by John Powers



If you need an antidote for divisiveness and pessimism, consider an interdisciplinary workshop, held on the eve of the national election, in conjunction with the Fall Conference of the Peak Load Management Alliance (PLMA). For several years, the PLMA has hosted half-day pre-conference workshops for each of its topic interest groups.  But this year, Steve Koep, co-chair of the Behind-the-Meter Storage group, and I, co-chair of a new DER Integration interest group and project officer for CSVP, went in together.  Steve's group focuses primarily on technology for behind-the-meter storage, while the DER Integration group focuses more on program design issues. The result was a striking demonstration of collaboration and of progress in our industry.

We attracted excellent presentations, as you can see from the PLMA Conference agenda. We hit on many of the topics of great interest to those of you who have followed CSVP, in its efforts to increase local solar-project value. We hit policy issues, thanks to Robin Roy, representing the National Resources Defense Council; technology issues surrounding batteries, electric vehicles, and grid-interactive water heaters, thanks to multiple vendors, as well as Mike Taylor of SEPA; and program design approaches, thanks to Rich Barone of Hawaiian Electric, Dan Bradley of Navigant, and myself.

I was struck by how quickly the market is responding to the need to combine technologies and program designs into solutions altogether different from the standard demand response program of just a few years ago. Utilities, grid operators, vendors, and aggregators are all recognizing that assets behind the meter (both chemical and thermal storage) can be used to provide grid services required by increasing renewables penetration. While there has been much talk lately about DERs, this specific discussion dates back to the launch of a new industry group, the Community Storage Initiative , which held its first Leadership Council meeting back in July.  

Perhaps unsurprisingly, Hawaiian Electric has taken leading steps, valuing specific grid services and embedding the results in "grid service tariffs." These tariffs include rates and riders that tell customers how they can benefit from providing these services, either through utility-administered programs or through aggregator-delivered programs (via Grid Service Purchase Agreements with HECO). Rich discussed how this approach is currently being applied in demonstration projects, while these tariffs are being finalized and filed. 

In my opinion, this is a Big Deal. There are few, if any, other examples of vertically integrated utilities working in the absence of an ISO or RTO to break out economic value of individual grid services. This approach holds promise for many other utilities. It is especially meaningful for those operating in markets without ISOs, or more broadly, in markets without an active ancillary services market open to behind-the-meter resources. We at CSVP have found that the majority of utility-led community solar programs are in those regions, so Rich's experience could map onto utilities that want to use community solar as a market-based laboratory for testing a full DER integration strategy.

Meanwhile, from a market six time zones east of Hawaii, we heard from Dan Bradley of Navigant discuss the Brooklyn Queens Demand Management Initiative. This is Consolidated Edison's major project to defer billion-dollar distribution system improvements in a congested urban area.  Here, Con Ed ran an auction mechanism to create a competitive market for distributed energy resources, with four product auctions conducted in July of this year. The mechanism chosen was a "reverse auction," in which the auction was open for a set period of time, during which bidders could enter one or more bids in real time. Candidate technologies included load curtailment, energy storage, and a limited amount of self-generation (typically Diesel). Con Ed accepted offers for 22 MW of peak-hour DR from 10 providers, at prices ranging from $215/kW/year to $988/kW/year, depending on the amount of power reduction and technology used. These reductions must be delivered during specific time intervals when called in 2017 and 2018 in the specified locations.

This too is a Big Deal. The deferral of distribution expenses has been an elusive goal of DR programs and distributed-solar resource proponents for many years.  A reverse-auction mechanism in a specific geography appears to hold promise in reducing the complexity of problems like estimating market potential and targeting programs. The assembled group at our workshop looks forward to hearing more regarding Brooklyn-Queens initiative results over the next two years.

I'm running out of space to report on awesome work in grid-interactive water heaters, electric vehicle programs, and lots more, so feel free to contact me, via CSVP to discuss any of these developments. But the key takeaway for followers of CSVP is that the markets for behind-the-meter storage and demand response are evolving rapidly, in ways that can add value to solar programs. Watch the Community Storage Initiative and related efforts for new opportunities to integrate multiple forms of distributed energy resources in ways that capture additional customer and grid value. If you have a hard time keeping up, watch this space; CSVP, through the work of each of our participating firms, is leading, not only in the specific field of community solar, but also in building the larger collaborations needed to support growing penetration of all kinds of solar resources on the grid.

