii, New Jersey, Wisconsin, and Minnesota which have also formally committed to 100% clean or renewable energy targets.

Two other big wins are community solar and residential net metering. Colorado and Maine enabled larger-scale community solar projects, and South Carolina provided pathways for community solar to grow; Maryland extended their pilot program through 2022. Maine restored their residential net metering that the previous administration rolled back, and South Carolina eliminated net metering caps while extending existing rates for two years. In addition to committing to 100% renewable energy, Puerto Rico also protected net metering for five years in the same bill.

There is a lot of work still to be done for solar in the U.S., but with many of the solar policy development highlights from 2019 being positive, a quick celebration for these wins is in order!

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These 9 states and territories/districts had notable solar policy changes in 2019.

Colorado

Earlier this year Colorado Governor Jared Polis signed a flurry of climate and renewable energy bills, seven to be exact! Among them is the Community Solar Gardens Modernization Act (HB 19-1003) which increases the maximum size of community solar projects from 2 MW to 5 MW, with the cap eventually increasing to 10 MW.

Polis also unveiled a roadmap that would take Colorado to 100% renewable energy by 2040.

[Fun Fact: The Coyote Ridge Community Solar Farm in Fort Collins, Colorado is the largest low-income community solar project in the U.S. at 1.95 MW.]

Maine

Maine is also having a great year in solar friendly bills. Governor Janet Mills signed three big solar energy wins—committing the state to 100% renewable energy by 2050, reducing barriers to access clean and affordable solar power, and restoring net metering.

An Act To Reform Maine’s Renewable Portfolio Standard (LD 1494) increases the state’s Renewable Portfolio Standard (RPS) from 40% today to 80% by 2030, with a goal of 100% by 2050. Among many other benefits, An Act to Promote Solar Energy Projects & Distributed Generation Resources (LD 1711) will create new jobs, create a grant program to support the installation of over 375 MW of distributed solar, and enable larger-scale community solar projects.

Additionally, An Act to Eliminate Gross Metering (LD 91) restored residential net metering in Maine. Maine for many years had net metering, but it was rolled back during the administration of former Maine Governor Paul LePage. Now, residents who own their systems will again receive a one-to-one credit for supplying excess energy back to the grid—a huge win for solar customers in the state!

Maryland

Maryland’s Clean Energy Jobs Act (SB 516) became law without Governor Larry Hogan’s signature, and commits the state to 100% renewable energy by 2040, with an interim goal of 50% by 2030. This bill also increases the requirement for 2.5% in-state produced solar to 14.5%, provides funding for clean energy workforce development, and requires utilities in the state to subsidize solar and wind. The in-state solar requirement is especially noteworthy because it’s one of the most aggressive (if not the most) of any state RPS policy.

Community solar also got a win in Maryland with the enactment of Extension of Community Solar pilot (HB 683), which extended the state’s community solar pilot program through 2022. The bill also removed the cap on the number of subscribers per project and increased the allowable generating capacity per system.

See how Aurora helps solar companies grow revenue, cut costs, and impress their  customers!

Nevada

On Earth Day, Nevada Governor Steve Sisolak signed SB 358 and raised the state’s RPS to 50% by 2030 and committed the state to 100% clean energy by 2050. This legislation sped up what Nevada voters approved last year—to include an increase to the state’s RPS in their constitution; the state now does not need to hold the second vote required to approve constitutional change.

New Mexico

In March, New Mexico officially committed to 100% renewable energy by 2045, with interim targets of 50% by 2030 and 80% by 2040 when Governor Michelle Lujan Grisham signed the Energy Transition Act (SB 489).

The state’s largest utility, Public Service Company of New Mexico (PNM), also supports the bill. PNM had already filed plans to shut down its coal assets, and SB 489 provides a system to help ease the closure of San Juan Generating Station. It establishes a financing system to make up for revenue lost, a $20 million fund to aid displaced coal workers, and job training programs for the renewable energy industry.

Puerto Rico

On April 11th, Puerto Rico Governor Ricardo Rossello signed the Puerto Rico Public Policy Act (SB 1121) committing 100% renewable energy bill by 2050 with interim goals of 40% by 2025 and 50% by 2040. This bill also requires a complete transition away from coal by 2028; there is only one coal plant on the island.

Additionally, it protects net metering for five years, mandates automatic interconnection for systems under 25 KW, and reduces approval time to 90 days for commercial and industrial solar projects. Puerto Rico's Electric Power Authority is planning to rebuild the island’s grid into eight mini-grids.

South Carolina

In South Carolina, net metering caps were eliminated and existing residential solar rates were extended for two years with Governor Henry McMaster’s signature for The Energy Freedom Act (HB 3659 / SB 332). This bill also provides pathways for community solar to grow and removes restrictions to expansion of affordable solar options.

Washington

Washington not only committed to 100% renewable energy by 2045 with Governor Jay Inslee’s signature on the 100% Clean Electricity bill (SB 5116 / HB 1211), the bill also requires the state’s utilities to ramp off of coal power completely by 2025 and to be 100% carbon-neutral by 2030.

Washington, D.C.

In January, Governor Muriel Bowser signed the Clean Energy DC Omnibus Amendment Act of 2018 (B22-0904) setting a goal of 100% renewable energy by 2032. This bill is by far the most ambitious in terms of target date for all electricity sold to come from renewable sources. Among other action items, this bill will double the District’s required amount of solar energy, provide energy bill assistance to low- and moderate-income residents, and fund the DC Green Bank to attract clean energy projects.


These state actions in the first half of 2019 paint a positive picture for the future of the solar industry and are great news for solar contractors. What other policy developments are you excited about? Let us know in the comments below!

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Topics: solar policy

The 100% Clean Energy Revolution is Here–with Big Solar Opportunities

Posted by Gwen Brown on Dec 12, 2018 12:49:06 PM

Not only do solar and other renewable energy sources enjoy broad support among individual Americans (9 out of 10 support solar according to SEIA!), local governments have also been demonstrating increasing clean energy commitment. In fact, this month, Cincinnati, Ohio became the 100th U.S. city to set a target of sourcing 100% renewable energy!

The Sierra Club, whose Ready for 100 campaign supports communities in committing to 100% renewable energy, estimates that 15% of the U.S. population now lives in a city with a 100% clean energy target. An additional 11 counties  and 4 states–Hawaii, California, New Jersey, and, most recently, New York–have made comparable commitments. The city council of Washington, D.C. has also committed to 100% renewable energy, pending approval by the mayor and Congress.

Add to that the numerous other state actions in favor of clean energy this year and the over 400 mayors representing 70 million people that have expressed support for the Paris climate agreement, and it’s clear that support for solar and other clean energy is reaching unprecedented levels.  

The importance of these commitments can hardly be overstated, particularly in light of the recent report by 13 federal agencies which identified drastic climate change impacts for the U.S., including significant contraction of the country’s economy. Fortunately, investment in renewable energy can significantly reduce carbon emissions while driving economic benefits and job growth. Not to mention it can create significant business opportunities for the solar industry!

In today’s blog post we explore what local commitments to 100% renewable energy mean for solar–particularly how solar contractors can get involved in the clean energy transitions of their local communities.

Which cities and towns have committed to 100% renewable energy?

Cities all across the country have made commitments to 100% renewable energy, including Atlanta, Boulder, Minneapolis, Salt Lake City, San Diego, San Jose, St. Louis, Cleveland, and many, many more. For the full list, and contact information for city representatives, see the Sierra Club’s list of 100% Renewable Energy Commitments.

Metadata: Cities that have committed to sourcing 100% clean energy, courtesy of Sierra Clubs Ready for 100 campaign for 100% renewable energy.Cities that have committed to 100% renewable energy (white dots) and cities already powered by 100% renewable energy (blue dots). Not pictured is Kodiak Island, Alaska (powered by 100% renewable energy). Source: Sierra Club Ready for 100.

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What is involved in a city’s commitment to 100% renewable energy?

You might be wondering what it really means when a city commits to 100% renewable energy. Does the commitment only apply to electricity use by the local government, or does it apply to all residents and local businesses? While the specific commitments vary by city, many of these local commitments cover the electricity consumption of the entire community.

As the Sierra Club explains, its 'Ready for 100' campaign recognizes community commitments... where a city’s leadership has established a goal to transition to the entire community to 100% clean, renewable energy. This can be through a stand-alone Resolution or Proclamation, or integrated into a community's Climate Action Plan or Energy Action Plan.”

In the case of Cincinnati, the city has committed to sourcing 100% of electricity for residents and small businesses from renewable energy by 2035. The first stage of that commitment will involve 25 megawatts of solar development, and the city is exploring potential project sites.

For communities interested in similar commitments, the Sierra Club offers policy guidelines, including recommendations that local clean energy mandates consider justice, equity, affordability, and access to clean energy, and that they follow a transparent and inclusive planning process.

What do local commitments to 100% renewable energy mean for solar companies?

As you might expect, these local commitments can open up a lot of business opportunity for solar companies to help meet the community energy needs with solar. Like Cincinnati, many of these cities are actively working to encourage the development of local solar projects or directly soliciting bids from solar companies.

Utility Dive reports that a partnership of 20 cities–including Boston, Chicago, Houston, Los Angeles, Portland, and Orlando–have teamed up to jointly issue Requests for Proposals (RFPs) for collectively purchasing a total of 5700 GWh renewable energy!

