As this Website has turned attention to broader questions of community-scale solar, storage, and load flexibility, we have separated our trove of informative, link-laden blogs.

Blogs related to our new work are posted under a current Blog link on our main menu. That work includes, Solar-Plus for Electric Co-ops (SPECs), along with work relationships formed through the NREL Solar Energy Innovation Network (SEIN), through the National Community Solar Partnership and our long-standing participation in industry networks.

It is our plan to provide a guide to archived blog topics. Meanwhile, Contact us with any questions related to community-scale solar, storage or load flexibility, especially related to innovations among electric cooperatives and public power utilities. We will freely point you to current and archived resources.

by Jill Cliburn

At this turn of the year, a lot of us who work in renewable energy feel a nice sense of accomplishment, and also the press of a challenge to follow through on great expectations. The list of states that are aiming for 100 percent clean energy by 2050 has grown to nine, plus the District of Columbia and Puerto Rico, and more than 150 local governments nationwide have issued similar goals. We love the vote of confidence, but now we—and I include in our circle researchers, local utility leaders, upstream utility counterparts, engineers, program designers,  policy wonks, citizen-advocates and business folks--we all have to move fast and think big.

Energy storage was always the missing puzzle piece. The growth of affordable battery storage is changing that—but we also need to look beyond batteries. The list of viable alternatives is growing; we could not list them all. But we decided to cast our eye on a sleeping giant: pumped-hydro energy storage, reconfigured for communities in nearly all geographies. Read on; you might be surprised.

Pumped hydro relies on moving water between an upper reservoir and another reservoir at a lower elevation. When electricity is needed—even in a quick response mode—it may be generated by releasing the stored water through turbines in an operation that is similar to conventional hydropower. Then, during periods of low demand, the upper reservoir is recharged by using lower-cost electricity from the grid or from co-located renewables to pump the water back up. The technology is well-established and used by (among others) our nation’s federal hydropower providers. Altogether, the U.S. has about 22 GW of pumped hydro storage today. According to Mark Gabriel, Administrator of the Western Area Power Administration, “It’s the best storage you can get.”

However, it may be no surprise that most existing pumped storage projects are big—averaging over 600 MW—and that they have not always met high environmental standards. The question is whether pumped hydro could be cost-effective on a much smaller scale, using modular designs, that would be acceptable and directly beneficial to the communities nearby.

I learned a bit about this technology from David Timmons, a mild-mannered associate professor of environmental economics at the University of Massachusetts, Boston. Timmons presented at Solar 2019, the annual conference of the American Solar Energy Society, held last summer in Minneapolis. He shared resource assessment and modeling completed for an island nation called Mauritius, in the Indian Ocean. Isolated from sources of fossil fuel and fully aware of worsening climate impacts, the leaders of Mauritius wished to go “100% renewable.” Timmons’ team designed a solution that included a range of renewable resources, but required a cost-effective approach to energy storage.

According to Timmons, pumped hydro storage came in cheaper than today’s battery storage costs, especially for longer duration operations. (Timmons modeled his economics using 2018 Lazard data.) The surprise was that the pumped hydro system could be accomplished on a relatively small scale. Modeling targeted a reservoir that also provides drinking water and irrigation for the island’s 1.2 million residents. The cost—especially for longer-duration storage—beat batteries, even considering likely battery cost reductions. Timmons believes that relatively small-scale pumped hydro can help balance the costs and more importantly, the environmental impacts of lithium-ion and other battery products. Where reservoir evaporation might be a an issue, floating PV could be developed to serve a dual, high-value purpose.

We checked the facts and found reasons for cautious optimism. Most small pumped hydro storage projects take a hit on economies of scale, but the designs and the dollars are improving. In 2017, U.S. DOE funded nine projects, including one with Shell that is just 5 MW. The DOE’s Hydropower Vision summarizes a range of new designs, including smaller scale pumped hydro projects.

We also found a recent study from researchers in Australia, employing a mapping tool that identified more than a half-million suitable sites for pumped hydro projects worldwide. Altogether, they would provide more than 22 million GWH of energy storage capacity. An article in PV Magazine quoted one of the authors, saying, “Only a small fraction of (these sites) would be needed to support a 100% renewable global electricity system. We identified so many potential sites that much less than the best 1% will be required.” The team’s approach included identifying sites where dry gullies could be adapted to create pumped hydro stations with less environmental impact than the classic approach, which focuses on damming river ecosystems. The team published a smaller study in 2017, focusing on Australia before going global.

Image of likely pumped storage sites from researcher Matthew Stocks, Australian National University.

Most likely, even the 1% target for developing potential pumped hydro sites will prove difficult, but from Timmons’ view, it is worth thinking about stored hydropower on the community scale—even using even municipal water reservoirs or charging new systems, as the Aussies envision. According to Timmons, it is entirely possible to see more projects that deploy storage in a front-line integrated-DER strategy, which could provide renewables integration and greater rewards close to home.

We are still betting on batteries for the near term, but looking ahead, we would love to see alternative storage solutions on future SEPA “Top 10” lists, which recognize the top providers of annual watt-hours of storage, per customer.