According to the Urban Dictionary, the status “It’s Complicated” refers to an ambiguous state that is beyond acquaintance, but not quite a relationship. It also may indicate dissatisfaction with a current relationship. So when Utility Dive recently asked me why the state of community solar policy is so complicated, it’s no wonder I flashed on the need for relationship re-boot between the key parties—the utilities and the solar developers—who both should have the long-term interests of customers in mind. Granted, the Community Solar Value Project (CSVP) has sat with the utilities most often, but we know our share of developers, too. Both sides in this relationship could use to sit down and recognize each others’ strengths and weaknesses.
 
The way I put it for Utility Dive is worth repeating, “Policies that keep utilities from working effectively with developers could be a lost opportunity.” Time and again, members of the CSVP team and I have been to workshops and events where the topic will touch on community-solar policies, and the utilities are missing. Likewise, the utility folks, who just a few years ago were very excited about community solar, often see “policy” on the agenda for a community solar event, and read it as a trigger warning for an ensuing a heap of trouble.
 
The Dive article itself demonstrated how broad utility participation could make community solar better. Author Herman K. Trabish, briefly recognized that there are numerous ways to add value, before jumping on a current favorite: project siting, or “locational value.” While that’s a worthy value, let me reiterate four different areas where utility-led community solar programs add value:

• Solar project siting and design,
• Financing and procurement,
• Target marketing, and
• Co-marketing with solar-plus companion measures

 
While I read Herman's article with great interest and respect (It’s complicated!), the fledgling community solar industry would be severely short-changing itself to put too much emphasis on locational value—or on any one strategy—alone. The challenge of entering a new landscape of integrated, distributed energy resources (DERs) is that it is an ever-changing place. A suitable local solar site with high locational value is rare and likely to change within the life of the project you put there. But a combination of technical and programmatic strategies, devised by utility- and developer-based innovators working together, could bring benefits that complete a solar-portfolio triad, along with with third-party rooftop solar and centralized utility-solar resources. What would a fleet of distributed community-solar projects, incorporating diverse benefits and net high-value, look like? How could utilities work with one or more developers over time to bring this about, with a greater long-run payoff for everyone?
 
If you’re interested in this discussion, our October webinar on the Value of Going Local provides a glimpse of a new analytic strategy that takes into account a few different value-add strategies, while avoiding the traps of a conventional (utility trigger warning!) Value of Solar analysis. We also recommend that if you want to learn more about the policies that do or do-not promote community solar innovation, we’ve had a webinar on that, too, featuring NRRI’s incisive policy analyst, Tom Stanton. You can replay the webinar or download the presentations here.
 
At CSVP, we are ready to embark on our third year. We’ve accumulated lessons learned and a list of questions that need resolution in order to support a thriving community-solar movement. One thing we know for sure: We need both utilities and developers to solve problems together, and we need regulators to let them.

For community-solar program designers, the first-cost of the solar project is always a consideration, but it is not the only consideration in promoting program success. The CSVP’s recent webinar on solar carports and shade structures illustrates this point. I can give you at least five reasons why solar shade structures merit consideration in your community-solar program plans, despite the added cost. And these reasons were underscored by our August webinar guests, Dan Ciarcia at Two Willows Consulting and Bob Boscamp at PowerParasol.

Reason #1: Carports Keep It Local
I’m not the only one who thinks community solar should be locally sited, on the distribution grid. Recent market research from SEPA and the Shelton Group suggests that most people who want community solar would like it to be sited locally—ideally within a short drive from where they live. Yes, there are some market segments that focus on price above all, but large segments say they would be willing to pay a small premium in order to keep community solar local.

The problem is, urban and suburban communities often have few good sites for ground-mounted solar projects. One of our Utility Forum members, Palo Alto Utilities, which is located in a community that is famous for its trees and its high property values, is a prime example. Palo Alto has not yet finalized plans for community solar, but it has already launched a carport-focused solar incentive. We anticipate that many communities—and especially those with sustainability goals—will demonstrate new ways to finance carport-based community solar, to keep participant costs acceptable.

Reason #2: Lower Solar Costs Make More Room for Improvements
A study from GTM Research in 2014 predicted a price premium ($/Wdc) for solar carports of 60 to 80 cents through 2018. CSVP has documented current premiums in the range of 45 to 60 cents in the West for relatively standard carport designs. Design innovations, improved installation procedures, and economies of scale as the industry grows can make a difference—but only up to a point. Most solar canopies use steel, at a relatively fixed cost.

But look at it this way: As PV costs decline, project sponsors can afford more of the add-ons that were beyond practical consideration a few years ago. A solar carport today is in same price range as a basic rooftop-solar project was in 2013.