Similarly, Los Angeles, San Francisco, Portland, and Seattle have jointly issued a Request for Information (RFI) for electric vehicle charging infrastructure development valued at more than $10 billion.

Other examples of cities incorporating solar development into their 100% renewable energy commitments include:

  • Concord, New Hampshire–planning a large solar plant on a closed landfill and changing local zoning to better accommodate local solar projects
  • Denton, Texas–approved a contract for a 100 MW solar project
  • Denver, Colorado–in addition to a community solar program, Denver is requiring all new construction to be net zero by 2035, a move which may encourage more solar on new construction
  • Fayetteville, Arkansas–exploring solar projects on its municipal buildings
  • Orlando, Florida–in addition to other pro-solar initiatives, Orlando’s Collective Solar cooperative helps residents take advantage of economies of scale when purchasing solar

While the specific plans for achieving 100% renewable energy vary by city, if there are cities in your area with such commitments it’s worth taking a close look at their procurement plans. In particular, check to see if they include RFPs or other opportunities for your solar company to participate in local solar development. For those interested in learning more, the Sierra Club’s Ready for 100 list includes contact information for local representatives who can provide more information on particular programs.

Even if your local area doesn’t have a 100% clean energy commitment, take a look at what other clean energy initiatives they have. Many cities and towns without such ambitious targets still have powerful incentives for advancing local clean energy. For example, Watertown, Massachusetts recently passed a measure requiring solar installations on all new commercial buildings over 10,000 square feet.

If your locality doesn’t have clean energy policies, consider talking with your local representatives about how clean energy can benefit your community. After all, as a solar contractor, you know the ins-and-outs of solar project development and can be a valuable source of information for your elected leaders. Around the country, local communities are leading the way on the clean energy transition–which is good news for the environment, the economy, and the solar industry!

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Topics: solar policy, Solar Business Tips

The 2018 State Solar Policy Changes You Need to Know

Posted by Gwen Brown on Dec 5, 2018 11:37:00 AM

[Editor’s note: This article was originally published on May 16, 2018. It was updated on August 27, 2018 and again on December 5 and 24, 2018 to reflect new policy developments. The December updates reflect new solar policy changes in CaliforniaIllinois, Kansas, Maryland, Massachusetts, Nevada, New York, PennsylvaniaVirginia, and Washington.]

The solar industry is always dynamic, and keeping track of the latest developments around the nation can be tricky. Although 2018 got off to a rocky start with the federal government’s decision in January to impose a 30% tariff on foreign-manufactured solar components, there have since been a plethora of state-level policy developments that paint a more positive picture for the industry.

Actions by California, New Jersey, New York, and Washington state to commit to 100% renewable or carbon-free energy were especially noteworthy. Nevada also established an ambitious clean energy targets of 50%. California also made the striking decision to require solar installations on new homes. This move—by the world’s fifth largest economy—will help normalize solar technologies and massively expand the solar market.

Additionally, Hawaii’s redesign of utility incentives provides a model for how utilities can benefit from solar growth. Virginia’s major utility took the first steps toward significant solar procurement in accordance with a new state law. Illinois, New York, and Massachusetts updated their solar incentive programs and Maryland offered grant funding for solar-plus-storage projects to improve resilience.

Not all of the state-level actions in 2018 were supportive of solar, however. In particular, rollbacks of net metering may dampen the solar markets in Michigan and Connecticut. Massachusetts and, more recently, Kansas approved demand charges for solar customers. Despite these setbacks, overall 2018  demonstrated that many states recognize the value of solar and other renewable energies and are ready to take action. 

Solar Policy Developments- Map Update Dec. 2018

Just interested in a particular state? 
Click on one to jump ahead:

CaliforniaColoradoFloridaHawaii, Illinois, Maryland, Massachusetts,
New Jersey, Nevada, New York, PennsylvaniaUtah, Virginia, Washington
Connecticut, KansasMassachusettsMichigan


(Green indicates positive developments for solar and orange indicates negative ones. Massachusetts had both and appears in both sections.) 

The Good News

California

By far the biggest state policy updates, in terms of impacts for the solar industry more broadly, came out of California this year. California mandated that all new homes include a solar installation starting in 2020, as part of a requirement to make homes net zero. Additionally, in September, California Governor Jerry Brown  signed legislation requiring all of the state's energy to be carbon-free by by 2045. As the fifth largest economy, California's decisions on these issues have massive implications for the growth of solar energy.

The Solar on New Homes Mandate

On May 9th, the California Energy Commission mandated that nearly all new homes have rooftop solar starting in 2020. The changes, part of the state’s newly approved 2019 Building Energy Code, received final approval on December 5th.

The decision will significantly increase demand for solar energy; Greentech Media predicts a 14% increase in total U.S. solar sales over the next four years as a result! It also represents an important shift in making solar energy a new normal for consumers. Resulting industry changes may also contribute to falling costs for California solar installations.

(For a detailed overview of the policy and related business opportunities for  solar contractors, check out our on-demand webinar!)

This announcement will spur further growth in the California solar market, which has more installed solar than any other state by a factor of five according to SEIA. 

California solar policy change: rooftop solar required for all new homes in 2020

SB 100: Carbon-free Energy for California by 2045

In September 2018, California Governor Jerry Brown signed into law Senate Bill 100 which establishes a target of providing 100% of the state's electricity from carbon-free sources by 2045. In addition to creating a path to complete clean energy, the bill accelerates the pace of California's clean energy transition–increasing to 60% (from 50% previously) the amount of energy that must come from renewable sources by 2030. California is the second state to make a 100% clean energy commitment after Hawaii, which made that commitment in 2015. 

At the signing ceremony, Brown also announced an executive order to make California carbon neutral also by 2045, meaning that it would need to remove as much carbon dioxide from the atmosphere as it emits. 

In September 2018, California's Senate Bill 100 became law requiring 100% of its electricity to be carbon-free by 2045.

Colorado

Colorado became one of the first states to designate energy storage as a consumer right when Colorado Governor John Hickenlooper signed SB 18-009 into law in late March. The law states that residents should be able to install, use, and interconnect energy storage systems without unnecessary restrictions or discriminatory rates. It calls upon the Colorado Public Utilities Commission to establish rules governing customer-sited energy storage. 

Colorado solar policy change: energy storage deemed consumer right

Florida

In a notable development for the Florida solar market, the Public Service Commission issued a statement in late April declaring that residential solar leases are allowed in the state. Previously, solar leases were deemed “third-party electricity sales,” which are prohibited in Florida.

Sunrun successfully argued to the commission that solar leases should be allowed because the payments are fixed and not contingent upon the amount of solar electricity the system produces. Florida solar customers now have a new financing option to choose from and solar companies in the state can offer a new product. 

Florida solar policy change: Solar leases are now legal in Florida

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Hawaii

Hawaii is changing the revenue model for investor-owned electric utilities to better align their incentives with the growth of solar and energy storage. The measure, signed into law in April, is expected to aid the process of modernizing the state’s electricity grid because utility revenues will now be linked to performance metrics. The use of distributed energy resources like solar, rather than investment in costly new utility-owned infrastructure projects, will be incentivized.

This is big news. Utilities are a major player in the power sector, and their support or opposition is a major determining factor in solar market growth. Better aligning utility incentives with solar growth, as states like Hawaii and New York have endeavored to do, presents new opportunities for utilities to support the growth of renewable energy.

[Note: For related insights on how new revenue models for utilities can advance the growth of solar, see Aurora’s interview with Dr. Varun Sivaram.]

Hawaii solar policy change: utility incentives now favor solar, storage

Additionally, in July, regulators ruled that existing solar customers in Hawaii who have net metering agreements (from prior to the state’s elimination of net metering in 2015), may now add energy storage systems without voiding the terms of their metering agreement.

Illinois

In April, Illinois regulators produced a plan to procure 25% of the state’s energy from renewable sources by 2025, as required under the Future Energy Jobs Act passed in 2016. Not only does the plan cover large investor-owned utilities, it also includes smaller, municipal utilities and rural electric cooperatives–which solar advocates say will make solar incentives more accessible to low-income and rural customers.

The policy impacts the state’s Renewable Portfolio Standard, which allows utilities to source some of their required renewable energy in the form of credits (Renewable Energy Certificates, including solar-specific SRECs) produced by renewable energy system owners. Under the new policy, Illinois existing SREC program is being updated.

The SREC program will now become an adjustable block rate program, in which solar will be compensated at a set flat rate (which declines as certain levels of installed capacity are hit), rather than a traditional SREC market where prices fluctuate based on market dynamics. Additionally, the SREC incentive program now lasts for 15 years, rather than the previous 5 year limit. The details of the program are still being finalized, but it will go into effect sometime in 2019. 

Illinois solar policy: In 2018, Illinois announced plans for sourcing 25% renewable energy by 2025, including changes for its SREC program

Aurora's financial analysis tools can model a wide variety of state and local  incentives. See how in a free demo. 

Maryland

In November, the Maryland Energy Administration launched a program to create “resiliency hubs,” powered by solar and energy storage, in disadvantaged communities. The program makes $5 million in grant funding available to solar and storage providers to help ensure low-income residents have access to basic services during power outages. The deadline for grant applications is March 1, 2019 and more information on the program can be found here.