In parting, Timmons reminded me of the professors who were my mentors years ago, working in relative isolation but thinking freely and a bit wildly. Not all, but most of their renewable-energy innovations eventually came true. And that inspires my holiday wish: keep fueling our future with bold thinking. And here’s to abundant energy for 2020 and the decade beyond.

by Jill Cliburn

A just-released 2019 U.S. Solar Market Insight report from SEIA and Wood Mackenzie predicts, “By 2023, roughly 30% of total non-residential PV capacity will come from community solar, and 20% of all non-residential capacity is expected to have storage attached.” This prediction resonates with the view we expressed last summer, that the market for community solar-plus is rumbling and ready to rock the industry, before a lot of community solar planners and developers can get their socks on.

It’s exciting, but also a risky time—especially for municipal utilities and co-ops that are still on the learning curve about solar PPAs and storage operating agreements, even as they are negotiating their place between upstream wholesale providers and downstream customer/advocates.

How do you get through it? At CSVP, we have always recommended a collaborative process, and our Solutions process seems more apt today than ever. But in addition, we can offer some newsy additions.

Recently, our friends at the Rocky Mountain Institute (RMI) Shine Program opened a  website focused on community-scale procurement. It is aimed to support solar in the 1- to 10-MW range. Recommendations were refined over a series of procurements in 2016-18, which RMI supported for utilities in Colorado, New Mexico, Texas and New York. Those experiences are documented in its report, Progress and Potential for Community-Scale Solar.

Above: 2016, RMI estimated costs of $85/MWH for community-scales solar. General market forces have helped to lower solar costs, but specific procurement strategies led participating utilities to achieve especially attractive pricing—even on projects under 5 MW.  RMI, 2018.

In short, RMI’s hypothesis about the value of buy-side consulting to facilitate solar procurement proved true. Its process has secured attractive PPAs, including a run of community-scale projects in the $45 to $55/MWH range. Specific strategies, which RMI calls “levers,” can be credited for much of this success. They range from increasing the utility's contribution (for land, interconnection, etc.) to facilitating better communications between utilities and bidders, to applying effective techniques between the short list and the final negotiation and encouraging group deals among utilities. In discussing these strategies with RMI program manager Kevin Brehm, it is clear that the outcomes generally exceeded expectations. Yet they also hit a few bumps. For example, the challenges of pulling off a group deal among locally-controlled entities often prevent utilities from realizing full economies of scale. Also, a recent RMI procurement process that included solar plus storage revealed reluctance among bidders to deal, at least at this stage of market development, with RMI’s analytic requirements and streamlined terms. (We return to that topic below.) While anticipating further refinements, the Shine project website will focus on solar projects, except to report on solar-plus in its case studies.

A full set of storage case studies, plus plain-English explanations of storage technologies, use cases and economics, are featured in a new guide, Battery Storage Overview, released this summer by the co-ops. Co-authors include National Rural Electric Cooperative Association (NRECA), National Rural Utilities Cooperative Finance Corporation, CoBank, and National Rural Telecommunications Cooperative. This guide complements the solar development resources already housed on NRECA’s SUNDA project website. It includes an explanation of the levelized cost of storage (LCOS), accompanied by a real-world example, to show how still-costly storage can alleviate wholesale demand costs. It suggests lithium-ion storage for a (not unusual) utility, paying $12/kW/Month for demand, $22/MWH for energy, producing benefits that “payback” in 8 years. In this scenario, the utility would buy the battery. Beyond the economics cited, this hypothetical project might further improve cost-effectiveness by tapping resilience value, grid deferral, or other integration values.

A municipal utility example, aimed at demand cost reduction, was recently updated by the North Carolina Clean Energy Technology Center. The (NC CETC) solar program worked with the Fayetteville (NC) Public Works Department on a community solar plus strategy. It uses a purchase model, in contrast to another muni-based community solar-plus program at Sterling (MA) Light and Power, which used a PPA. Fayetteville aimed to make its project work without access to the ITC. With analytic support from NC CETC, Fayetteville was able to procure a relatively small, 500-kW/1MWH lithium-ion battery, along with a 1-MW solar array. Community solar economics are shouldered fully by program participants, while the battery serves all ratepayers. Demand-savings provide a 10-year payback, before counting any extra storage-related values.

A spotlight poster presentation at Smart Energy Week last month described how NC CETC modeled the time and duration of likely utility peaks, using multi-year data. After analysis, the utility decided to trade perfect peak-demand avoidance for avoidance around 80%. With that, the utility could acquire the battery now, for a full program launch this fall. This is an important lesson for smaller utilities that want to gain battery experience. Such utilities can work on a demonstration scale and still reap savings. That is true, even as NREL predicts that regional markets with increasing renewables will find 4-hour batteries—or even 8-hour batteries—necessary to fully address their widening peaks in future years. The storage value proposition is likely to play out differently at the local level than from the regional bird’s eye view. Local utilities may be first to optimize storage and load flexibility, revealing values that analysts can barely see from afar.

Above: Battery storage required for full vs. partial avoidance of wholesale peak demand charges, testing scenarios customized for Fayetteville PWC. NC CETC 2019.

None of the resources referenced above fully address one key problem that many utilities face as they venture into the battery storage market. That is, how do you estimate and evaluate the battery storage agreement and options for dispatch support? As CSVP reported last year, this is a prescient question.