Reason #3: Communities Want Green Parking
The U.S. Green Building Council now has a program called ParkSmart, which is gaining popularity in cities nationwide. This program has documented lots of ways in which solar carports improve community sustainability, from reducing the need for gas-fueled car air conditioning, to protecting night skies while supporting efficient lighting options, to reducing heat-island effects. Indeed, studies have documented that solar panels reduce heat island effects, relative to bare asphalt, by as much as two-thirds.

Reason #4: Community-Solar Carports Are Good For Business
A number of community solar projects have brought so-called anchor customers together with other participants in the community, to solve solar siting problems and increase economies of scale for community solar. Parking lots for retail shopping might be great anchor sites for community solar, where the business stakeholders take on a little more of the full project cost in order to benefit accordingly from the chance to offer their customers much-wanted shade. PowerParasol has cited research from the University of Arizona, indicating that shoppers will spend more time in stores (and spend more money), if their cars can be parked in shade.

Power Parasol also has demonstrated the value of solar in shading not only cars, but mingling people, as they participate in farmer’s markets, public performances, and outdoor events of all kinds.

Dan Ciarcia provided a compelling case for solar carports in cold climates, too. For example, one Honda dealership documented savings on snow plowing and sending sales staff to constantly move vehicles—adding up to a full week of worker’s pay for every snow storm. That’s not to speak of the extra advantage of being able to show more cars year-round.

Reason #4: An Invitation for School-Based Community-Solar Projects
One of the biggest markets for solar carports today is at schools. The buildings are hard to retrofit—especially in California and other places requiring architectural reviews. While some school districts are already obtaining carport solar from third parties, others are looking for solutions in partnership with utilities and whole communities. We’ve heard of at least one case where a utility considered treating the school as the anchor customer for a community solar project that would also offer shares to households in the community.

Reason #5: A Glimpse of the EV Future
Every electric utility should be preparing for an increase in electric vehicles. That includes early preparations for car-charging programs that contribute both energy sales and renewables-integration value. The Green Car Congress reported a recent study from Navigant, indicating that the EV market is growing at 60% year-over-year in North America. Of course, total market size is still small, and most utilities are not ready to go full bore into EVs. But a community-solar program that includes a carport-based charging demonstration is a great lead-in for talking about EVs with internal utility staff, local officials and customers.

A carport-based community solar program can keep the original concept of community solar as a test bed for new ideas alive and exciting. Most projects eventually would pay for themselves through energy benefits, but some carefully planned projects could pay for themselves sooner, through subsidization by anchor customers or even by charging a little bit every day for that prized parking spot in the shade.

Based on my experience, I advise utilities to take build a diverse portfolio of local community solar resources. This allows the resource base to grow with customer demand, and it gives utilities a chance to evaluate the real costs and benefits of alternative strategies.

And More...
A paper discussed in our July blog, on taking a new approach to solar value, includes a detailed discussion of how adding a few MW of carport solar to a larger community-solar portfolio can be achieved at no extra cost. (It also outlines a strategy that would work for many utilities in the West, utilizing flat-roofed solar carports that are cheaper to site and build, and which offer greater solar production on peak summer days.) In addition, we will be adding more resources on solar carports and other strategic solar designs to our website this fall.

As part of our participation in the National Solar Conference, in San Francisco this summer, CSVP team members produced a paper for American Solar Energy Society Proceedings. The paper focuses on the value to utilities of adding a significant amount of distributed, local PV to the community solar portfolio. This is in contrast to opting only for low-cost centralized solar resource, delivered from the transmission grid, through a retail community-solar tariff. (An updated version of both the paper and presentation are now available; see below. This includes slight improvements, thanks to our generous peers.)

The so-called cost gap between centralized solar and distributed solar has created an unanticipated barrier to local community solar programs. At risk are some much needed local flexible-grid benefits and other strategic utility-program values. As we looked hard at that problem, the CSVP team began an analysis, which resulted in this paper. The paper, A New Tone of VOS: Improving the Argument for Local Community Solar, is available if you send us a note on the Contact page, and the presentation is available below, with this post.

It introduces a new process, aimed at triggering utility acceptance for a mixed fleet of community solar resources, which includes a significant and growing distributed PV.  The process begins with discussion of a realistic hypothetical case, allowing internal utility stakeholders to consider solutions without arguing about details. And it is goal oriented, toward meeting a benefits target, rather than toward adding up every possible solar benefit. The process applies analytics sparingly, to facilitate better decision-making under highly changeable technology, market, and policy conditions.

