Author: Adam Capage

Adam Capage is the vice president of corporate and government affairs at 3Degrees. Adam has 16 years experience in the energy industry.

4 Key Takeaways from a Week of Energy Conferences

April 29, 2019 Adam Capage

Recently, I embarked on a week-long tour of energy conferences, including the ACORE Renewable Energy Policy Forum in Washington DC, the Climate Leadership Conference in Baltimore, and Bloomberg’s New Energy Finance Summit (BNEF) in New York City. While the conferences each had a different focus within the renewable energy and climate space, I noticed key themes in the various sessions and conversations that I had with attendees.

The age of energy abundance

“We’re entering an age of energy abundance.” While this statement is from a speaker at the Bloomberg event, supporting evidence was discussed at all three conferences. Many speakers noted that current and projected natural gas prices remain low and that wholesale electricity generation costs are falling as renewable energy generation with zero marginal cost comes online. Meanwhile, advances in energy efficient technology are driving down total energy use per capita. The combination of new, low-cost renewable electricity supply and energy efficiency seems likely to yield energy abundance for developed countries. Coming 50 years after many predicted we’d literally run out of energy, this is a remarkable turn of events. This new reality also necessitates a shift in mindset for policymakers, the energy industry, and consumers alike: instead of fearing a scarcity in our energy supply, it’s critical that we now focus on limiting energy’s environmental impact.

Instead of fearing a scarcity in our energy supply, it’s critical that we now focus on limiting energy’s environmental impact.

The challenge of intermittent generation

The next wave of policy innovation and technological progress supporting renewable energy generation will center around reliable, cost-effective integration of intermittent generation. Large scale wind and solar projects regularly win energy request for proposals (RFPs) with highly competitive prices, so it’s not unreasonable to think that tax credits and grants will be allowed to fade away. But now the next chapter begins: we need new rules guiding how intermittent supply is valued, larger wholesale energy markets, more energy storage deployment, and clear market signals to shift demand. More progressive policies in these areas are actively being discussed and implementation will enable continued rapid deployment of renewable energy generation.

All eyes on transportation

In 1990, the electricity sector was the single largest emitter of carbon dioxide emissions (CO2), responsible for roughly 25% more emissions than the transportation sector (the second largest emitter). Over time, the emissions profiles of the two sectors slowly converged, and in 2017 the transportation sector took the lead as the largest source of emissions . This statistic was clearly weighing prominently on conference attendees’ minds. Although none of the conferences I attended were explicitly about transportation or electric vehicles, all three included multiple sessions and much hallway conversation about the transportation sector, the environmental challenges it presents, and how it’s likely to evolve in the decades ahead.

Similar to the adoption of solar photovoltaic technology a decade ago, the EV story today is one of high growth rates on a very small existing base. Applying the solar adoption model to EVs today, conventional wisdom predicts that in another decade, we will see an exponential increase in the number of EVs on the roads globally. In fact, BNEF’s most recent Electric Vehicle Outlook predicts this number will hit 30 million by 2030. Activities and policies that will support this outcome, including an expanded public charging network, more EV options for consumers, less expensive batteries, and continued subsidies at the state and federal level are all currently or soon-to-be underway.

…in another decade, we will see an exponential increase in the number of EVs on the roads globally.

RECs remain a critical ingredient

All three conferences provided ample evidence of the critical role that renewable energy certificates (RECs) play in tracking the generation and use of renewable energy. RECs are indisputably the currency of renewable energy transactions, whether meeting renewable portfolio standards (RPS) or tracking voluntary renewable energy purchases. However, it’s challenging to maintain the accounting integrity of RECs in an age of distributed solar and cap-and-trade systems that overlap state RPS guidelines set up to protect the voluntary market. Going forward, I anticipate that electrification of the transportation system will bring even more tracking and attribution challenges. It seems clear that all market participants benefit when everyone is clear what a REC represents, when everyone can trust that a REC hasn’t been double-claimed, and when market rules are aligned. One concrete action in support of these outcomes might be for every tracking system to adopt a policy of all-generation tracking; the New England Power Pool (NEPOOL), PJM General Attribute Tracking System (GATS), and New York GATS have all been built this way and it helps with tracking across state boundaries.