The combined costs of solar-plus storage agreements that have been reported on fairly large projects, have been compelling. The 2018 Utility-Scale Solar Markets report from Lawrence Berkeley National Labs reported multiple solar-plus battery projects where the added cost of batteries over solar alone was just $5 to $15 per MWH. The same analytics do not apply at the distribution scale. However, the buzz around smaller-projects last year suggested that well-designed battery agreements, combined with good forecasting on the solar-generation and demand side, can produce strong net economics for community-scale projects, as small as 1 MW/2 MWH. Small projects are do-able, but there is still a lack of information readily available, without relying on peer-to-peer networking.

Consultants on our team recently proposed a new collaboration to improve the understanding and use of solar-plus PPAs and storage agreements. Based on discussions with a half-dozen utilities and as many technology experts and providers, we’ve concluded that the need for best-practices and guidance in this area is delaying more widespread solar-plus-storage success.

For now, there are a few limited but helpful places to turn. The Clean Energy States Alliance, (CESA) has spotlighted utility-based solar-plus projects and touched on the challenges, costs and benefits of storage agreements. CESA works closely with the team at Sandia National Labs, showcasing Sandia’s state-of-the-art analytics—still unfortunately out of reach for a lot of local utilities. NREL also continues to refine its ReOpt analysis tools for solar and storage integration. And industry groups like the Peak Load Management Alliance integration forum have hosted some dialog between solutions providers and utilities. Much more of that dialog—before, during and after procurement—is needed to assure the best community solar-plus project outcomes.

by Jill Cliburn

There it is, below: my favorite image of people working in silos. Unfortunately, you may see a similar image in your own community—or in any organization that is striving to succeed with community solar-plus. CSVP has led a gentle, persistent campaign to move all the folks needed for these highly integrated solutions out of their silos and into more effective and fast-acting collaborations. But as we discuss at this year's Solar Power International Conference and Exposition, sometimes gentle persuasion needs a boost, in the form of policy action.

We explore these thoughts in an SPI poster that CSVP principals Cliburn and Powers co-authored with Achyut Shrestha of North Carolina Clean Energy Technology Center (NCCET) and Marta Tomic of Vote Solar. High points and policy-oriented conclusions are summarized here.

Taking a critical look at the small number of existing community solar-plus projects, we recognized that most solar-plus projects are still in the realm of consumer-owned utilities (COUs, such as electric co-ops and munis). That is primarily because COUs face fewer state-policy barriers to innovation. Yet there are some emerging IOU projects, too, which we also examined. We identified four major barriers to community solar-plus success:

1. Less favorable net metering policies for community solar or customer-owned systems persist, and there is little if any guidance for solar plus storage;

2. Lack of standardization in procurement methods for energy storage systems, especially with regard to establishing complex multi-partner storage-operation contracts;

3. Full requirements wholesale power contracts for COUs often limit the local utility's ability to generate their own energy or to hold PPAs. At the same time, many wholesale suppliers are reluctant to provide local DERs;

4. COU’s represented by G&Ts or joint action agencies must revisit agreements to promote both innovation and equity among members.

Notice that none of these has much to do with a need for technology innovation. The closest we come to a missing technical link would be to improve the operation (perhaps standardization?) of storage operating software, so utilities could more readily integrate battery storage with existing DR programs. Tech wizards I have not met yet are probably out there shrugging. “Sure, we can do that.”

But the rest of these barriers have to do with policy. For example, here in New Mexico, I met last year with a team that was drafting community solar legislation. We agreed that allowing community solar to co-locate with storage would be forward-looking for utilities and stakeholders. But if the community solar developer were a private "third party," then more guidance would be needed in order to work with the utility. Would the arrangement affect the community solar "share" value? Virtual net metering, using time-of-use rates or incentives, could be part of that answer. But, diving deeper...? These are complicated questions. Alas, that legislation did not pass last session, but it will come up again.

According to Vote Solar, states like Massachusetts and Hawaii have recently taken steps to provide additional value for community solar plus storage. Under the Solar Massachusetts Renewable Target Program, co-located energy storage that meets performance requirements receives a $0.045 cent per kWh storage adder. Hawaii encourages community solar to be interconnected with a range of DERs to deliver 85% of the system's output during on-peak times from 5 to 10 pm. In exchange for meeting minimum performance requirements, these facilities can earn a Peaker Credit Rate via a clearing price auction. For states like Hawaii that have high penetrations of renewables, it is critical to develop policies to incentivize dispatchable power at times of peak grid demand and to discourage solar over- production. Additional incentives could be provided for aspects of strategic siting and design, local resiliency, and community empowerment. In coming months, more policy innovation in leading states could provide examples that state regulators and local utility boards can follow.

Why does it matter? Utilities are already acquiring a tremendous amount of storage, largely without the community solar element. In Q1 of 2019, the amount of utility energy storage was 5 times that acquired in Q1 the year before. But the utility’s focus can be narrow. Based on price alone, centralized solar-plus or even batteries disassociated from solar may appear to be the top choice. The aforementioned community-based DER benefits need policy support—at least until more of these benefits are accurately and routinely monetized under regulation. Community solar represents a force to preserve interest in local solar; it has been credited as the major force behind commercial solar growth the past several years. Once regulators and utilities start to work across silos—even if required to do so—they can unleash more value in the synergies associated with community solar-plus.