In writing this paper, the coauthors, Jill Cliburn and John Powers from the CSVP team, with Joe Bourg of Millennium Energy, offer something provocative for utilities to consider. As we dicsuss, not all utilities will be able to implement this strategy point-by-point, and we know that. But the process described—focusing on the strategic narrative, rather than the spreadsheets—is, we believe, a timely and broadly useful contribution.

Finally, let’s add a word about the American Solar Energy Society (ASES), and its role in getting our team to sit down and write! The organization has sponsored the National Solar Conference for 45 years, and it continues to encourage rigorous thinking and academic-style presentations. This is a relatively small organization (these days) within our burgeoning industry. But the sometimes-painful process of writing a paper for publication has reminded us that careful research, analysis, and discourse can lead us all in new and exciting directions.

By Erich Huffaker

As we examine the landscape for new utility “solar plus” projects, along the lines of community solar combined with demand response (DR) or storage, we realize that one of the more compelling reasons why utilities should pursue a this type of program is that a growing number of non-utility companies are already working in this market space. On the East and West Coasts and in some places in between, there is a burgeoning industry around integrated demand-side management, including DR, storage and distributed renewables. Innovative third-parties are giving electricity customers increasingly better tools to cut demand charges, modernize operations and reduce overall bills. For utilities that choose to watch from the sidelines, the fracture in the traditional utility-customer relationship drives deeper.

For example, GreenCharge Networks (GCN), with offices in Silicon Valley, New York, and San Diego, provides “intelligent energy storage” solutions-management services for onsite generation, energy management systems, DR, and storage. GCN installs integrated battery systems in large buildings and institutions nationwide. Recognizing that these systems can greatly expand the value of solar in mitigating utility demand charges, GCN is specifically targeting commercial solar sites. It is not adverse to utility partnerships, however—should the utility ask—as proven by recent work in collaboration with Duke Energy.

What about the arguments that storage is prohibitively expensive? Earlier this year, GCN secured financing to offer no-money-down battery systems to customers. And, GCN is not the only one providing this innovative financing model. Stem, a primary competitor to GCN, headquartered in Milbrae, CA, also offers a behind-the-meter demand-charge mitigation storage tools.

Companies are also making innovative software platforms to handle the increasingly evolving ecosystem of devices and hardware available for customer energy management. Geli’s hardware and software helps manage microgrid and EV-solar battery integration projects. The platform optimizes for complicated use-cases, involving multiple on-site assets, focusing on solar-plus-battery sites. Geli models the technical performance and financial impacts of installations, with market-specific information on how the system impacts utility tariffs and demand charges.

The takeaway is not that every utility should attempt to undertake innovative, complex integrated demand-side management projects on its own. Instead, it is that there is a growing customer appetite for more holistic energy management. In fact, this growing appetite is more important than any specific end-use solution. Once a customer has embarked upon this path with one service provider, that customer is unlikely to abandon that path completely and to start work with a whole new partner or partners. Continuity is valuable to these customers. That’s why the utility must show up now and join in, before it’s too late.

We’ve found that the utility has unique comparative advantages, which may be leveraged with the customer during this early-stage window of opportunity, irrespective of what other offers may be on the table by third parties. Utilities need to think clearly about what kind of a service packages they can provide to meet their customers’ needs. Often this will involve technical partners and initial pilot projects—in fact, projects that might include community solar, designed to include key stakeholders and technical partners. But utilities need to get serious about addressing this growing market, because if they don’t, somebody else will.

Erich Huffaker, a Project Specialist at Olivine, Inc. will be departing the CSVP Team this month as he pursues diverse professional interests and a penchant for travel. He recently coauthored the CSVP guide, Integrating Demand Response Into Community Solar Programs. We will miss him and look forward to his future dispatches.

When we began the Community Solar Value Project, we held a clear vision of shared-solar projects that would bring the utility and its customers together in a market-based demonstration of several DER strategies needed for an integrated and flexible grid. We envisioned tapping strategic solar siting and design plus DR and storage “companion measures”—orchestrated to help balance the load and increase the net value of local PV. Now, a year later, we’re almost there, except for a few challenges, including one in the guise of low-cost centralized solar.

Yes, it is hard to turn down a cheaper solar option. According to the Solar Energy Industries Association and GTM Research, solar costs fell last year to less than $1.50 per Watt for utility-scale fixed-tilt systems. If you were doing community solar primarily to deliver savings to subscribers, this might look like an answer. A number of utilities are now planning voluntary programs that tap big solar and package it kind of like wind-based green-power programs. Even community solar on the distribution grid is going to the urban fringe. In Minnesota, community solar developers have been co-locating 1-MW projects to reach economies of scale, with the state limiting developers to five co-located projects.