The meta theme of continuous change undergirds everything in the energy industry and the tricky part — as always — is to know which topics will still be relevant two, five, and ten years from now. As I reflect on these recent industry conferences, I believe that these four themes — recalibrating to an age of energy abundance, addressing intermittent generation, decreasing transportation emissions, and supporting effective systems for tracking renewable energy generation and use — will stand the test of time.

Should utilities report to CDP?

March 1, 2018 Adam Capage

Last month 3Degrees hosted a webinar with CDP on the value of CDP reporting for utilities. I moderated the event and was joined by Simon Fischweicher, manager of disclosure services at CDP and Lauren Wilson, environmental policy manager at Xcel Energy.

Here are some key aways from the webinar:

There are clear benefits of reporting to CDP: Xcel has been reporting to CDP for more than 10 years and despite some challenges (more on that below), Xcel views the process as beneficial to their organization. Lauren explained that the reporting process has created greater transparency around their environmental initiatives and this in turn has encouraged Xcel Energy to tell their clean energy and carbon reduction story to a broader audience.
The resources required to report are not trivial: Xcel Energy has a team of eight people that meet regularly for several months to prepare their answers to the annual CDP questionnaire. They are not working on this full time, but it does take significant effort. Lauren suggested setting up a time tracking system to fully understand the time requirements. And because CDP is just one of a number of groups looking for sustainability reporting, it is important for organizations to prioritize where they invest their time. As utilities look to set science based targets (SBTs), this adds an additional layer of reporting requirements that should be fully understood as companies move forward with these initiatives.
CDP is working to make it easier for utilities to report: Responding to CDP for the first time can feel risky to many organizations. To address this, CDP allows first time responders a chance to submit a private response.This allows both the responder and CDP an opportunity to discuss the information and how it’s reviewed and assessed. This year, new responders can also opt for a private score.This will allow CDP to gather a broader range of information from utilities that fear their score won’t be as high as they would like. CDP has also introduced a streamlined version of their questionnaire for new responders and is even experimenting with a shorter version of their full questionnaire.

Toward the end of our discussion, Lauren also shared some examples of how utilities can keep their leadership focused on emission reductions:

Provide long term incentives to executives that are directly linked to emission reduction trends.
Assign an internal price to GHG emissions so that future electricity generation decisions include internalizing the cost of carbon emissions.
Explicitly list climate oversight as one of the responsibilities of the utility’s board of directors.

To learn more, listen to the full webinar.

To learn more about the services we offer for utilities, take a look at the following pages:

Community Solar and Barbecue: The Devil Is in the Details

September 13, 2016 Adam Capage

3Degrees compares community solar to barbecue: The Devil Is in the Details

Last year, we published a three-part series about community solar as offered by regulated utilities. These articles focused on key program design decisions; many of those discussions are just as relevant now as they were last year. But today I’d like to take the conversation up a level and talk about all the different varieties of community solar.

Reports about community solar usually begin with a definition such as this one provided by NREL: “a solar-electric system that provides power and/or financial benefit to multiple community members.” Agreed. But that definition leaves considerable room for various forms of community solar, and I think we’re still collectively struggling to find common language to describe these different types of community solar. Calling all variations of community solar by one generic term is sort of like calling all varieties of barbecue just of “barbecue” with no way to differentiate between North Carolina, Kansas City or Texas barbecue. Although they all have some common elements, there are fundamental differences as well — from ingredients to cooking style to condiments. So too with community solar. In this article, we offer a framework for thinking about the varieties of community solar programs across the country.

The most significant dichotomy in community solar programs is between those offered in regulated versus competitive retail markets. Let’s discuss each of these electricity markets and the varieties of community solar that are offered in each.

Community Solar offerings in regulated markets

In fully regulated utility service territories, there is a single (almost always) vertically integrated utility, serving all customers. Regardless of whether the utility is investor-owned, a municipal or a cooperative, there are a few different types of community solar operating.