Today, the cost of large solar projects can often beat the cost of conventional new generation, and a growing number of utilities are making remarkable commitments to buy it—lots of it, and lots of wind power too. About a half-dozen utilities announced goals of 100 percent renewable by 2050 or sooner; a growing number are shooting above 50 percent. Facing climate destruction, we are happy for plans to work big and fast. But we were surprised—maybe even dismayed—by questions that have come up recently, asking if there will still be a need for community solar in light of these coming, big-renewable portfolios.

Of course the answer is yes. While in some locations, community solar is nearing its useful life as a simple wake-up call for utilities to look at solar, that hardly the case everywhere. Moreover, community solar can help take care of particular needs that are daunting for most utilities to serve. And it can add much-needed load management and resilience value to the local system. I may have said this before, but the examples just keep coming—and getting better.

In terms of addressing difficult community needs, the potential for community solar to serve low- to moderate-income customer needs is striking. The opportunity to lock in lower energy prices or to leverage benefits like improved housing options, equity and jobs development for under-served communities can be a game-changer. Check out the winners of the US DOE Solar in Your Community Challenge, just announced. That national multi-year program drew participants from communities nationwide. DOE called out 17 award-winners, which take the familiar model for community solar and adapt it—or reinvent it—to overcome policy, market and economic hurdles. These programs are compatible with increasing renewables in the overall utility portfolio, while drawing out the particular benefits that local, strategic program designs can deliver.

As a side note, buttons are popping at Cliburn and Associates, because we were honored to do training and coaching for the Challenge program. One of the teams we (lightly) coached, SunShares at VEIC in Burlington, VT, received special recognition for innovation.

The days when PV for low-income communities amounted to a photo-op are over. Challenge winners are aimed at replication, scaling up to MW or tens of MW and backed by financing partners ranging from banks, to corporate co-sponsors, to an emerging field of impact investors. One winning project is was submitted by the Kerrville, TX, rural electric cooperative, implementing solar PPAs for four projects on land leased from local nonprofits. The potential for national replication is obvious. While large, centralized renewable energy projects should represent the bulk of utility portfolios in coming years, there is plenty of room for local solar resources that deliver important, though harder-to-monetize benefits.  

That does include solar-plus-storage. The Challenge program saw at least one notable solar-plus design—a project designed for resilience and submitted by the Blue Lake Rancheria, an indigenous community in California.

Solar plus storage, designed for integration value, as well as for community resilience, gets my bet as the most impactful, emerging way to reinvent community solar. We are currently working with Minnesota Power, in collaboration with Grand Rapids, MN, which is one of its wholesale customers. Grand Rapids Public Utilities looked at the benefits of community solar in Northern Minnesota and found it do-able, but not quite compelling—until battery storage was incorporated into the plan. As one of many utilities that pays a high monthly demand charge to its wholesale supplier, as well as a pass-through charge for ISO-coincident demand, Grand Rapids realized it could see significant savings from a solar-plus-storage project, which would—by the way—enable the customer-focused community solar to move forward. That project is awaiting a final go-ahead from local decision makers, but it is targeted for implementation in 2020.

Though it would be a trailblazer, the Minnesota Power project with Grand Rapids would not be the first community solar plus project in the US. We know of several community solar projects that use storage and more that are underway. Usually the storage is a utility-provided companion that “sweetens” a customer-supported solar project. One early example that approached this model was completed by Austin Energy a few years ago. Another, following a model very similar to the one proposed for Grand Rapids, is fully subscribed and saving hundreds of thousands of dollars in demand charges at the Sterling, MA, municipal utility.

We spoke at the Peak Load Management Alliance Conference in Minneapolis this week, addressing not only the option of solar-plus battery storage, but also the opportunity for community solar to pair up with other, customer-side load management strategies. We considered the easy case—for a locally controlled utility—and the challenges of doing that in a market where legislation requires community solar to be administered by a non-utility entity. In the latter case (envisioned in proposed community solar legislation for New Mexico among other places), the community solar developer might receive some incentive to work with the utility, in the interest of co-locating a battery with the community solar project.

The opportunities for transforming solar kWh from “plain vanilla” to “Cherry Garcia” (or whatever your favorite premium-value flavor might be!) are emerging fast. The benefits are technically appealing and appealing to customers, who remain at the very center of any effort to decarbonize and sustain reliable, 21st Century electric service.

by Jill Cliburn

Our continuing work in development, policy and program design for high-value solar has kept us in touch with the questions from utility planners. As the longstanding solar investment tax credit (ITC) begins to wane and solar-plus-storage policies waver, we find that questions about timing are top of mind. If you didn’t start your solar-plus project already, can you make it work with next year’s lower ITC? Or, should you wait to see if storage-only tax credits take shape in Congress? If successful, a storage-only tax credit could add flexibility for charging from the grid and eliminating the need for solar and storage to advance together, like awkward cousins in a three-legged race.

As we look into the CSVP crystal ball, we see clear indications for this answer: Start now with a good project concept, and it can only get better.

The step-down schedule for the solar and solar-plus-storage ITC is widely known. Projects that are legitimately under construction by year-end 2019 will receive the 30% ITC, which has been in place since its last extension in 2016. Projects under construction in 2020 suffer a 4% drop in the ITC, with another 4% drop in 2021, followed by a return to the standard 10% commercial investment tax credit.