At the Community Solar Value Project (CSVP), we always recognized the benefit of scale. But we are focused on distribution-system projects, and preferably infill projects in the 500-kW to 2-MW range. Why? Well, one of our core assumptions is that distributed solar is here to stay. Whether or not the utility is involved, customers will pursue distributed solar. But if the utility were involved, the pairing of these large-commercial scale projects with DR and storage options (and in some cases, energy efficiency) represents what we call a “market-based laboratory” for field-testing many of the smart-grid and flexible-DER strategies that are currently stuck at the white-paper stage or in isolated pilot programs. As far as we know (and tell us if we’re wrong) no one has yet market-tested the economics of a distributed solar fleet strategy (achieving, say, 10 MW through a fleet of community-solar projects). Certainly there is little testing of distributed solar strategies that incorporate high-value companion measures. Sources like GTM Research and Rocky Mountain Institute and ICF International all have recently touted the distributed-energy future. And, for the most part, we believe them. But implementation in existing utility cultures, including engagement with and learning from “real” customers, is a project that needs to start now. The smart grid will not emerge fully armed, like Athena, from the head of Zeus. It will emerge from a trail of better and bigger attempts to get the thing right.

The CSVP recently started to work on an effort called “Filling the Pricing Gap,” to help utilities create and justify more competitive community-solar pricing for programs based (at least primarily) on local PV resources. You will see presentations and reports on our progress here in coming weeks. The folks at the Sacramento Municipal Utility District have been walking this road with us—or more accurately, they are usually in the lead, as they apply tremendous experience and in-house expertise to the challenge. One early example: they have taught us that a conventional “value of solar” argument is not such a practical solution for justifying near-term program design. For one thing it makes most utility guys’ hair stand on end. For another, it raises endless “what-if” questions about increasingly dynamic technical options, markets, and policies.
While others look for a VOS algorithm that would be, in effect a “theory of everything” for DER, we work to combine a relative few, fairly indisputable aspects of VOS analysis with targeted strategic arguments. This includes presenting what we call “realistic hypotheticals,” scenarios with ranges of numbers that are not intended to hit the value nail on the head, but which are nevertheless worth considering.

I use plural because we are addressing multiple internal stakeholders in the utility, all of whom have strong (and often conflicting) points of view. We are also addressing the utility’s most timely concern—that it needs to build and maintain strong customer relationships throughout these trying times. Watch our Library and Workshops pages for our reports from the field—where at least for the most part, we are keeping it local.

By Andrea Romano, CSVP Team

When community solar subscribers sign up for project shares, they will likely feel proud to be “getting solar,” even if the project itself is far from home. The question for utilities is, are these subscribers really getting solar? And if program shares include something less than REC-bundled kWh, how should you describe them in marketing materials? Ever since the advent of renewable energy certificates (RECs) in the late 1990s, confusion has surrounded these questions, because, according to REC guidelines, electricity is only renewable the RECs are included and retired.

Yet policymakers and program designers know that most solar supporters are eager to get the REC value, and would gladly trade away this arguably esoteric distinction. Should the utility use REC purchases to sweeten the community solar offer—or not? The Community Solar Value Project (CSVP) just released a new factsheet, Understanding Renewable Energy Credits, to address this issue. It is posted with this blog and in the CSVP website Library.

The REC, defined as the renewable energy attributes of one megawatt-hour (MWh) of renewable electricity generated and delivered to the grid, is a concept originally developed for three main reasons: 1) Federal agency, business and industry interest in purchasing "green power," 2) state-sanctioned accounting to meet renewable energy mandates, 3) added economic benefits in negotiating power purchase agreements to cover renewable energy project costs.

Today, all claims of using renewable electricity depend on the RECs associated with that electricity. Even if a renewable generator produces electricity on-site, the project owner is not considered to be using renewable energy if the RECs are not associated with the electricity and retired on behalf of the customer. RECs are a credible way to buy and sell renewable electricity because RECs can be uniquely numbered and tracked. The electricity associated with a REC may be kept bundled with the REC or sold separately. If it is kept bundled with the REC then it is called renewable electricity or “green” electricity. If the electricity is split from the REC, it is considered standard energy.

REC guidelines apply to all renewable energy, including community solar. The most common REC allocation options for community solar programs include:

• Utility owns and uses the RECs for current or anticipated regulatory compliance.
• Utility or customer sells the RECs into the local or regional REC market.
• Utility retires RECs on behalf of the customer.