Maryland solar policy: Maryland announced funding for resilience hubs - available to developers of solar + storage projects

Massachusetts

In October, the Massachusetts Department of Energy Resources approved compensation for owners of new solar projects under the state’s Solar Massachusetts Renewable Target (SMART) program, a successor to its previous SREC incentive program.

Like SRECs, the SMART program is a production-based incentive, meaning that PV system owners are compensated based on the amount of energy their system produces. Unlike the SREC program, however, system owners receive a fixed rate of compensation per unit of energy produced rather than being compensated a variable amount based on market demand.

The program is a declining block incentive program (similar to Illinois’ incentive program), where compensation rates will gradually decline over time as certain levels of installed capacity are reached. Applications for SMART compensation opened on November 26, 2018. Although compensation under this new program will be somewhat less than under the previous SREC program which had reached its limit, the program maintains incentives for solar customers and provides much-needed certainty to the industry.

Massachusetts solar policy: Massachusetts launched its SMART solar incentive program in 2018, replacing its SREC program

New Jersey

The New Jersey solar industry also got good news this year. Governor Phil Murphy signed into law several key energy bills, including one that updates the state’s Renewable Portfolio Standard, requiring 35% of its power to come from renewables by 2025 and 50% by 2030. In addition, the law establishes the most ambitious solar-specific target in the nation, requiring that utilities source ~5% of their energy from distributed solar by 2021.

The law also includes a 600 MW energy storage target and establishes a community solar pilot program for the state. It also establishes a planned phase out of New Jersey’s SREC program in 2021 but calls on regulators to establish a successor program to support distributed New Jersey solar projects. 

In other positive news for clean energy advocates, Governor Murphy also signed an executive order requiring the development of an Energy Master Plan providing a comprehensive plan for the state to reach 100% clean energy by 2050.

NJ Renewables Target graphic-updated

 

New York

In October, New York Governor Andrew Cuomo announced that the state will make $40 million of incentives available to support solar-plus-storage projects. The initiative is intended to advance New York’s existing commitments to source 50% of its electricity from renewable sources by 2030 and install 1500 MW of energy storage by 2025.

The funds will be available as part of New York’s existing Megawatt Block incentive program. Eligible projects with energy storage will be able to receive an additional incentive of $350 per kWh of installed storage capacity. Solar projects that have already been approved for the state’s existing incentives may be approved for these new incentives if they add energy storage.

New York solar policy change: $40 million in incentives now available for solar + storage projects

Then, on December 17, 2018, Governor Cuomo pledged the state to 100% carbon-free electricity by 2040 in a speech announcing his policy agenda for early 2019. The move builds upon the state’s existing strong commitments to renewable energy.

New_York_Solar_Policy_Changes2-100_percent_carbon-free

Nevada

In the midterm elections in November, Nevada voters approved a ballot initiative (”Question 6”) to increase the state’s Renewable Portfolio Standard (RPS) to require utilities to source 50% of their electricity from renewable energy by 2030. This is a significant increase from the state’s previous RPS which called for 25% renewables by 2025, and another great example of states leading the way on clean energy policy.

Nonprofit advocacy group Vote Solar worked to build support for the measure, and the Natural Resources Defense Council estimated that the policy could contribute to the creation of 11,170 full-time jobs and $1.5 billion in economic activity in 2030.

Nevada solar policy change: Nevada will seek to source 50% of electricity from renewables by 2030

 Pennsylvania

Pennsylvania has lagged behind neighboring states like New Jersey and Maryland in solar development. A new initiative announced by the Pennsylvania Department of Environmental Protection (DEP) may help change that.

Funded by a Sunshot grant from the U.S. Department of Energy, the state has initiated a 2-year planning process called “Finding Pennsylvania’s Solar Future” which is exploring approaches to provide 10% of the state’s energy from in-state solar by 2030, including changes to Pennsylvania’s Alternative Energy Portfolio Standards (it’s RPS).

A key output of the collaborative planning process is Pennsylvania’s Solar Future Plan, a set of recommendations released in November 2018 which includes 15 recommended strategies. The next step will be the development of an Implementation Report which will provide direction on how to implement the plan.

However the plan is implemented, it’s likely to be good news for the solar industry in Pennsylvania. The DEP predicts the plan could create between 60,000 and 100,000 new jobs, and as much as $1.6 billion in economic benefits annually.

Additionally, Governor Tom Wolf signed a bill earlier this year allowing commercial PACE (C-PACE) financing in the state, which would allow commercial property owners to repay solar loans via their property taxes, in municipalities that establish C-PACE programs.

Pennsylvania solar policy change:

Utah

Two new policies with important implications for the Utah solar industry were signed into law by Utah Governor Gary Herbert in late March. One extends a $1,600 tax credit for residential Utah solar customers for an additional two years. The credit will begin to be phased out in 2021 over a period of three years. The other is a consumer protection measure that requires solar companies provide all residential customers with a disclosure statement to help ensure they understand the terms of their contracts. SEIA has applauded these developments.

These developments, particularly the tax credit, are welcome news for Utah’s solar industry since recent data show a slowdown in its rooftop solar market, likely stemming from a 2017 change to the state’s net metering approach.

Utah solar policy update: tax credits extended, consumer protection measure passed

Virginia

The solar industry in Virginia is poised to surge as a result of its Grid Transformation & Security Act of 2018 which states, among other things, that 5000 MW of solar development by utilities is in the interest of the state. In October, Dominion Virginia Power issued a request for proposals (RFP) for 500 MW of solar projects, to be developed by 2020.

The projects may either be sold to Dominion or it will purchase the energy they produce through 20-year power purchase agreements. The resulting solar development will be utility-scale, with the minimum allowable project size being 5 MW. 

Virginia solar policy change: A new law states that 5000 MW of solar is in the state's best interest; Dominion Power is now seeking 500 MW in solar

Washington

On December 10, 2018 Washington Governor Jay Inslee released an ambitious clean energy proposal that addresses “five policy goals: 100% clean energy by 2045, transitioning to electric transportation, adding a clean fuel standard, constructing energy efficient buildings and eliminating hydrofluorocarbon.” As part of the transition to 100% clean energy, coal-fired power plants would be phased out by 2025. The proposal also calls for the reduction of over 80 million metric tons to limit them to 25% below 1990 levels by 2035.

Washington_Solar_Policy_Changes

The Bad News

Connecticut

Despite vocal opposition from the Connecticut solar industry, the state recently eliminated net metering for solar customers. The bill, which advocacy groups had decried as a serious threat to 2000+ Connecticut solar jobs was signed into law by Governor Dannel Malloy in June. 

As written, the policy would set a new flat rate for solar compensation, though the exact structure that will be implemented remains to be seen. The decision now goes to the state Public Utilities Regulatory Authority for review and rate setting. One bright spot in the bill is that it establishes a target of 40% renewable energy by 2030 under the state’s renewable portfolio standard by 2030.

Connecticut Net Metering Elim graphic- revised Aug. 2018

Kansas

While many states took steps to advance the growth of the solar industry, Kansas took a step back this year. In September, Kansas regulators approved a new charge that only applies to solar customers of the state’s largest electric utility, Westar Energy. The demand fee–of $9 per kilowatt in summer and $3 per kilowatt at other times of the year–is expected to cancel out the savings for many smaller solar projects, reports Midwest Energy News. The fee will apply to solar systems installed in 2015 and later, including new systems.

Demand charges, while common for commercial customers, have historically been rare for residential customers (though Massachusetts also applied residential demand charges this year, as discussed below).These charges are based on the maximum amount of energy the customer used during any (usually 15-minute) interval during the month. They are very difficult for customers to control and, as we discuss in a commercial case study, can significantly reduce solar savings.

Kansas solar policy change: regulators approved hefty demand charges for solar customers in 2018

Massachusetts

In one of the first blows to solar energy this year, Massachusetts approved new charges for new solar customers in January. At the same time, the state became the first in the nation to approve demand charges for all residential net metering customers starting in 2019, a “charge without a cause” according to industry groups.

A bill passed by the Massachusetts Senate in June raised hopes that the demand charge might be repealed. Unfortunately, the version ultimately agreed upon by the House and Senate and signed into law by Governor Charlie Baker on August 9th, did not contain the repeal language. It upholds the charges, stating that a ”distribution company may assess a demand charge if it is based on system peak demand during the hours of a day determined to be peak hours of system demand and if the distribution company regularly informs affected customers of the manner in which demand charges are assessed and of ways in which said customers might manage and reduce demand.”

Massachusetts solar policy update: Massachusetts applies fees and demand charges to solar customers

Michigan

Michigan dealt a serious blow to solar by eliminating net metering. In late April, the Michigan Public Service Commission elected to replace net metering with a new approach. Under this policy, solar customers will buy energy from the grid at the retail rate but be compensated for the solar energy they send to the grid at a significantly lower rate. That rate will be based on an estimate of how much the utility would otherwise pay to procure that power, an “avoided cost” calculation. Fortunately, current Michigan net metering customers will retain their current rates for 10 years, but the shift is a big loss for future Michigan solar customers.

[Note: For an overview of related trends, check out Aurora’s blog post on how net metering is changing—and being scaled back—around the country.]

Michigan Solar Policy update: In April 2018, Michigan eliminated net metering for future solar customers, significantly reducing savings from solar.

Although not all of the state policy changes to date this year were favorable for solar, it’s great to see so many states recognizing the value of solar and working to make it more accessible. We’re excited to see how solar continues to grow in the coming year!