For solar-plus-storage projects, the IRS has provided additional guidelines, outlined in this factsheet from the National Renewable Energy Lab (NREL). Remember that, in some cases, a Modified Accelerated Cost Recovery System (MACRS) depreciation deduction may apply, as well, adding to the total project benefit. A co-located solar-plus project must charge the battery with solar at least 75% of the time, while the tax credits are paying off, in order to qualify; in some locations that is tricky. But anxious utility managers may find solace in a simple formula that predicts how much of the tax credit would apply with success on a yearly basis ranging from 75 to 99.9%.

In short, the solar-plus-storage ITC is a good thing. Starting a project now reduces your chances of leaving ITC and MACRS money on the table. For the many utilities that cannot take advantage of tax incentives directly, either because they are non-taxable or because of state normalization rules, your first step may be to explore financing options that let you take advantage of these benefits through development partnerships. The simplest of these is a Power Purchase Agreement (PPA), which has a long track record on the solar side. On the storage side, an Energy Storage Service Agreement (ESSA) is the likely instrument. Similar in some ways to a service lease, the ESSA may target one or more use cases and give the provider some leeway in how to meet your bottom-line needs. See CSVP resources on financing and  early-stage storage planning.

It is a common mistake to focus on incentives instead of on bottom-line needs. Utilities and stakeholders alike may have a hard time seeing deep inside storage and solar-plus-storage business models, but the best providers rely on a team of market-watchers and risk-managers to figure out how a kaleidoscope of changing technologies, supplier-pipeline conditions, policies and investor requirements affect the bottom-line project offer. During the RFP process, it is crucial to assess each potential provider’s business record and technical qualifications. When stuff happens—and it usually does—you want to know your developer can rework parts of the plan, to achieve your key goals.

To give this discussion some context, my colleague John Powers, from Extensible Energy, ran a hypothetical project analysis, illustrated above. Assuming a utility that could use storage to avoid high peak demand costs from its wholesale supplier, the benefits of storage are considerable. We used a simple Benefit-to-Cost ratio to compare the impacts of different scenarios on 25-year project cost-effectiveness. Our Base Case called for solar plus storage at a combined price of $60/MWH. (This is not Hawaii!) Without the storage, a solar-only case looks weak. But all the scenarios with batteries show impressive cost-effectiveness. Losing 4% on tax incentives will cost projects a significant amount of money, but that is by no means a deal-breaker. Perhaps more important is a careful procurement process and ESSA negotiation, providing some flexibility to address inevitable changes in markets and technologies over the long haul.

Should you be tempted to wait for the storage-only incentives that Congress began to consider last fall? In late March 2019, three new, bi-partisan energy storage bills were introduced in Congress, according to Utility Dive. One would amend the Public Utility Regulatory Policies Act (PURPA) to include energy storage. Another assures that more storage projects would be eligible for loan guarantees, and a third increases federal support, primarily for energy storage R&D. Tax incentives for storage currently are not on the table, though some utilities might snag new grant of loan funding.

Utilities may turn attention to storage market developments that continue to drive price declines. According to a report from Bloomberg New Energy Finance, lithium-ion battery storage costs have declined 76% since 2012. Other sources, including Wood Mackenzie GTM, note that the stunning annual price reductions seen five years ago have subsided, but storage prices continue to decline at a more sustainable rate—around 5 to 10% year on year, including reductions in pricing for both battery technologies and balance of system components—not to mention continuing solar-price reductions. Clearly, there are more ways to reach a bottom-line target than to take a laser-focus on the ITC.

Any number of crazy things could happen to steer a solar-plus project off course. Supply-chain disruptions are characteristic of emerging markets. Who knows how the tariff story will play out? Who knows how mergers and acquisitions in this market may affect a particular project? And who knows if something as weird as the weather could wreck havoc on your solar-plus plans?

But most signs point to the emergence of a solid storage industry and to continued growth in renewables—especially solar. In an effort to meet rising renewable-energy targets nationwide, utilities have to get down to what CSVP has called the “market-based laboratory,” to learn how to add value to solar and storage and to meet customer needs in a fast-changing market. An extension of the solar-plus ITC or emergence of more storage-only incentives may come, as a ways to speed the utility energy transformation along, but the impact of any one market condition upon this industry is neither predictable enough nor impactful enough to stop a good project plan from moving ahead.

  By Jill Cliburn

In recent months, I’ve had the pleasure of working boots-on-the-ground, planning for a new, MW-scale community solar-plus-storage project. It is too soon to share all the details, but Cliburn and Associates has led program-design and early-stage procurement efforts, with Extensible Energy adding tech expertise.

The utility understood its value proposition—based mostly on wholesale demand reduction—from the start. The community stakeholders also understood their value proposition, and in fact, they drove the project early on. However, we recognized that the facets of project value differ quite a lot from each perspective. We’ve fostered a good dialog, which increased understanding—and enthusiasm—on all sides. Here, I thought I would share a little more about why and how this kind of communication matters in designing community solar-plus projects—or any innovations that are part of the grid-edge revolution.