According to a September 2015 NREL Report, RECs for community solar projects are most often used to meet RPS compliance. Considerations affecting how specific programs treat RECs include program goals, regulatory orders, negotiations with solar developers, and program economics. Many utilities with community solar programs claim that customers either don’t understand or don’t care about the RECs. In some cases, RECs are retained by the utility and aren’t even explained to customers.

Xcel Energy’s Community Solar Garden program in Minnesota has taken an interesting approach, allowing third-party community solar project operators to decide whether to retire RECs on their customer’s behalf or to sell them to the utility for $0.02-$0.03/kWh. Initially the Xcel managers thought most third-party project operators would sell the RECs to the utility to improve their economics, but subscribers have been more interested in retaining the RECs than originally assumed. The jury is still out regarding how the Minnesota community solar market will develop. But no matter what your utility decides to do with community solar program RECs, it is important to engage customers and stakeholders honestly in the discussion–early in the program-design process. Clearly explaining the concept and treatment of RECs to community solar subscribers is an important component of marketing any community solar program.


Yet policymakers and program designers know that most solar supporters are eager to get the REC value, and would gladly trade away this arguably esoteric distinction. Should the utility use REC purchases to sweeten the community solar offer—or not? The Community Solar Value Project (CSVP) just released a new factsheet, Understanding Renewable Energy Credits, to address this issue. It is posted with this blog and in the CSVP website Library.

The REC, defined as the renewable energy attributes of one megawatt-hour (MWh) of renewable electricity generated and delivered to the grid, is a concept originally developed for three main reasons: 1) Federal agency, business and industry interest in purchasing "green power," 2) state-sanctioned accounting to meet renewable energy mandates, 3) added economic benefits in negotiating power purchase agreements to cover renewable energy project costs.

Today, all claims of using renewable electricity depend on the RECs associated with that electricity. Even if a renewable generator produces electricity on-site, the project owner is not considered to be using renewable energy if the RECs are not associated with the electricity and retired on behalf of the customer. RECs are a credible way to buy and sell renewable electricity because RECs can be uniquely numbered and tracked. The electricity associated with a REC may be kept bundled with the REC or sold separately. If it is kept bundled with the REC then it is called renewable electricity or “green” electricity. If the electricity is split from the REC, it is considered standard energy.

REC guidelines apply to all renewable energy, including community solar. The most common REC allocation options for community solar programs include:

• Utility owns and uses the RECs for current or anticipated regulatory compliance.
• Utility or customer sells the RECs into the local or regional REC market.
• Utility retires RECs on behalf of the customer.

According to a September 2015 NREL Report, RECs for community solar projects are most often used to meet RPS compliance. Considerations affecting how specific programs treat RECs include program goals, regulatory orders, negotiations with solar developers, and program economics. Many utilities with community solar programs claim that customers either don’t understand or don’t care about the RECs. In some cases, RECs are retained by the utility and aren’t even explained to customers.

Xcel Energy’s Community Solar Garden program in Minnesota has taken an interesting approach, allowing third-party community solar project operators to decide whether to retire RECs on their customer’s behalf or to sell them to the utility for $0.02-$0.03/kWh. Initially the Xcel managers thought most third-party project operators would sell the RECs to the utility to improve their economics, but subscribers have been more interested in retaining the RECs than originally assumed. The jury is still out regarding how the Minnesota community solar market will develop. But no matter what your utility decides to do with community solar program RECs, it is important to engage customers and stakeholders honestly in the discussion–early in the program-design process. Clearly explaining the concept and treatment of RECs to community solar subscribers is an important component of marketing any community solar program.

by Spence Gerber, CSVP Team

Thanks to Solar Holler, a West Virginia-based non-profit solar development company for showing us how to prompt community engagement and leverage demand response (DR) in a completely new way. While this program model is not driven by a utility, it is utility-savvy, employing a similar DR strategy as the highly regarded program at Steele Waseca Electric Cooperative.

Two differences, though: First, it is focused on bringing solar benefits to public buildings, low-income housing, and churches, in a true spirit of “shared solar.” Second, it monetizes DR benefits at a regional market—in this case PJM. That may be a region-specific opportunity, but the overall program translates to almost any utility easily. Moreover, the big story here is that there is plenty of room for out-of-the-box thinking and innovation in the community solar space.

Let’s take the example of Solar Holler’s first project, where about 100 participants helped put 16-kW of PV on a Shepherdstown, WV, church. Anyone who has worked with a non-profit community based organization, whether it be a school, church, library or community center, is well aware of the challenges associated with meeting basic financial obligations—including the energy bill. Grant applications, fund drives, bake sales and passing the hat are efforts that are all too familiar to the good folks doing good things. All of this consumes an inordinate amount of effort and creates constant worry for the organization’s board and staff.