Are there policy developments we missed?  Let us know in the comments below!

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Topics: solar policy

How Have Solar Tariffs Impacted the Industry–and What Can We Learn?

Posted by Sara Carbone on Oct 23, 2018 9:21:40 AM

Concerned about solar tariffs? You’re not alone!

Given that there have already been three tariffs introduced this year that affect the solar industry, it’s understandable if you’re concerned over their impact on your business.

In today’s article, we provide an overview of each of the 2018 solar tariffs to date and explore the extent of their impact so far. We spoke with David Dunlap, Vice President of Operations at Baywa r.e. Solar Systems, to get a distributor's perspective on the impact of these tariffs on contractors.

Tariffs have definitely caused some pain in the industry, but thankfully the repercussions have not been as dire as many initially expected–at least for solar contractors and customers. And, there may just be some lessons to be learned from the experience!

The Context

When the first solar tariff was announced in January 2018, there was a great deal of uncertainty about how it would impact the industry, but many feared the worst. An initial industry response predicted a loss of approximately 23,000 jobs in the solar sector. Indeed, cancellations of more than $2.5 billion in large installation projects by solar developers have resulted in a loss of thousands of jobs this year.

There were a lot of factors at play, however. M.J. Shiao of Wood Mackenzie Power & Renewables highlighted the multitude of forces impacting the economics of the solar market, in addition to the tariffs, in a GTM podcast. Among these were the upcoming reduction of the Investment Tax Credit in 2020, lower interest rates in general, the repeal of the Obama-era Clean Power Plan, and individual states’ efforts to drive their own pro-renewable policy agendas in response. Some of these elements have tempered the extent of the tariffs’ impact, particularly for residential and commercial installers.

Today, after some short-term turmoil, module prices have largely stabilized and the impacts of tariffs on other solar components are expected to be less severe. Dunlap explains, “Entering Q4 2018, PV module prices to installers are flat to 10% below [prices before the first tariff was applied in February 2018].”

The Solar Tariff on Panels and Modules: Section 201

In January 2018, the Trump Administration announced a 30% tariff on imported crystalline silicon PV panels and modules, imposed under Section 201 of the Trade Act of 1974. The decision came after two module manufacturers, SolarWorld and Suniva, argued they could not compete with the lower-priced imports. The tariff, which went into effect in early February, will be reduced by 5% a year over four years. The first 2.5 gigawatts of imported cells are exempt.

Though there was quite a bit of concern about the impact of this particular tariff, so far there has not been a dramatic market shift. Dunlap explains that “while there was a temporary spike in prices from the 30% tariff (effectively anywhere from 0% to 20%), we have since recovered to end of 2017 pricing while the manufacturers are still paying the 30% import tariff fee.”

Stockpiling and Supply Chain Pain

In anticipation of this tariff, many solar firms stockpiled their supplies. As Dunlap explains, “Manufacturers and distributors saw a huge spike in sales leading up to the tariff date (Q4 [of 2017] was huge, and January plus some of February were way above normal). This means that project development companies and large and medium installers stuffed their warehouses, and maxed out their cash reserves and credit lines to lock down inventory.”

“By April and May, sales slowed down dramatically, because the entire channel was stuffed with all this product purchased in advance. If we were to look at the total excess inventory bought by installers in Q4 + Q1 and spread it out over Q2 and Q3 2018, the total net sales to installers would be right in line with overall market expectations for 2018, which was flat to maybe only 10% up year over year.”

He says that only later did it become apparent that the module price increase caused by the tariff was temporary because manufacturers were ultimately forced to reduce prices to stimulate demand (while still paying the 30% import fee). However, Dunlap does point out that many installers who stockpiled are struggling with resulting challenges around cash flow, storage costs, and credit lines.

Dunlap also notes that in many cases residential customers were insulated from a net price increase. This is because many installers who had to absorb the temporary 10%-15% spike chose not to pass on the price increases to the customer.

Other Factors Influencing Module Prices

Another global policy factor which seemed likely to impact U.S. panel prices was China’s mid-year decision to halt the majority of it’s solar development, which eliminated 20 GW of global demand for solar and shifted the panel market to one of oversupply. According to Dunlap, however, that ultimately the policy change had little impact in the U.S. because earlier anti-dumping tariffs had shifted module imports from China to Southeast Asian countries like Malaysia and Thailand,

However, he does predict additional price reduction due to the expiration of the Minimum Import Price for Chinese modules in Europe. This has “opened the floodgates for excess Chinese capacity to go to Europe at far lower prices than had previously been allowed.” Already prices have dropped 30% in four weeks. Dunlap says this will remove European demand for Southeast Asian products, leaving the U.S. as the only real market for their modules–driving prices down even further.

Solar Tariffs on Additional System Components: Sections 232 and 301

In March, the Trump Administration imposed a 25% tariff on steel and 10% tariff on aluminum under Section 232 of the Trade Expansion Act of 1962, increasing prices for racking, wiring, and ground mount posts.

Then, in August, a 25% tariff implemented under Section 301 of the Trade Act of 1974 was placed on a host of imported Chinese goods – including solar cells and modules. Another tariff was added to Section 301 on September 24 that includes solar inverters and non-lithium batteries; it starts at 10% and increases to 25% in January.

Once again, the impact of these tariffs is not thought to be dire. As Dunlap mentioned, Chinese cells and modules make up a small fraction of U.S. solar imports (11% reports PV Magazine). Plus, most new factories planned for the U.S. will not be affected because they use materials that do not come from China.

Dunlap believes that “Looking ahead to the Section 301 tariff affecting certain Chinese-manufactured inverters, the net impact to the overall system will be much lower than in the Section 201 tariff on PV modules, because inverters are a lower portion of the total system equipment cost than PV modules.” Plus, “it won’t even affect all manufacturer brands, so therefore won’t affect all installers and homeowners.”

He also notes that since equipment prices have dropped so much over time, hardware now represents a much smaller piece of the overall system cost.

Conclusions

The 2018 solar tariffs have certainly had an impact on the American solar market. Amanda Levin, a policy analyst for the Natural Resources Defense Council, recently noted that the solar market would almost certainly be growing more rapidly if the current administration had not imposed these tariffs.

Cory Honeyman of GTM Research, whose organization lowered its prediction for additional U.S. solar generating capacity for the next five years by 11%, stated, “There’s just a lot of demand that could have happened that is not going to ultimately be realized because of these tariffs.”

But although the solar industry could be growing faster if tariffs had not been imposed, the prediction continues to be for rapid growth for solar in the U.S. The SEIA Solar Market Insight Report 2018 Q3, released in September, showed some positive numbers including the prediction that total U.S. installed PV capacity will more than double over the next five years. As of July, there has only been a loss of 8,000 solar jobs.

For Dunlap, the industry’s response to tariffs offers some lessons for the future. “In retrospect, I think our collective industry fear about the potential negative impact on the consumer market caused us to act somewhat irrationally to “safe harbor” more product than we actually needed… and caused financial stress on all organizations…. All of that stress and effort resulted in very little change to the rate of new installations in the end.”

“As our industry grows up, I hope we can manage cost changes in healthier ways.” He concluded his remarks by noting that “there is very little room for additional cost reductions in solar equipment with current technology, and as an industry, we need to focus our value-engineering efforts on non-hardware costs, which have much more room for improvement.”

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Topics: PV System Costs, solar policy

California’s Solar Mandate for New Homes: What You Need to Know

Posted by Gwen Brown on Aug 29, 2018 10:09:35 AM

[Editor's note: This article was updated on December 6, 2018 to reflect formal approval of the policy by the California Building Standards Commission.]

As you may have heard, California recently became the first state to mandate solar PV systems on all new homes. This is a momentous decision for the industry; it brings the benefits of solar, a historically niche product, directly to a significant portion of homeowners. The policy will dramatically expand the size of California’s solar market–already the most mature in the nation–and perhaps it will eventually inspire similar action in other states.

For California solar companies that position themselves effectively, this could open up some great opportunities to serve a vast new sector. In today’s article, we detail what’s required under the new policy so you can make sense of what’s changing and assess the market opportunities.

Interested in learning more about the resulting market changes, business opportunities, and how your company can get involved?Check out our recent webinar with Solar Power World!

What policy establishes California’s new home solar mandate?  

On May 9, 2018, the California Energy Commission (CEC) approved the 2019 Building Energy Efficiency Standards. What’s significant in this update to the Building Code is that, starting in 2020, every new home built in California will be required to have a PV system installed. (That is unless the building qualifies for an exception, of which there are a few). The policy got official approval from the California Building Standards Commission in December 2018. 

What types of buildings are covered under California’s solar mandate for new homes?

The code states that the solar requirement applies to “all low-rise residential occupancies including single-family homes, duplexes, garden apartments, and other housing types with three or fewer habitable stories.” This includes multi-family housing like apartment buildings as long as they are under three stories. And for single-family homes, it doesn’t matter how tall the building is–all homes of that type must comply.

California’s mandate of solar on new home requires solar PV systems be installed on all new homes, including both single-family and low-rise multi-family homes.California’s mandate of solar on new home requires solar PV systems be installed on all new homes, including both single-family and low-rise multi-family homes.

There are a few exceptions under which a home would not be required to have a PV system (such as including when there is limited unshaded roof space) or would be allowed to install a smaller system. Multistory buildings with limited roof space and homes that incorporate energy storage can qualify for a smaller PV system. Additionally, buildings that are permitted prior to January 1, 2020 will be exempted from the requirement.