A new JD Power 2019 Utility Industry Outlook, gives several clues about why good communications matter, when you're introducing 21st-Century changes that are roundly considered smart for the long-run, but that are new, nonetheless. For example, JD Power’s latest research found that the introduction of Time of Use rates (and presumably other load-management rates) can erode customer satisfaction—but that depends on how rate changes are presented. “When these programs are implemented as part of a broader environmental initiative, complete with proactive communications (and risk-reducing measures)… customer satisfaction can actually improve,” the report found. This comes as no surprise to us at CSVP. We have long held that utilities need to engage customers directly in inventing the utility of the future. And it’s hard to find an easier opener than community solar. Community solar, implemented with TOU rates or offered with DR companion measures, doesn’t just tell customers how these elements work cost-effectively together; it demonstrates results. And it does that under voluntary conditions.

Of course, a conversation goes both ways, and community solar is also an opener for customers to express their values, explaining what "solar choice," broadening solar access, sharing benefits and achieving environmental sustainability mean to them. To be successful, a community solar offer has to address a good number of these customer concerns. The process for developing high-value community solar can build respect—and enthusiasm—on all sides. We know this is true, because we have seen it happen.

This approach, using community solar as the conversation opener and using it (as we like to say) as a market based laboratory, harmonizes with other findings from the JD Power Outlook for 2019. The report notes that customers are increasingly likely to say that their utility’s commitment to the community is a “strong driver” for their satisfaction. This could involve seeing utility folks at any number of community events or noticing that the utility supports a good cause. But guess what? Community solar is a good cause. That same JD Power report notes that 43% of electric utility customers now say they are considering solar power—and that “the biggest obstacle to adoption among the 57% who aren’t interested is cost.” Community solar is widely recognized as a solution for customers who find solar attractive, but too costly or unsuitable for their homes.

So here’s my suggestion: if you are a utility, get involved in a high-value community solar project, whether that includes strategic solar-plus-storage and companion measures or high-value solar siting and design, or special appeals for lower-income customers and other target markets. Then open up the conversation. How many other opportunities do you think you will have to explain to customers and stakeholders what a demand charge is, or how the value of resources is affected by market conditions in your region? How many other opportunities do you think you will have to hear customers express how they care about future energy choices, while they look to the utility as less of the problem and more the solution? A dialog can be a fragile thing, because it requires the maintenance of trust. But in my own experience, working on community solar across the U.S., I’ve come to understand that community solar presents a real opportunity for the elusive utility/stakeholder win-win. The value of an extended and positive exchange about community solar is, as we say, non-monetizable, and… priceless.

For more about how to set up a good communications process around community solar, see the Process section of our Solutions toolbox. If you think that begins with getting top-level approval, you may be right, but we have some resources in the toolbox to help you with that, too. Or if you would like specific or general assistance planning your community solar effort, please send a note via our Contact page.

by Jill Cliburn

It’s fair to say that the CSVP was a pioneer in utility-led solar plus DR and storage strategies. Drawing on experience in IRP, renewables and a range of DERs, members of our core team have been working around the edges of solar-plus since the early aughts. Soon after the U.S. DOE SunShot program selected CSVP to carry that work forward, we produced a guide to Demand-Response Companion Measures for High-Value Community Solar Programs. Published in 2016, it’s still a popular planning tool. We also worked with utilities on using various forms of storage, including batteries, and we published a guide to Solar Plus Storage Companion Measures for High-Value Community Solar Programs, last year.

But enough with the self-congratulations! For all we got right, we missed just how fast batteries in particular would take off and exactly how pivotal their role would be. For our recent utility and commercial clients, we’re updating our work on battery economics and opportunities. Here, I thought I’d share some insights on how these market changes apply to high-value community solar strategies today.

The recent Wood Mackenzie/GTM Research Vision Study of Community Solar, commissioned by Vote Solar, embraces the potential for community solar plus storage, DR and other companion measures. However, that study sees such measures coming with a “maturing” community solar market, a decade or more into the future:

But at CSVP, we’ve talked about storage, DR and energy efficiency as “companion measures” that engage utility customers and accelerate development of the 21st Century grid, starting now. GTM foresees the right services and opportunities, but apparently as part of an orderly transformation, resulting in 60 to 80+ GW of community solar by 2030. I would suggest that unless community solar providers and supporters embrace solar-plus as a disorderly and disruptive force, then the community solar sector could be left behind.

Recently, Utility Dive featured an op-ed on this theme, describing a growing number of demonstrations and new use cases for community storage—primarily batteries. Community storage may apply to utility or third-party programs that provide storage for a cluster of customer loads, whether or not associated with a specific solar project. The range of possibilities is geographically and conceptually broad. But it is easy to see the solar connection here, too—established in part because the ITC tax incentives for batteries apply only when batteries are co-located with solar generation. Austin Energy, a public power leader, launched its community solar program with co-located battery storage in 2017, and today the list of similar projects nationwide is long and growing.

For example, Connexus Energy, a large electric co-op in Minnesota, recently announced plans for a 20 MW, 40 MWh storage system, to be co-located with 10 MW of solar. We like a smaller, new project at United Power in Colorado, where I worked with in-house visionary Jerry Marizza on community solar nearly a decade ago. Now United has launched a similar shared storage program for commercial and industrial customers, for whom the energy-only offsets of most community solar programs would fail to address significant C&I demand charges. Neither of these are community solar-plus programs, but they remind us of what's coming.