Utility-led: In these cases the utility has decided to offer community solar to customers on its own, and in most of these cases, the utility has made a policy decision (or been directed by their commission) to ensure that program participants cover the full cost of offering the program. In practice, this often means that the community solar is offered at a price premium, and that energy price is fixed for the time the customer stays in the program. Customers can usually make renewable energy claims (because they keep the REC). Examples include Rocky Mountain Power and Consumers Energy.

Third-party-led: In this model, some sort of legislative or regulatory intervention creates a market for private companies to offer community solar within a utility’s service territory. In these instances, the utility typically pays either a full retail rate or something close to it for the energy from the system, and the third party is then able to offer solar power to customers at a savings to traditional utility rates. In return, the utility is able to use the RECs to meet RPS requirements. Colorado is a poster child for this structure, and it’s where community solar first gained real traction in the market.

All of the above: Until last month, California was an outlier with legislation that mandated that the regulated utilities offer community solar and created the framework for third-party community solar providers to acquire and service customers in the utilities’ service territories. In April of this year, Oregon joined California, passing legislation directing the Public Utility Commission to finalize rules that will allow the regulated utilities to offer community solar programs while also allowing third parties to provide community solar to customers of the regulated utility. As one would expect, the relative success of these programs in both states will be defined by how the final rules are structured — the higher the rate for energy provided to the solar facility, the more successful the program will likely be.

Community solar in competitive markets

For those of you who spend all your time in the western or southern U.S., it’s easy to forget that retail competition (with varying levels of actual competition) is alive and well in many states in the Northeast, a few states in the Midwest, and in Texas. In these competitive markets, there is a distribution utility that sends out monthly bills and acts as a default provider, but customers can buy energy from a number of retail providers. Community solar is an interesting new option in this world. But, it is important to note, currently it only works when there is an incentive for the solar that makes it price-competitive. With rapidly falling solar prices, this will surely change in coming years, but for now, the vast majority of capacity installed for community solar products in competitive states receive energy payments well above rates paid to other energy resources.

There are two common ways to provide an incentive for community solar developers. One is to allow developers to pass through net metering credits to end-use customers. These credits are often valued at the full retail rate for every kilowatt-hour of energy generated. A second option is to agree on the value of solar provided to the grid by the system and then compensate community solar developers at this rate. The value of solar is a rate negotiated with state regulators; not surprisingly, the higher it is, the more appealing community solar is to potential buyers. In both cases, the developer is most likely selling the REC to someone else so the customer is not receiving the renewable energy attributes of the electricity produced. These products are predicated on providing a financial benefit to customers, rather than solar energy.

Community solar has many variations. Some programs are granted sizable incentives, some are not. Some are small, some are relatively large. Some transfer the renewable energy attributes to the customer, some do not. Depending on the details of each program, customer interest and acquisition costs can vary widely. And just like good barbecue, the details (or ingredients) matter — especially when we review case studies and best practices and seek to apply lessons learned from one program to another. As the market matures, we should get more specific with our language so that when we are comparing programs, we’re talking about the same type of community solar.

Originally published on GreenTechMedia

Negative Prices Require Positive Changes in Community Solar

February 19, 2016 Adam Capage

Adam Capage looks at the negative REC prices in Colorado’s community solar program, explains how we got here, and suggests a fix.

Last fall, it was disclosed that renewable energy certificate (REC) prices in the Colorado Solar Gardens program have turned negative — that is, developers have submitted bids that require them to pay the utility to take the RECs generated by their projects.

How could this be? Does it mean RECs fundamentally have no value? Or maybe that participating retail customers don’t value solar energy from community solar projects? No and no. Negative REC prices in the Solar Gardens program are a direct result of a complicated web of regulatory guidance and program design in Colorado that distorts REC pricing.

The issue

The Colorado Solar Gardens program meets many pro-solar policy goals simultaneously: it promotes small utility-scale projects, engages individual households and businesses that want to support solar but can’t install a system on their roof, and provides a market for third-party developers — and it does all this while also helping investor-owned utilities meet the distributed generation carve-out portion of Colorado’s renewable portfolio standard (RPS).