What is required to comply?

One of the most important things to understand is the required size of the PV system under California’s solar mandate for new homes. The policy establishes a minimum PV system size for a home based on the building’s projected annual electrical usage. 

Minimum PV system size is calculated based on the conditioned floor space (square feet) and the climate zone where the building is located. (To determine what zone your building is located in, you can use the EZ Building Climate Zone Search App developed by the CEC.) In order for a home to receive a building permit, the builder will need to demonstrate that it will have a solar system of at least that size.

A map of California’s Building Climate Zones, relevant to PV system size under the state's solar mandate for new homesA map of California’s Building Climate Zones; the zone a new home will be built in will influence the size of solar PV system that must be installed under the state’s new mandate of solar on all new homes. To determine what zone your building is located in, the EZ Building Climate Zone Search App is a handy tool. (Image credit: CEC)

Aside from requiring compliance with the minimum system size, the policy allows some freedom for solar contractors and builders to meet the requirements in different ways. For one, developers could choose to install a community solar installation for a group of homes instead of putting rooftop solar on each building. However, they would need to be able to demonstrate that it would offer equivalent benefit to residents as if they had solar on their own home. 

Additionally, a variety of solar financing options are allowed. Systems could be owned by the homeowner (added into the cost of the home) or third-party owned. This means depending on what kinds of solar financing your solar company offers customers, you’ll have flexibility.

How do you determine the required PV system size?

The code includes two different paths for compliance, prescriptive and performance; either can be used to meet California’s solar mandate for new homes. The prescriptive approach utilizes a formula to specify the minimum PV system size (see the appendix at the end of this article for the formula and an explanation). This method is simpler but less flexible.

The performance method (aka “computer compliance method”) is a little more complex but allows for greater flexibility. The CEC has created a free software program (“CBEC-Res”) to allow contractors to model alternative PV sizes, based on different building characteristics like battery storage or demand response. 

Next Steps

Some details of the policy, including more specific guidance for compliance, are still being developed by the CEC. We’ll continue to share relevant updates as they are available. In the meantime, you can check out the resources below to learn more.

Finally, if you want to prepare your company to take advantage of the resulting business opportunities, check out Aurora’s recent webinar hosted by Solar Power World.

Watch the Webinar

Aurora Solar design and sales software enables solar design for homes not yet built because you can design based on roof plansAn example of a solar project site model created from building roof plans in Aurora–one of the ways Aurora makes it easy to adapt your solar design processes for this new solar market. Our webinar (linked above) demonstrates this process.


Additional Resources:


Appendix–Prescriptive Compliance Formula

The following formula establishes the minimum PV system size for a new building under the prescriptive approach in the 2019 Building Energy Efficiency Standards. For a full explanation, see section 7.2 of the 2019 (Draft) Residential Compliance Manual (a final version is still under development at the time of writing so this draft version is the latest guidance).

kW PV required = (CFA x A)/1000 +(NDwell x B)

Here’s what those variables mean:

  • kWPV = kWdc size of the PV system
  • CFA = Conditioned floor area
  • NDwell= Number of dwelling units
  • A = Adjustment factor from Table 7-1 (see below, center column)
  • B = Dwelling adjustment factor from Table 7-1 (see below, right column)

2019 Building Code Table 7-1 for Prescriptive Formula 

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Topics: solar policy, California

SEIA President & CEO Abby Hopper on Solar Policy Priorities and More

Posted by Gwen Brown on Jun 27, 2018 4:56:15 PM

From Washington, D.C. to state capitals around the country, if there’s a policy change that affects clean energy in the U.S., chances are the Solar Energy Industries Association (SEIA) is there advocating for the advancement of solar.

As the national trade association for the U.S. solar industry, SEIA represents organizations across all sectors from manufacturing to installation. SEIA works to champion the use of cost-competitive solar, grow solar jobs and diversity, remove market barriers, and educate the public about the benefits of solar energy.

Leading SEIA is President and CEO Abigail Ross Hopper, who joined the organization in January 2017. Prior to SEIA, Hopper had an impressive public service career focused on energy, including serving as the Director of the Bureau of Ocean Energy Management. She also held the roles of Director of the Maryland Energy Administration, Energy Advisor to Maryland Governor Martin O'Malley, and Deputy General Counsel of the Maryland Public Service Commission.

We had the pleasure of speaking with Abby Hopper to learn more about SEIA’s advocacy priorities, changes in solar markets around the country, opportunities for increasing diversity in the solar workforce and customer base, and more. We’re excited to share that conversation with you today.

SEIA President and CEO Abby HopperSEIA President and CEO Abigail Ross Hopper. Photo Credit: SEIA.

Prior to joining SEIA as President and CEO a little over a year and a half ago, you held several prominent positions in government. How have your previous positions prepared you for your role at SEIA?

One thing I’ve learned is that you can always learn the substance. I was not a solar expert when I got this job; I wasn't an oil and gas expert when I got my previous job. I always learned the substance. What matters, I think, is your ability to think strategically, to execute, and to form relationships and partnerships to make that all happen.

I’ve also I learned in my career that thinking about the "why" of what we're doing is so important. Making sure that you're approaching the “why” and the “how” thoughtfully and intentionally—and not just doing things “because”—that's important.

Another thing I've learned in my career is that relationships are the most important currency you can have. I could have all the knowledge in the world, but if I don't have the relationships to make things happen, it doesn't matter. Forming, building, and maintaining relationships is incredibly important.

What are a couple of SEIA’s top policy priorities at the federal and state level?

We have a couple of top priorities at both the federal and the state level. Strategically, those priorities center around defending markets that are already open to solar and ensuring market access. Those are big theories, but that's what drives our work.

At the federal level, we're really focused on making sure that—at whatever the venue, FERC, DOE, etc.—solar has an opportunity to compete. Any policies that might come out of this administration that tend to favor existing resources, coal and nuclear in particular, SEIA is going to be opposed to. We are keeping a really careful eye on that. More proactively, we are really lobbying hard for the Investment Tax Credit to be applied to stand-alone storage projects. We think that can be incredibly helpful to the storage industry, and also as it relates to solar.

At an intermediate level, if you will, we are thinking about Regional Transmission Operators (RTOs) and the kinds of market rules that are created there. We are engaged, and engaging more and more, to make sure that those rules and marketplaces are fair and open to solar energy.

At the state level, every year, we choose about twelve priority states. Those are places where we focus our time, money, and energy. There are a range of priorities at that level, but all are about market access—Renewable Portfolio Standards (RPSs), ensuring fair compensation for net metered customers, tax abatement, land policy, etc. The overriding theory is making sure that solar can compete.

Building upon that, given that there are so many different solar policy developments around the country, how do you pick the top priority states to focus on?

We are a membership organization, our members tell us what's important to them and that's where we focus. These priority states have historically been a combination of existing strong solar states (places like California or New York, markets we want to make sure stay open and healthy and grow) and emerging markets (Illinois, for example, New Jersey, which was a big market, then wasn’t, and now is again). Those are on the list because they are places where there is a lot of opportunity.

It’s a process we go through every year. Every fall, we get together with our members and ask “what matters to you?” And then we prioritize and focus on those areas. Similarly, I didn't come up with SEIA’s policy priorities; it's not “what Abby Hopper thinks,” it’s what our members tell us is most important to them.

Since you have such a high level view of what's going on around the country, what are some state markets that might not necessarily be in the news a lot, but where solar has made significant strides or where solar policies are being advanced that we might want to keep tabs on?

As we look at the country, the Midwest is a fast emerging market—Illinois, Michigan, Minnesota, Wisconsin, are all states that are, to one degree or another, grappling with solar and putting policies in place to help advance solar. (With the exception of Michigan, which just had a bad decision out of the Public Service Commission).

The Southeast is another emerging area. In the regulated markets down there, those Public Service Commissions have really been leading the way on requiring solar for their utilities. Once that initial step was taken, it’s obviously taken off. That's been exciting to watch.

I would say those are the two regions, with specific focus on the states that I mentioned and places like Georgia and South Carolina.

My next two questions touch upon one of the priorities that you highlighted when you took the helm of SEIA: ensuring inclusivity in solar both in terms of customers and the solar workforce.

First, what are some examples of successful strategies you've observed for making solar more accessible to groups that have traditionally had a difficult time accessing it (low income communities, renters, apartment residents, etc.)?

One is that, as we think about state policies or state programs to incentivize solar, there needs to be a low income element to it. For instance, if it's a grant program or some kind of rebate program, there should be funds dedicated to low income members of the community.

Community solar, I don’t have to tell you guys, is incredibly impactful and allows so many people to have access to solar who wouldn't otherwise be able to benefit from it. Community solar has really taken off in the past year and it shows in the 2017 market growth numbers. It's very accessible to people; it’s a business model that intuitively makes sense—people can understand that you're basically buying a share in a solar farm. So I think community solar will continue to grow.

Lastly, prices coming down has helped make solar even more accessible. I know that sounds obvious, but it’s making a big difference. At our board meeting recently, we had a speaker from Lawrence Berkeley National Labs, which recently published a report about the income levels of home solar adopters. In four states, the average income of solar adopters is on parity with average income in the state; it's right where it should be.

Although there are more women in the workforce than even a few years ago, we still see, according to The Solar Foundation’s Solar Jobs Census, that women represent less than a third of solar industry employees. What do you see as some of the key steps the industry can take to achieve greater representation of women in the solar workforce?