But Solar Holler has developed a model that takes a chunk of the ongoing expense of energy costs away from the organization, engages supporters, and provides collateral benefits to the community at-large. Based on estimated project costs, Solar Holler launched a crowd-funding effort for the church. Rather than ask for cash, participants that have electric water heat were asked to sign up for a free water heater controller. A small, nearby company that serves as a DR aggregator, called Mosaic Power, put in the devices, controls them together as a “virtual power plant,” and then participates in the PJM energy market. Mosaic gets paid for participation as a curtailment service provider.  The aggregator covers the cost for the equipment and installation of the water heater controller, as well as paying $100 per year to the each participant. Instead of receiving the annual payment directly, participants agree to apply the money toward payments on the loan for the solar installation. This plan has benefited the church and subsequently other facilities that serve low-income communities.

Solar Holler points out that the combination of solar-plus-DR reduces the use of fossil fuel in two ways. First, the solar project generates carbon-free energy, and second, the DR that Mosaic Power is selling to the grid most likely displaces fossil fuel resources that would otherwise be dispatched.  Beyond that, the solar and controller installations are providing real-life experience for local job training programs. According to the Dan Quitos, of Mosaic Power, the program has scaled up well so far and could support a larger effort, covering a large utility territory. The Solar Holler website includes detailed media coverage on all of its projects, including new work in the low-income housing sector.

To hear Dan tell the whole story, go to our webinar archive, under the Media tab. Solar Holler was featured on the CSVP November webinar, along with Grid Alternatives, another non-profit company that brings community solar to the low-income audience. In that case, projects often involve utilities directly. The staff at CSVP has identified these and other low-income community solar programs, in response to strong interest from the utilities nationwide. We invite you to learn more through this fact-sheet, and to let us know how you are tackling the challenge of increasing the availability of community solar options to people of all income levels and all housing types.

While there are countless facets to a “better” community solar program, we’ve found three (see above) that merit nearly all of our team’s attention. One of these—the integration of community solar with companion measures—is especially interesting. But often, it is my job to sharpen our focus even more, to distinguish between aspects of integration that are merely interesting and those that are truly important.

What’s Interesting about integrating solar with demand response (DR), storage, and other DER measures?

Everything.  In the area of renewables integration, a news note seems to pop up every 20 minutes.  Microgrids, battery storage pilot projects, electric vehicle charging technology, analyst opinions on the cost curve for lithium ion vs. flow batteries, grid-interactive water heaters bid into ancillary services markets (yup, that’s a thing)… All of it is super-interesting.

But what’s important?

In part, that has been defined by the wisdom of our project funders. The CSVP lives under the U.S. Department of Energy Solar Market Pathways program umbrella. Awards in this program must work with market-ready technologies and approaches that could drive down soft costs of distributed solar in the market in the next three to five years, helping to reach SunShot Initiative goals.  Further, any results our project develops must facilitate replicable projects at scale, and soon.  

That mandate leads an economist like myself to apply some simple rules when considering whether to spend project resources considering any particular technology or approach. Specifically, can I imagine this Thing (product, technology, concept, approach, whatever) driving hundreds of megawatts (MW) of new community solar projects over the next three to five years?  If so, it’s important. If not, it’s just interesting.

What makes me imagine that a given approach will yield hundreds of MW of new community solar projects? Economics. Yes, there will be experimental projects that are not economically competitive with other generation sources, and those will deliver a little capacity here or there. But to deliver lots of MW soon, projects have to be economically viable.  In this blog, I won’t be doing LCOE calculations, and I won’t even get into whether “economically viable” means a nickel or a dime per kWh,  but to be important, a Thing needs to move the dial now, without extraordinary subsidies.

This rule of thumb brings me to the reason why we are leaving some technical options out of our program focus—notably, microgrids. I will be open to reader comments on this, but let me first give my rationale.

I am perfectly willing to believe there will be community solar projects (maybe even quite a few of them) that are part of microgrids. But do I think this will lead to hundreds of MW of new community solar projects over the next three to five years?  No I do not.  Microgrids are expensive. Sometimes, very expensive. (See http://www.acgov.org/smartgrid.htm) In some applications, that’s fine – maybe a hospital or a jail needs to be on a resilient microgrid, and maybe a military base does too, and maybe current economics in those applications are secondary. But a 1-MW community solar project as part of a microgrid would cost several times more than a 1-MW community solar project that operates as part of the utility grid. Unless there are other sources of funding to subsidize a community solar microgrid, it is doubtful that we will see significant market growth in that option anytime soon.