Courtesy of Greentech Media

When the program was originally set up in 2010, the market for solar was very different than it is today. In order to encourage rapid development of community-based projects, the program guaranteed compensation for the power at the full retail rate in Colorado. At the same time, Colorado’s RPS required utilities to purchase large amounts of renewable energy (in the form of RECs) from distributed solar. To address both of these issues, the program was designed so that the RECs from the participating community solar projects would be sold to utilities, providing an important revenue stream for the developers, and helping the utilities meet their RPS goal with RECs generated in-state. This structure, combined with above-average solar resources, meant that even small utility-scale projects of just a couple of megawatts had a decent chance of being economically viable. So a key benefit of this approach was that it quickly helped create a vibrant market for solar development in Colorado.

Unfortunately, this structure also had some disadvantages, not all of which were apparent at inception. One key problem: RECs embody the environmental attributes and claiming rights of renewable energy. By selling the REC to the utility instead of the participating retail customer, retail customers were not (and still aren’t) buying solar power or lowering their carbon footprint. If the RECs are going to the utility for its RPS requirements, then the RECs can’t help customers use renewable energy or lower their carbon footprint.

This is a difficult concept for even sophisticated commercial customers to understand, and it is unlikely that many (any?) residential retail customers get it. So, while the policy secured a secondary revenue stream from REC sales that allowed developers to offer the program to customers at a lower price point, there is a less-than-ideal lack of transparency and choice for customers that want to receive renewable energy.

Fast-forward five years. Community solar is booming in Colorado, and by the end of 2016, as much as 40 megawatts of capacity may be operating. These projects are creating a lot of RECs, and the utilities don’t need them all. Add to this another key development: the cost of solar has dropped significantly and continues to decline.

Now we have a situation where the utilities no longer need the RECs and developers are willing to propose projects without REC revenue. However, the policy still requires that the RECs from these projects be sold to the utility. As a result, developers bidding on new projects have started to assign zero or even negative value to the RECs in order to have the most financially attractive bid. The policy that was intended to encourage the solar market is now distorting it, and as a result, we see negative REC prices in Colorado.

So where do we go from here?

This dilemma can easily be fixed by changing program design such that retail customers can actually purchase solar energy when they sign up for Solar Gardens. This would entail the customer — not the utility — paying for the REC and then having it retired on their behalf. Many benefits would accrue from this policy change, including:

Residential and small commercial customers could pay for and receive the solar power they almost certainly already believe they’re buying.
Small commercial customers would be able to buy the renewable energy from the project and make renewable energy claims based on program participation. Added bonus: commercial customers could use the RECs to earn points for LEED certification or participate in the EPA Green Power Partnership.
Customers could use their participation in the program to lower their carbon footprint.

Perhaps the biggest benefit for the renewables industry at large is that this change would increase transparency and choice — always a good thing — and prevent solar markets from being roiled by nonsensical negative REC pricing.

Originally published on GreenTechMedia

Strategies for Fairly Pricing Community Solar Programs

May 19, 2015 Adam Capage

Adam Capage of 3Degrees explores the complex topic of pricing power from community solar programs in an equitable manner.

When a utility offers a community solar (or shared renewable) option to its customers, there are a range of program design questions to address. In previous articles, we’ve talked about project ownership and siting considerations and options for mitigating risks. This article addresses the options for defining the final price to customers of solar energy from a community solar program.

In some states, there is a legislative or regulatory mandate that provides the answer. For example, in 2013 Minnesota passed a law mandating a solar standard for Xcel Energy, as well as a requirement to create a Solar Gardens program to help meet the standard; as a result, Xcel Energy has since defined specific bill credits for solar energy and RECs delivered to the utility.

But for utilities that have voluntarily decided to launch a community solar program, defining the final cost of the solar can be a contentious process. This isn’t surprising when you consider how these utilities are operated and regulated. The cost of utilities’ portfolio of generation is spread across the entire rate base, so all costs and benefits are packaged and priced together. Aside from tiered pricing or time-of-use pricing models, every residential customer pays the same amount for the same bundle of energy, no matter when they use it.