Why would a community solar vision, like GTM’s or others, see solar-plus developments as far-off? First, if the vision were focused on modifying the business models of established community solar providers, then the move to community solar plus storage might be delayed until the low-hanging community solar fruit were well-picked. Utilities and some state policy makers see this evolution differently. Anxious to preview the battery market, they are looking past community solar providers, to work with developers that focus on battery services or solar-plus-batteries as their main line. (See a reasonably good explanation of market developments in a new EIA report.) If community solar providers come late to this party, will utilities pursue local battery projects without community solar, or will they fill in community solar blanks on their own, with the help of task-specific contractors instead of focused community solar providers?

Either way, the message is that a disruptive market waits for no one. The market researchers who’ve worked on the community solar vision may not have noticed how quickly solar plus storage is becoming commonplace—perhaps even becoming the most prevalent way to develop solar on the grid.

The market researchers who’ve worked on the community solar vision may not have noticed how quickly solar plus battery storage is becoming commonplace—perhaps even becoming the most prevalent way to develop solar on the grid.

Secondly, there is an important dimension to these new battery service providers’ approach, which confounds community solar providers, who have relied on fairly straightforward models. The fact is, battery service providers and solar PPA providers who offer solar-plus are cramming together two very different types of offers, coming up with creative, but very complicated, solar-plus deals.

We would need more than one blog to explain how battery service providers are arranging and pricing their deals. And frankly, we’re still decoding some aspects of these mostly-proprietary deals. But it’s key to remember that solar plus battery services are not the same as buying an energy-only solar PPA, and it’s not the same as buying storage hardware. For example, that GTM and Bloomberg cite operating costs for lithium-ion battery storage plummeting from $1000/kWh in 2010 to a low of $210/kWh in 2017 (inching back up slightly this year). But what do these numbers that mean? The economics that matter depend on how many discharges from what sized battery, for how long, over what time-frame—and whether the battery might be used for demand reduction alone or in addition, for other arbitrage and integration services. In addition, the offer would have to factor in O&M and decommissioning or refurbishing or replacing the battery after about 10 years time, whereas a solar plant is likely to last, with relatively modest degradation, for 30 years or more.

We have a few economic benchmarks for utilities that have purchased batteries, such as the municipal utility in Sterling, Massachusetts and the community solar plus storage project at the Fayetteville Public Works Commission in North Carolina. However, the financing on each of these projects was relatively unique—with Fayetteville self-financing and Sterling using grant funding and incentives.

For most utilities, the more appealing approach would be akin to the PPA. Drawing on publicly available numbers from larger (regulatory-reviewed) solar-plus acquisitions, the median bid price on a Colorado Xcel Energy RFP for combined solar plus storage reviewed late last year came in at $36/MWh. That was way better than Tucson Electric Power’s already-low solar plus storage deal announced just a few months earlier, at $45/MWh. Then, regulators in Nevada shared results of solar-plus storage procurements in that state, coming in around $30/MWh. In practice there is little relationship between the dollars per kWh metric for battery costs or the standard solar PPA metric (traditionally, the LCOE) and these solar-plus PPA prices.

Smaller projects often use a solar PPA plus a separate battery services agreement. But the economics for these deals still striking. Several public power utility managers, who have ongoing solar-plus negotiations, have confided to me that they’ve seen darned good economics on pretty modest solar-plus deals. They cite their fairly limited storage service needs, and the options that battery services providers may keep to sell battery services on the market for other integration services—or even resiliency. It is certainly possible that a rush for solar-plus market share is adding temporary downward pressure.

As it stands, one can guesstimate solar-plus economics for a given project, in order to get through the first gate for a go/no-go decision. But it’s likely that utilities today would be smart to tap expert support at the planning and RFP-development stage, if they wish to produce a basket of informative, competitive bids that look even remotely like apples to apples.

While the market is still maturing, I hope  community solar supporters won’t let the market’s current complexity mask the opportunities to act now—especially where local utilities can play a lead coordination role. I do not know how much today’s still-falling solar prices might rise, once current tariffs take hold and kinks in the supply chain work out. Nor could I guess the impact of weakening ITC-related benefits, starting in 2020. But the strength of community solar still relies largely on the idea that communities of people working together can help to move the industry forward. Battery storage strategies do not belong behind a dark curtain. They will evolve faster and better (as a triple-win for providers, utilities and their customers at large) if their business models see the sunlight uniquely associated with community solar. The community solar industry has just scratched the surface of what innovative program designers, working with technical engineers, creative financiers and visionary community leaders can achieve.

by Jill Cliburn

A year ago, CSVP held a Utility Forum Workshop in Golden, Colorado, where we talked about clean electrification—using electric devices, equipment and vehicles as a “sink and source” for energy to help balance renewables on the utility grid. The idea was a good fit for CSVP, as co-marketing such products with community solar increases the chance to have a win-win conversation with customers. Most customers are already interested in solar, but they may never have thought about the need to balance the grid. Our Workshop in Golden was a memorable introduction for dozens of utilities and stakeholders in attendance.