That’s a great question. It’s something I think about every day!

It's not as simple as just getting more women into the solar workforce, right? There are lots of things we can do to achieve that. But it's more than that, it's about recruiting women, retaining them, and promoting them. The job is not done on day one.

After that, it becomes about: How do we make sure that women are staying? How do we create work workplaces where they feel included, feel valued, feel heard? And, how do we create opportunities to promote them, so that those of us in leadership are not all by ourselves? There needs to be an intention to do it. It's not going to happen organically; I think you have to devote time, energy, and resources to making it happen.

Where and how are you recruiting new employees? What kind of education are you providing? Once they're in the door, it’s about understanding what your workforce needs—there may or may not be different needs and different opportunities. Are there examples of women in leadership? And if there aren’t examples of [female] leadership in your organization, where can women in your organization find other examples of leadership? Where can they get mentoring? It doesn't have to be just women mentoring other women, but there have to be opportunities for professional growth in a way that's meaningful.

Finally, you’ve gotta promote them! There are fully capable [women]. But if you don't look at your board, or your executive team, or your sales team, or your engineers with an eye towards diversity, you're not going to see it.

I look at all of those things—“How diverse is my my executive team? How diverse is my board?” We don't get all A+s; SEIA has work to do, but we are doing it. We're being thoughtful and intentional about it, and trying to create a kind of place where women come, stay, and get promoted.

And, I answered your question in terms of women, but these same things apply to people of color and other underrepresented groups of our community. And one of the things, in terms of getting people in the door, is expanding the network that you're trying to recruit from.

People share job notices with people they know, and people usually know people that are very similar to them. So this means we need to be thinking about things like: Are we going to historically black universities and colleges? Are we in partnership with NAACP and can use some of their networks? Are we coordinating with the Latino Chamber of Commerce, and can we use that network? We need to think more broadly than we sometimes normally do to make sure that we get [diverse] candidates in the door.

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Topics: Solar Spotlight, solar policy

How a Shift in Chinese Solar Policy Is Shaking Up the Industry

Posted by Gwen Brown on Jun 13, 2018 9:42:35 PM

It can be easy to see the solar industry through the lens of your local market. But we periodically get powerful reminders of the fact that global market forces have huge sway over our industry.

One of the biggest recent reminders was the U.S. government decision to impose tariffs on foreign-made solar panels in an effort to protect domestic manufacturers from an influx of cheap Chinese solar panels. Now, major policy changes in China are making waves in solar markets around the world—including here in the U.S., where they may counteract the impacts of the tariffs.

Today, we explain solar policy changes the Chinese government announced in June 2018, why they are significant to U.S. and global markets, and how they are expected to impact different industry sectors.

How Are China’s Solar Policies Changing?

On June 1, the Chinese government announced policies that effectively halt the development of new utility-scale and distributed solar projects around the country and scale back incentives for solar. These policy changes could reduce the solar capacity installed in China this year by as much as 40% (20 gigawatts) according to GTM Research.

Specifically, the National Development and Reform Commission, Ministry of Finance, and National Energy Administration jointly issued a statement outlining the following policy changes:

  • No new utility-scale solar plants will be approved in 2018. The previous target of 13.9 GW of utility-scale solar (compared to 34 GW installed last year) has been abolished.
  • Distributed solar projects are capped at 10GW for 2018 (compared to 19GW last year); analysts say this cap has already been reached for the year, so this is effectively a halt to distributed solar (e.g., rooftop) development as well.
  • Feed-in tariffs for solar generation are now reduced by 0.05 yuan per kilowatt hour (a 6.7 - 9% reduction depending on the region).

These changes are the most significant scale-backs of government support for solar in China to date. They are intended to reduce a deficit of $15.6 billion in the country’s state-run renewable energy fund.

What Do These Changes Mean?

China leads the world in solar installations, accounting for approximately 54% of global PV installations in 2017. GTM Research reports that this reduction in demand from China could lead to the first contraction in global PV demand since 2000.

Additionally, this sudden evaporation of China’s massive pipeline of projects is expected to lead to a significant oversupply of modules in the global market. Roth Capital estimates an oversupply of 34 GW!

This oversupply will theoretically lead to a significant drop in solar module costs. Bloomberg New Energy Finance (BNEF) has predicted that module costs will fall 34%. These cost reductions are comparable to what was seen in 2016, when the U.S. solar market experienced its greatest growth on record. BNEF estimates that module costs will fall to $0.24/watt by the end of the yearcompared to $0.37/watt at the end of 2017.

solar panel manufacturing

Installers and Developers See Relief, Manufacturers Feel the Burn

The expected reductions in module cost are welcome news for solar installers and project developers. The U.S. government’s decision in January to impose 30% tariffs on imported crystalline silicon solar panels has caused pain for these sectors, where higher costs changed the economics of projects and led to cancellations, particularly in the utility-scale sector.

Although the full impact of these unexpected Chinese policy changes is still uncertain, if module costs fall as much as anticipated then the price impacts of U.S. tariffs may be at least partially counteracted. In the short-term, BNEF predicts uncertainty and the suspension of some installations as developers wait to for updated prices. Longer-term, however the outlook for solar growth is optimistic.

In an Op-Ed for PV Magazine, Tony Clifford of Standard Solar predicts that “the solar industry in the United States could quickly return to its full strength,” observing that even under conservative estimates prices will be “much lower than where they are today and even where they were two years ago, during solar’s greatest growth year ever.”

On the flip side, these developments will put greater pressure on manufacturers as they exacerbate the competition against cheap imported modules that tariff proponents originally sought to alleviate. Stocks of many module manufacturers dropped noticeably after the announcement.

What About Global Impacts?

Although China’s decision to halt solar development this year reduces global solar demand, the resulting price reductions from an oversupply of panels may help spur solar growth around the world. India, which pledged to double renewable energy to 175 GW by 2022, is expected to benefit from these lower solar prices, as are countries in Southeast Asia.

Overall, by further driving down solar costs these changes are expected to help solar energy grow around the world and compete with fossil fuels. We’ll continue to follow these changes as they develop.

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Topics: solar policy

California’s New Smart Inverter Requirements: What “Rule 21” Means for Solar Design

Posted by Gwen Brown on Nov 8, 2017 9:30:00 AM

In the fall of 2017, California became the first U.S. state to require the use of advanced, or “smart,” inverters in solar projects (and other forms of distributed electricity generation). These changes, implemented through updates to “Rule 21,” require that inverters have certain capabilities to help ensure proper operation of the electric grid as more and more renewables are connected.

While these requirements are specific to California for now, the changes are representative of approaches other states are likely to consider in the future. So, if you’re a solar professional, it's a good idea to get familiar with these changes no matter where you’re based. In today’s post, we explain the new inverter requirements under Rule 21 and what they mean.

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Why Are These Changes Being Implemented?

The significant expansion of solar and other renewable energy sources is a huge opportunity—for tackling climate change, improving public health, delivering cost savings to consumers, and much more. However, it also presents new challenges for the management of the electric grid, which was originally built for one-way flows of power from power plants to the grid and then to consumers.

Customer-sited “distributed energy resources” (DERs)—like solar—introduce two-way power flow, as systems feed excess energy back to the grid. The variable nature of energy sources like wind and solar, which fluctuate depending on weather conditions, adds additional complications for grid managers.

California has led the nation in the deployment of solar and is likely to continue as the state works toward achieving its target of sourcing 100% of its electricity from renewable sources by 2045. As the proportion of renewables reaches unprecedented levels, there is a need for grid operators to have additional tools at their disposal to manage these resources and keep the grid running smoothly.

As the “brains” of solar projects, inverters can support grid management, but to date regulations have prevented the use of the full range of inverter capabilities.

Picture of the inside of an inverterSmart inverters, now mandated under California’s Rule 21, can help support management of the electric grid.

Beginning a few years ago, California utilities warned that advanced inverter capabilities would be needed to avoid potential grid disruptions. With more nuanced capabilities for determining when and how solar systems disconnect from and reconnect to the grid in the case of a power outage or other disturbance, smart inverters can help ensure that solar and other DER systems don’t make grid disturbances worse.

For instance, during and after a disruption on the grid, variations in voltage and frequency may occur. Historically, PV systems have been required to immediately disconnect when these conditions are detected; however, if a large amount of DER capacity disconnects at once this could further destabilize the grid. Similarly, the grid could be stressed if many solar installations reconnect to the grid at once after an outage, or increase their power output at too steep a rate. Smart inverter functions allow systems to remain connected to the grid under a wider range of voltage and frequency levels.

Requiring these changes now also has cost-saving benefits, because they may prevent the need for costly retrofits to the inverter fleet. These issues—both grid instability and the need for expensive inverter retrofits—occurred in Germany, where solar capacity expanded very rapidly over the span of ten years.

Beyond preventing grid disruptions, the use of advanced inverter functions has the potential to improve the stability of the grid. For example, dynamic volt/var operations (also called dynamic reactive power compensation) of smart inverters allow systems to help counteract voltage deviations on the grid. Furthermore, eventually, remote communication capabilities will be rolled out that allow grid operators to remotely adjust the operation of inverters to support the grid.

The Smart Electric Power Association and the Electric Power Research Institute note   that smart inverters may be one of the most cost-effective mechanisms for addressing many grid management challenges, and in some cases, “could help defer or avoid certain distribution, transmission, and electric supply upgrades.”