Now along comes community solar, which is premised on the idea that customers will be purchasing solar energy from a specific facility, possibly at a fixed price. This is an entirely different value proposition for the customer. And it raises a number of complex questions for utilities and their regulators: Should customers be able to direct their dollars to a specific resource and then accrue specific benefits, such as a fixed price? How should the public benefits and costs of solar power be addressed? Should these values be calculated and credited to the individual who enrolls, or should ratepayers that haven’t enrolled still share some of the collective costs and benefits?

These are difficult policy questions, and there is no single correct answer. For some utilities, the goal will be to precisely value solar energy; in other instances, stakeholders will want to make the program comparable to rooftop solar; still others will focus on holding non-participating customers harmless by ensuring every possible cost of the solar resource is borne by participants, as with green pricing programs today. Different goals and the resulting terms of each negotiated agreement will determine the net price of each utility’s community solar program.

So let’s think about some of the key options that are being debated. For the sake of discussion, consider this hypothetical program structure. Customers purchase a portion of their total energy, in 250-kilowatt-hour blocks, from a solar resource. Their purchase is reflected on their bill in the form of two new line items, one representing a charge for the solar energy and one that provides a credit for system resources not being used because of the solar purchase.

On the line charging for the solar energy, the cost of the solar energy is the largest component. Program administration and customer education costs are also captured here. For the sake of this example, we’ll leave the more complicated questions to the credit line.

For the line that provides a credit for energy not purchased, the key consideration is how to value that credit. We see utilities considering several options, including:

Full retail rate: This is how rooftop solar is compensated under net metering rules. For utilities that want to make their community solar program approximate the experience of rooftop solar, this is the best option. The financial result will be a net benefit to customers who enroll, which will make the program very appealing. However, this approach doesn’t calculate the actual value of solar in the utility system, which may be higher or lower than the full retail rate. As such, this may raise concerns and discussion about cost-shifting to non-participating customers.
Disaggregated retail rate: Utilities that break out the component charges of their final retail rates may choose to credit customers only for the energy portion of the rate, along with pro-rated fuel adjustments and any other charges that shouldn’t reasonably be borne by customers buying solar energy. Under this option, participating customers may still pay transmission and distribution charges.
FIT rate: This is only relevant in locations that have defined a feed-in tariff rate; in these instances, above-market energy costs for the solar are being spread across the rest of the customer base.
Value of solar: This concept has spurred much debate and many studies, including this one. If stakeholders have agreed on a value of solar, that number can be credited to participating customers.
Avoided cost: By crediting customers with the marginal cost of the next kilowatt-hour, the utility avoids any possibility of subsidy to program participants. However, this presumes there isn’t any other value to the solar energy that the utility can or should recognize and credit to the participating customers.

This topic — how to price, credit and value solar — is at the center of a contentious discussion that we see playing out within utilities and at public utility commissions across the country. Final decisions on how to price community solar will vary, but the future is clear: voluntary, utility-led community solar programs will grow to include hundreds of thousands of customers in the next three to five years.

Originally published on GreenTechMedia

Designing Community Solar Programs to Manage Risk

April 16, 2015 Adam Capage

In the second of three articles, Adam Capage of 3Degrees looks at how utilities can address the larger risks of a community solar program.

With interest in community solar continuing to grow, more utilities are grappling with how to design a successful program that meets their organizational goals.

In part one of this series on best practices in community solar, we reported on project ownership and siting options. This article focuses on risk mitigation — a critical subject for every utility, but especially for investor-owned utilities (IOUs) that operate within regulatory mandates to hold non-participating customers harmless. When designing a community solar program, there are multiple risks utilities must assess. Here, we’ve focused on two that are particularly important and relevant.

Risk No. 1: Oversupply

Every utility designing a community solar program worries, “What if our solar supply doesn’t sell out?” Even if the unsold portion is small, the downside regulatory risks are high. Selling any over-supply to third-parties is an option, but this can bring complications and administrative expenses out of proportion to the solar volumes involved. Fortunately, there are other options to mitigating this risk.