On the other hand, mundane tweaks to existing demand response (DR) programs are timely and important.  DR programs have been around for several decades, and have been targeted primarily at peak reduction (often in emergency situations). New DR technology, including sensors, controls, communications technology, and new priorities—in particular, wind and solar integration—are breathing new life into the DR industry. For most applications, using building thermal mass or hot water as a storage medium by pre-cooling buildings or pre-heating water can be far more attractive economically than using batteries for storage. For example, a 2014 white paper from ESource cited data from Sandia National Labs, comparing the cost of storing a kilowatt-hour in a properly-controlled electric water heater to the cost per kWh for storage using various batteries and other storage technologies. The water heater option cost one-fifth to one-tenth as much as storage in a lithium-ion battery. Of course, the battery costs are declining, and some are recommended for particular applications. But given the relatively low cost and proven success of existing DR programs, applications of DR for renewables integration are, by my definition, important today.

In the coming months, you’ll see some preliminary results from the CSVP project that can assist utilities in selecting different options that raise the total value of a community-solar-plus-storage-plus-DR program. Based on our analysis and experience so far, we are convinced that the incremental value created in community solar programs by this type of integration (along with the strategic solar design and market innovations mentioned above) can be quite significant.  And as community solar programs around the country start to scale up, we think that will turn out to be important.

When people ask what excites me about this project, I often say it’s that community solar—done right—demonstrates how utilities and their customers can bring a high-value, low-carbon utility of the future to life right now, in a neighborhood near you.  

Some years back, I spoke at a national conference about the need for utilities to grasp the potential strategic value of distributed PV (DPV). The solar industry had pushed the needle, but few utilities had even experimented with the distributed-solar value proposition. I got a little worked up, and remarked that until customers, utilities, and industry partners would work together to make solar count, DPV was little more than “solar bling.” In fact, a 2013 NREL report on the treatment of solar generation in utility resource planning confirmed that even then, most utility planners believed that customer-sited DPV was simply counted as net load than generation, and its impacts, for better or worse, were easily “lost in the noise” of load forecasting. Following suit, many distribution-system operators and others in the utility saw DPV mostly as lost load, lost revenue, and pesky engineering problem.

























Today, that is changing. As distributed-solar penetrations increase, DPV is being recognized as a resource. And projects like the Community Solar Value Project are supporting the collaborative work that’s needed to assure that solar counts. We believe community solar is exactly the right place to begin, because it is, by definition, a collaboration. Utilities can guide the best possible siting, design, and specification of community solar projects, regardless of ownership structures. And they can design “companion options,” involving customer demand-response or storage, creating synergy and added value for both the utility and the customer. We find utilities are especially interested in offering companion measures to adjust the generally imperfect fit between solar and costly system peaks, and to prepare for other, looming renewables-integration problems in various time domains. Community solar might be a “desert first” strategy to sell more smart-energy vegetables. And to secure needed customer participation, utilities have to take customer interests seriously. These include interests in savings and convenience, but also in embracing community values.

Our colleague Tom Hoff of Clean Power Research recently attended a CSVP workshop and shared an easily visualized example of one way to “make solar count.” Using a single household as his example, he showed how a homeowner might be dismayed to find that putting 4.4 kW of PV on the roof does relatively little to reduce total household carbon impact. Adding an electric vehicle and increasing the size of the solar system could do much better—but if the vehicle were charged at night in a region with low wind resources, it still might draw on fossil fuel. In addition, the amount of solar needed to virtually offset the vehicle’s needs could exacerbate the so-called Duck Curve, with its steep afternoon peak and risks of seasonal over-production. The solution? Well, night-time charging, for one thing. But Tom also suggested a handful of other energy-efficiency and load management solutions, such as storage water heating and pre-cooling, which taken together would make this household nearly carbon-neutral. The CSVP team recognized much of this strategy, leading us to question whether that household's solar must be on the roof, or could it be part of a community solar project? Of course it could. And we believe that broadening the value proposition from one household to a community creates a large and diverse pool of other ways to maximize value for everyone.

That is a big vision, and we are just beginning. However, our utility partners, including the Sacramento Municipal Utility District, Public Service of New Mexico, and a half-dozen more are working with us to assemble the pieces of a new, high-value community solar model carefully and quickly. Solar is coming of age, and more and more customers are ready. They care about solar, and they care if it counts.