Craig Lewis, Executive Director of the Clean Coalition , a nonprofit that works to accelerate the transition to renewable energy and a modern grid, notes that “enabling the full suite of advanced inverter functionality is essential to bring high-levels of distributed generation online quickly and cost-effectively – in California and every other leading market around the world.”

On September 9, 2017, new requirements for inverters used in solar projects came into effect in California. These changes were implemented by the California Public Utilities Commission through significant updates to its Electric Tariff Rule 21 (or “Rule 21”), a set of existing interconnection requirements.

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What’s Changing Under Rule 21?

The revisions to Rule 21 are being implemented in three phases.

Phase One, which went into effect on September 9, 2017, requires that any solar project which applies for interconnection to the grid must use an advanced inverter capable of performing seven autonomous grid support functions. Inverters that are eligible for use under Rule 21 are those that have been tested and certified under the new UL testing protocol known as UL 1741 Supplement A (SA).

A complete list of eligible inverters can be found on the California Energy Commission (CEC) website . The list—which is updated monthly—contains over 3,200 eligible inverters.

One of the main changes under UL 1741-SA is that inverters are now allowed to operate under a wider range of voltage and frequency levels. As  Solar Power World explains , under the previous testing protocol, UL 1741, “the old interconnection requirements only allowed inverters to operate within a narrow range of... frequency and voltage requirements.” This meant that the use of many commercially available inverter functions, including those that offer grid support benefits, was prevented.

Graphic explaining Rule 21 Smart Inverter Requirements- Phase 1

Phase Two will establish communication requirements for inverters , setting standards for how inverters communicate with each other and utility systems. This will be important for enabling grid managers to eventually make remote adjustments to inverter operations to keep the grid running smoothly. Phase Two will also require that inverters have the capability to communicate over the internet. (However, internet connections for solar systems will not be required at this stage, because it has not yet been determined whether utilities or solar customers will be responsible for paying for internet connections.)

The exact date that Phase Two will go into effect is not yet determined, but it will be either March 1, 2018, or nine months after the release of an industry-recognized certification test standard for inverter communication protocols, whichever is later.

Graphic explaining Rule 21 Smart Inverter Requirements- Phase 2

Finally, Phase Three will require additional advanced inverter functions , “like data monitoring, remote connection and disconnection, and maximum power controls.” The specific requirements and timing of this phase have not yet been determined, although the Smart Inverter Working Group , which has been instrumental in establishing the details of Rule 21 revisions, has released recommendations (available here ).

Rule21-Phase3_graphic.jpg

How to Comply with Rule 21

To comply with the current phase of Rule 21, the main thing you need to know is that the inverter you select for your solar design must be one that has been certified under UL 1741-SA ; consult the CEC database  to be sure.

After choosing a certified inverter, some setup may be required to ensure that the inverter operates under the default parameters of Rule 21. As Solar Power World explains, the necessary settings can be determined during the interconnection process with the local utility and set up either remotely or through the inverter interface.

Coming Soon to a State Near You?

While California is the first state to take these steps, as a solar contractor it’s a good idea to be aware of these changes wherever you work, because other states are likely to be considering similar moves in the future.

Hawaii, Nevada, Arizona, Vermont, and Massachusetts are among states that may soon follow California’s lead. Quoted in Solar Power World, John Drummond, applications engineer at inverter company Chint Power Systems, says his company “expect[s] these kinds of advanced inverter functions to be required in the entire country in the next few years.”

As we work towards a future where clean, renewable energy is the norm, smart inverters will play an important role in managing the modern grid. We hope this article has given you a better understanding of how regulations are changing to manage rising levels of renewable energy and the details of Rule 21’s new inverter requirements for solar systems in California.

Editor's note: This article was updated in September 2019 to reflect California's passage of SB100 which sets a target of sourcing 100% of the state's electricity from clean energy by 2045.

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Topics: solar design, solar policy, inverter, smart inverter, California

How Virtual Net Metering Opens New Markets of Solar Customers

Posted by Gwen Brown on Nov 1, 2017 9:14:00 AM

Residential solar has grown dramatically over the last decade, making the benefits of lower electric bills and cleaner energy significantly more accessible. In fact, the annual growth in residential solar installations has averaged 68% over the last 10 years according to the Interstate Renewable Energy Council (IREC). In addition to the falling cost of solar components, this growth has to a large extent been driven by the development of policies and financing approaches that enable cost-effective projects.

To date, however, policies for residential solar, like net metering, have predominantly focused on supporting solar for homeowners, leaving renters and other potential solar customers limited options for accessing the benefits of solar energy. And for solar contractors, this means a large portion of the potential market has been closed.

Virtual net metering, which extends net metering to customers who do not share the same meter as a solar installation, has great potential to make cost-effective solar energy accessible to other portions of the residential market.

illustration of a multi-family apartment building with a solar array (virtual net metering enables shared solar)

Virtual net metering can allow residents of multifamily buildings to share the solar energy from a communal array.

What is Virtual Net Metering?

Virtual net metering (also called virtual net energy metering, or VNEM) uses the same compensation structure as net energy metering (NEM): utilities pay customers the retail rate for the energy that their solar system feeds back to the electric grid, so that they pay only for the net amount of energy they consume. However, unlike traditional net metering, virtual net metering allows the credits from an array to be distributed among multiple customers who do not share a meter with the system. For instance, energy credits from a solar array on a multifamily apartment building could be divvied up and applied to the accounts of different households in the building and to common area electricity usage. Virtual net metering policies are what enable shared renewable energy projects like community solar gardens, although some community solar projects are structured in other ways.

What is the Current Status of VNEM and How Big is the Potential Market?

In many states, and especially in cities, large proportions of the population live in apartment buildings, condos, or other buildings with multiple tenants. Since regular net metering policies require bill savings from a solar installation to be applied to a particular customer’s meter— rather than distributed across multiple accounts—it has been more difficult for these customers to access the benefits of solar. But with VNEM policies, this huge base of new solar customers is opening up.

How Does Virtual Net Metering Differ From Community SolarFor instance, nearly 17% of California residents live in apartments, but in major cities like San Francisco and Los Angeles that number is significantly higher (40 and 43% respectively) according to the Virtual Net Metering Policy Background and Tariff Summary Report  published in 2015 by the Center for Sustainable Energy, IREC, and CalSEIA. In Seattle, nearly 50% of the population are renters, and 40% of occupied housing is comprised of apartments (according to another IREC report ).

Around the country, there are already many states that have virtual net metering policies in place, though—for the most part—the number of projects developed under these policies has been limited. In California, for instance, one of the earliest adopters, virtual net metering was authorized for the general multi-tenant market in 2011 by the CPUC, following a pilot program for residents of affordable housing complexes. However, while there are several hundred thousand multifamily properties in the state that are eligible to develop shared solar projects under the state’s VNEM policies, as of 2016 only about a hundred such projects have been developed according to the Center for Sustainable Energy .

Virtual Net Metering Policies by State

Fourteen U.S. states have mandatory virtual net metering policies (typically applying to the state’s investor-owned utilities, or IOUs), according to IREC’s State Shared Renewables Program Catalog (updated September 2016). While this list focuses only on mandatory programs, “many utilities across the country, including IOUs, municipal utilities (MUNIs) and cooperative utilities (coops), also voluntarily offer shared solar or VNEM programs,” according to the Virtual Net Metering Policy Background and Tariff Summary Report.

The states (and districts) with mandatory virtual net metering policies include California, Colorado, Connecticut, Delaware, Hawaii, Maine, Maryland, Massachusetts, Minnesota, New Hampshire, New York, Oregon, Vermont, as well as Washington, D.C.

VNEM_mapchart.jpgAt the time of publication, 14 states have virtual net metering (VNEM) policies. 

The structure of virtual net metering policies (and the terms used to refer to these programs) varies by state, with diverse restrictions on customer type, technology type, capacity limits, and the allowable distance between the shared array and the meters of participating customers. California’s policy is somewhat unique in that it limits virtual net metering to “customers of multi-tenant buildings that share a common service delivery point (SDP)”1 meaning that only onsite projects are supported. In contrast, most other VNEM policies include solar systems located on properties that are offsite from participating customers.

How Can You Tap Into This Emerging Solar Market?

As you can see, VNEM policies in many states have made possible a whole new class of solar projects. But, while the policy mechanisms are in place, the limited use of these policies to date means that there is significant room for growth.

Curious about how to serve this market? While adding new services to your business is always something that should be weighed carefully, if your company is interested in understanding the business opportunities of virtual net metering processes here are some tips to get you started navigating this area.

First, you’ll need to understand whether there are state-level VNEM policies the areas where you work. (If not, it may be worth also contacting your local utility to understand whether the utility offers a voluntary VNEM program.)

If your state offers VNEM, the Virtual Net Metering Policy Background and Tariff Summary Report  is a good starting point, providing summaries of how each state implements VNEM (pages 31-48) and links to the relevant policies and rules. Another helpful resource is IREC’s State Shared Renewables Program Catalog , which provides a comparative chart of states’ shared renewables programs, like VNEM, for solar and other renewable energy technologies.