Use excess supply to meet other requirements: In California, utilities operating mandated shared renewable programs will be able to shift any unsold supply to meet their renewable portfolio standard requirements. This reduces risk and increases efficiency; we recommend every utility operating in a state with an RPS seek similar flexibility.

Similarly, utilities that currently offer voluntary REC (renewable energy credit)-based green power programs have the same built-in flexibility. When shifting supply to a REC-based green power program, the utility could pay avoided cost for excess energy produced and value the RECs at the difference between the avoided cost and the all-in price of the solar energy. If participation in the REC-based green power program is adequate, these relatively higher-priced RECs can likely be integrated into the green power program supply without increasing the cost of the program to participants because volumes will be low.

Actively manage program demand: Small community solar programs sell out easily, but for those that want to pursue a larger program with thousands of customers, and for those offering programs where the financial benefits of participating take longer to realize, it’s important to create a marketing plan designed to meet specific participation goals. For example, in some cases it will be necessary to flexibly ramp marketing up or down depending on program performance; in other cases it will be necessary to use marketing to help you build and maintain a wait list that can address turnover as customers move out of the service territory.

Carefully define terms and conditions: Some utilities are also looking at program rules such as requiring signup fees (even when the solar will be paid for in monthly installments) and/or cancellation fees, or setting minimum time requirements for program participation. There is not enough market data to know for sure how these rules may impact customer behavior.

Ultimately, however, we caution that fees and mandatory commitment periods represent barriers to customers’ decision to participate. Not only is this counter to the spirit of a program to engage customers with solar, but it’s likely to lead to higher sales costs and a longer sales cycles. The benefit these strategies ostensibly offer — reduced risk of unsold program supply — can be more easily attained using the other strategies discussed above.

Risk No. 2: REC treatment

Depending on how the utilities plan to use the RECs associated with the community solar project, another potential risk is running afoul of the Federal Trade Commission (FTC) Act. If the utility program conveys the REC to the customer or retires it on their behalf, there is no issue: the utility can say the customer is purchasing and consuming solar energy.

Things get more complicated when the utility decides to use the REC for other purposes. In these instances, it’s important that customers not be led to believe they are buying or consuming solar energy, because without the REC, which represents the environmental benefits of solar energy, they categorically are not. Here’s the key point to remember: it doesn’t matter whether the customer understands what a REC is (most don’t) or whether ownership of the REC is retained by the utility in contractual fine print. What is relevant is what a reasonable consumer believes he or she is getting based on all the program marketing.

The question is whether a reasonable customer believes he or she is buying solar power. No utility wants to risk misleading consumers, being accused of misleading customers, or being the subject of a complaint filed with the FTC.

Our recommendation is that utilities retire the RECs on the participant’s behalf — it lowers risk, delivers value to participants and makes marketing easier. That said, if the utility needs to use the REC for other purposes, it’s still possible to say the customer is investing in, or helping to build, emissions-free solar generation. This is likely to be appealing to many customers, especially if they are able to receive fixed-price energy through the program. In these instances, the utility should also inform the customer that he or she is not using solar energy, but that someone else is buying it. This 2-page report from the Center for Resource Solutions explains best practices.

Although the risks associated with community solar may initially seem daunting to utilities, the approaches to dealing with them can be relatively straightforward.

In the next installment, we’ll talk about the range of value propositions that utility-led community solar programs can offer to participants.

***

Originally published in GreenTechMedia April 16, 2015

Community Solar: Key Considerations in Designing a Successful Program

March 30, 2015 Adam Capage

The first community solar programs were started nearly a decade ago, and, as the name suggests, the early efforts were led by communities — neighbors, small towns, places of worship — in each case, a group of people dedicated to building solar systems and sharing the benefits of the electrical output.

From these humble beginnings, community solar programs have grown and evolved to include many different design structures — in fact, some programs now use the moniker “shared renewables” to reflect the fact that the concept needn’t be limited to solar. In this three-part series of articles, we’ll focus on what has become the most typical program design: community solar programs launched by utilities in service of their customers.