If you’re a solar contractor in California, you’re in luck, because the Center for Sustainable Energy, with support from the SunShot Solar Market Pathways Program, has put together some VNEM toolkits for contractors. These include interactive maps of multifamily buildings to enable more targeted marketing efforts, and guidelines and forms for navigating the interconnection process. Additionally, they’ve put together guides for owners of apartments and condominiums, which may be helpful references to share with prospective customers to help educate them on the value of virtual net metering systems and how the process works.

As we work towards a future in which renewable clean energy is accessible to all, the development and implementation of approaches to bring solar to new markets will be key. Virtual net metering presents a great opportunity to include many more people in the solar market—from renters, to residents who live in multifamily buildings, to those whose property is too shaded. For contractors who get familiar VNEM projects, a vast market of new customers awaits.

Topics: solar policy

Community Solar Is Essential to Expanding the Solar Market—Here's How It Works

Posted by Gwen Brown on Sep 13, 2017 12:00:00 AM

Solar energy has grown dramatically in the last few years, but for nearly half of all households and businesses in the U.S., installing solar is not an option.

With such a huge portion of the market unable to access solar through on-site installations, it’s clear that other options will be important if the benefits of solar energy are to become broadly accessible. Community solar—also referred to as solar gardens or shared solar—addresses this challenge by providing a way for multiple customers to share the solar energy produced by a solar array.

Community solar has emerged as one of the fastest-growing sectors in the solar industry, with capacity nearly quadrupling in 2016 . Although currently only 26 states have community solar projects, by 2020, the National Renewable Energy Laboratory (NREL) estimates that community solar could make up 32% - 49% of the total distributed solar market in the U.S.

Whether you want to access clean energy for your home or business but can’t (or prefer not to) install a system on your roof, are a solar professional looking to understand emerging markets, or just want to expand access to clean energy in your area, getting familiar with community solar can can open new opportunities.

In today’s article, we explore the variety of ways that community solar projects can be structured, how these different models work, and some of the complexities that project developers and participants need to consider.

What is Community Solar?

depiction of community solar

NREL defines community solar as a solar-electric system that provides power and/or financial benefit to multiple community members. While there are a number of different models for community solar, this definition highlights its core characteristic: that it provides a way for a solar project to supply energy to multiple homes and businesses, and reduce their utility bills, without being located on their premises.

How Does Community Solar Work?

Community solar projects come in a variety of forms and because the sector is still emerging new approaches may arise. However, a few dominant models for community solar have been developed to date.

How Members Participate: Subscription vs. Ownership Models

From the perspective of participant experience, it is helpful to think of community solar arrangements in two broad categories: subscription and ownership models. In an ownership model, customers buy specific panels or a share in the array to meet their desired level of energy. In a subscription model, the project is owned by a third-party, like the local utility or a company, and community members subscribe to a portion of the energy it produces.

Ownership-based community solar projects, as you might expect, require upfront payment by participants for their portion of the project, much as if a household or business was paying cash for a solar installation on their own property. Participants then receive credit for the actual amount of energy their portion of the project produced, either as a direct credit on their utility bill or through some other arrangement.

A subscription model, on the other hand, usually requires no upfront fees to join and offers immediate savings because members subscribe to purchase solar energy at a lower rate than what they would typically pay their local utility. Because there are no upfront costs, this model provides a means for low-income community members to access the benefits of solar.

Who Administers Community Solar Projects?

In addition to variations in how customers participate (buying in versus subscribing), there are also a variety of different models of community solar depending on what type of organization owns and/or administers the project. NREL identifies three ownership models for community solar: utility-sponsored, special-purpose entity (SPE), and nonprofit.

In a utility-sponsored model, the community solar project is owned or operated by a utility company, who opens it up to voluntary participation by their customers. Depending on the project, participants may pay upfront or make subscription payments. In return, participants receive credits on their utility bills proportional to their contribution and the amount of energy the system produced. Under this approach, participants typically buy rights to the benefits of a share of the energy produced (a subscription model), but do not have an ownership stake in the project itself.

Another common structure for community solar projects is to have a non-profit administer the project on behalf of donors or members. There are multiple ways that a nonprofit could approach this. They could develop and administer the project in a way that shares the benefits with participant members. (In a variation of this approach, the nonprofit could partner with a for-profit third party that could own the system and take advantage of tax incentives.) Finally, a nonprofit could also solicit donations to support the development of the project. This approach is not strictly “community solar” as the donors would not directly benefit from the energy produced, but might contribute for environmental or philanthropic reasons.

Finally, in a special-purpose entity (SPE) model, a community solar project is developed by a group of individuals who join together in a business enterprise. One reason for developing a shared solar project in this way is that registering as a business enterprise may make it possible to take advantage of tax incentives, like the Investment Tax Credit, that would otherwise be unavailable to tax-exempt nonprofits (and some for-profit utilities). However, in choosing this approach, those developing the project must take on the legal and financial complexities of forming a business and complying with related regulations (as discussed below).

Complexities of Community Solar

The development of community solar projects can be financially and legally complex because of federal and state securities laws that govern investments. Transactions involving financial investment in an enterprise with the expectation of earning profit through the efforts of someone other than the investor are considered securities and are subject to specific regulations. The process of ensuring compliance with securities regulations can add significantly to the time and cost involved in project development and failure to properly comply may subject participants to liability.

For these reasons, community solar project developers typically work to ensure that the project does not meet the legal definition of a traditional, taxable investment that would be governed by securities law. This results in a variety of rules about who can participate in community solar projects and how. For instance, it is common for projects to limit participation to those within a certain geographic area, and restrict the amount of energy participants can obtain from the project to their annual energy consumption.

While project developers should seek professional legal and tax advice as they develop the structure of their project, NREL’s A Guide to Community Shared Solar provides a great starting point for understanding some of the legal implications of different models.

Looking to the Future: Why Community Solar Matters

Because community solar can reach the half of the population that is unable to go solar via rooftop systems, it is one of the biggest growth opportunities for the solar industry. In the last few years, this option has grown from being almost non-existent to serving thousands of customers across the nation.

map of community solar projects around the country, courtesy of Community Solar Hub A map of community solar projects around the country, courtesy of Community Solar Hub , a clearinghouse of information on community solar.

In 2018, community solar is projected to comprise almost a third of the non-residential solar market. By 2020, NREL estimates that with supportive policies, community solar could represent over $16 billion of cumulative investment and comprise as much as 49% of the distributed PV market. Similarly, the Rocky Mountain Institute (RMI) has estimated that community-scale solar could reach 30 GW by 2020! (Our interview with RMI’s Dr. Joseph Goodman explores how software like Aurora’s can support this growth.)

Not only is community solar a huge opportunity to supply more of our electricity with sustainable, domestic energy, it also has important equity implications. By providing affordable solar energy with low or no upfront costs and no credit rating or property ownership requirements, community solar opens up clean energy to groups that have traditionally had limited access. We look forward to keeping an eye on this market—and keeping you posted—as it develops!


Interested in bringing community solar to your local area?

Some great places to start include:

Topics: trends, solar policy, community solar

NEM 2.0 Arrives in SCE Territory - Here’s What You Need To Know

Posted by Andrew Gong on Jul 6, 2017 12:00:00 AM

As you’ve likely heard, California is unveiling a new approach to net energy metering commonly referred to as NEM 2.0. This new net metering policy began in SDG&E territory on June 29, 2016 and in PG&E territory on December 15, 2016.

On July 1, 2017, NEM 2.0 became required for all new solar customers in SCE territory as well. This means that, as of this month, NEM 2.0 applies to solar customers of all the major California investor-owned utilities.

There are 4 major changes that NEM 2.0 introduces (as highlighted in our blog post on the topic):

  • NEM 2.0 customers accrue “non-bypassable charges” (NBCs) over the year that can’t be offset
  • NEM 2.0 customers are compensated slightly less for produced electricity
  • NEM 2.0 customers must enroll in a time of use (TOU) rate if available
  • NEM 2.0 customers pay a small interconnection fee

As a solar installer in California, what do you need to know to explain NEM 2.0 to prospective customers?

We’ve put together a handy guide with the key points:

[Note: Aurora customers who want to understand how to model NEM 2.0 for project financings should consult this Aurora Help Center article.]

What’s the purpose of NEM 2.0?

The original NEM 1.0 policy placed a cap on the total amount of distributed renewables that could be installed. This limit was set at 5% of the generation capacity in each of the major utility regions. As each of the 3 major California utilities approached this limit, the California Public Utilities Commission developed a new NEM policy.

What’s changing?

Most of the core elements of NEM 1.0, including market rate compensation for surplus electricity produced, remain intact under NEM 2.0. However, solar customers now contribute to certain public programs, like the decommissioning of retired nuclear power plants, through NBCs—a portion of their bill that cannot be offset.

Under NEM 1.0, solar customers often had little to no electricity bill at the end of the year. As a result, revenue to these programs dwindled since part of the electric rate pays for these programs. The introduction of NBCs serves to address this issue.

Why are TOU rates now mandatory?

TOU rates, which charge higher prices for electricity during periods of higher demand, encourage customers to adjust their consumption to reduce strain on the electric grid. In places like California, where a high proportion of electricity comes from renewable sources whose production varies throughout the day, this is particularly important.

The latest TOU rates, which are tailored to the patterns of energy consumption and production in California, incentivise solar energy production during later hours and a reduction in energy usage from 3pm-8pm. For more information, see pages 91-92 of CPUC Decision 16-01-044.

Topics: Solar Utility Bill, solar policy

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