Frequent readers of Greentech Media know that utility-led community solar programs are growing rapidly in popularity. According to the Solar Electric Power Association, there are now more than 50 community solar programs planned or operating. However, designing and launching a community solar program can be complex. Indeed, there are a number of questions that every utility faces as it works through the design of a program. Our three articles on the subject will walk through these questions, highlighting the many forks in the road toward the development of a successful program. Future articles will cover risk mitigation, impacts on utility bills, REC ownership, frequently debated terms and conditions, and best practices for customer messaging. Today, we’ll look at two key questions every utility considers when assessing a new community solar program: Who should own and operate the projects, and where should they be located?

Ownership

Project ownership is perhaps the first question a utility should consider, because the answer will drive decisions about countless other program design points. There are three fundamental approaches.

Utility-owned: In this case, the utility designs and operates the community renewables program, and the energy is sourced from projects owned by the utility. This option is most likely to appeal to investor-owned utilities (IOUs) seeking a rate of return on the solar asset used for the program. It may also appeal to electric cooperatives and municipal utilities that have a strong history of owning assets and or those that want to gain experience managing the process of building utility-scale solar systems. It is still an open question whether state commissions will allow utilities to earn a return on assets deployed for one segment of their customer base, even if the utility guarantees remaining customers will be held harmless. We expect commissions across the country will soon begin providing guidance to utilities pursuing this option. Utility ownership also poses the risks of asset ownership to the utility, and can be an inefficient way to monetize certain advantageous tax treatments available to encourage the development of solar systems around the country, such as the federal solar Investment Tax Credit. What is clear is that this model directly aligns with utility interests, particularly for large programs with many participating customers.

Power-purchase agreement (PPA): Under this option, the utility designs and operates the community renewables program, but the energy is sourced from projects owned by others.Though the right to purchase the asset over time may be included in the PPA, this option is likely to be easier and faster to execute due to the lack of upfront capital constraints. In addition, this option can be appealing in that it exposes utilities to lower technology and operational risks and may be the most efficient way to monetize available tax credits. What’s more, utilities can ensure they are receiving the optimal level of energy, as developers’ returns are directly correlated to the productivity of the projects. While this option presents many benefits, the utility should consider any possible risks it is exposed to related to the developer and project under development, as it does with other PPAs it enters into.

Third-party turnkey provider: This model differs from the other two in that the third-party provider not only owns and operates the project but also designs the community solar program, acquires customers, bears program risk, etc. Legislation in Colorado and Minnesota has supported this turnkey program design as part of a larger policy prescription to drive development of distributed solar. This model has also proven very popular with electric cooperatives, but less so with IOUs.

So far, programs operating today have utilized a mix of these options, but as more IOUs seeking a return on investment begin to voluntarily launch programs, and as programs grow in size and importance to the utilities, we expect the market to tilt toward the utility-owned model.

Project location

For utilities with small service territories, it is clearly appealing — though not always the right decision — to have the system sited within the service territory and close to customers. For utilities with larger footprints (for example, many IOUs), this issue is complicated by the fact that supply can’t technically be “local” for everyone, though it can be relatively closer and more visible to a high percentage of customers.

Local supply: A project within an urban area is clearly most appealing from a marketing perspective. People tend to connect more powerfully to a project they can see. However, this option will typically be significantly more expensive (e.g., by 50 percent or more) than a more remotely located project that is optimally designed on cheaper real estate.

Regional supply: Projects located within a utility’s service territory or at least in the territory of the same balancing authority (but outside of urban centers) can benefit from lower capital and operational costs, as well as superior energy resources, and thus can make the community renewables program much more likely to provide meaningful financial and/or energy hedge benefits to end-use customers. However, they also make it much less “visible” to customers being asked to participate.

Ultimately, 3Degrees expects to see utilities pursue a combination of these supply options for community solar programs going forward. In our experience, customers often verbalize a desire for extremely local supply, but when forced to act, they assign higher priority to a lower-cost option. Therefore, it will not be surprising to see community solar programs designed around a larger, cost-effective, regional project with other small projects located within population centers to provide visibility to the effort.

In the next article, we will cover risk mitigation for program design, REC ownership issues, and best practices for customer messaging about community solar.

Originally published in GreenTechMedia.