But a year later? Holy cow! The idea of clean electrification has taken off in utility talking circles, and there is a great deal of research going on to attack the technical details. For one example, you can catch John Powers and myself, with a dozen other thought leaders on the Clean Electrification Track at the American Solar Energy Society (ASES) Solar 2018 Conference in Boulder, August 6-8. Seriously, you should come—but here’s a preview.

The standard crystal ball for clean electrification is provided by EPRI. Its latest assessment, released in April 2018, looks out to 2050, anticipating growth in electricity’s share of total final energy use, from 21% today to between 32 and 47% in 2050. Four scenarios take different views of electricity sector growth, including electric vehicles, commercial and industrial technologies, and a tremendous shift in residential energy use. The most optimistic EPRI scenario would drive a decrease in U.S. carbon emissions by almost 70% by 2050.

While EPRI predicts greater use of natural gas in a clean electrification future, other researchers, as well as activist cities, see advanced "solar-plus" integration strategies and customer involvement as ways to push for even greater emissions reductions.

But even EPRI’s most aggressive scenario is not as impressive as some promoted by cities that are aiming to be “100% renewable” by 2050. Most of these cities have signed on to organized programs, such as Sierra Club’s Ready for 100 Campaign and the Mayors for 100% Clean Energy Campaign or the foundation-funded, international Renewable Cities program. For example, Vancouver, BC, already gets 98% of its electricity from renewable sources—mostly hydro with some wind and biomass – and just 2% from gas. Cities like Boulder are pushing hard for fuel-switching to get customers off natural gas for heating and cooling and aggressively promoting electrified transportation, along with solar and energy efficiency. (Note, Boulder is also on the program at Solar 2018.) The Sierra Club counts at least 65 U.S. cities committed to a 100% renewable energy goal.

Utilities are right to worry about this grassroots drive for high-penetration renewables. The Community Choice Aggregation (CCA) movement has cities in at least seven states (CA, IL, OH, MA, NJ, NY and RI) choosing wholesale energy contracts—and mostly green energy contracts—on behalf of their citizens. This creates more bottom-up pressure for renewables in the wholesale energy market, and that in turn creates greater urgency to get grid integration for renewables right.

This is a clear case of a threat that is also an opportunity. If utilities rise to the challenge of clean electrification, including increasing use of wholesale and locally-produced solar, then this could be a cure for the looming decline of the utility industry. The Brattle Group, which produced some seminal work in this field, has a new report that foresees electric utility sales growth rising to 2% per year on average, more than three times the current projections of annual growth rates of less than 0.6%, or essentially zip, per year.

At first this forecast may call to mind an image of the utility as the “old man,” called back into the game. But that is not the case. Utilities—and especially local distribution utilities—will only get into this game if they engage actively and well with their customers. That is, because their customers also happen to be voters, who can influence related policies and research. For me, with more than three years of CSVP work at my back, I’m more enthusiastic than ever about the ability of community solar to open this conversatoin with customers.

In fact, I’m heading to Grand Rapids, Minnesota, this month, to work with a group of smart and creative customers and their (also pretty darned sharp) municipal utility leaders on a high-value community solar program plan. I’m excited to see this and more examples of utilities and customers working together to ask the hard questions about, How do we maximize use of renewable energy? And, How do we bring other technologies on both sides of the meter, into the puzzle, to ease and speed this dramatic transition?

At risk of repeating myself, let me shamelessly pitch ASES Solar 2018 again, where I’ve been working with John Powers, the City of Boulder, NREL folks, and many third-party technology and service providers, to produce panels on clean electrification and community solar, which constitute an affordable mini-conference of their own on Monday, August 6.

by Jill Cliburn

It’s been a decade now since community solar grabbed the imaginations of a handful of forward-leaning utilities and solar entrepreneurs, and the results have been impressive—the market about doubled last year, and has topped 1 GW by now. But these results are still not as great as they could be. At CSVP, we were quoted on this in a recent article by Herman Trabish in Utility Dive. Here, I’ll share a little more of from our last check-in with the crystal ball.
 
Our gaze at the future is influenced, of course, by our experience in the past. There had been a few community solar projects before 2008, but in that year, the Sacramento Municipal Utility District (SMUD) announced its SolarShares, rate-based program, supported by a 1-MW utility-owned solar plant. Hopes for community solar soared. Also at that time, United Power, a co-op in the Denver suburbs, developed a plan for an upfront lease for participants in a third-party-financed CS program, called Sol Partners. I was part of that team, as a consultant to the Cooperative Research Network. We ran the numbers and checked and double-checked how the lease would work. The plan was replicable, we were convinced and co-ops nationwide began to notice. I’m not even sure if Holy Cross, another Colorado co-op, took lessons directly from United Power, but its came up with their buy-a-panel model and launched in 2010, working with a company that would become CEC—today’s community solar market leader. At the time, if felt like the discovery the North Pole or of DNA; it was bound to happen, and just a matter of who would get there first.
 
By 2015, pundits were talking about a GW-per year community solar market. Some simply counted residential rooftops on rentals and shade-covered neighborhoods, assuming that would define the market. At CSVP, we took a different view, building off early market date from SMUD and other utility programs, and then from Shelton Group, which was working with SEPA. There is evidence that the market for community solar includes lots of people who could use their own rooftops, but prefer not to. The question of how the community solar market would grow had more to do with program design than mere eligibility. True that.
 
So now, I was quoted in Utility Dive: “If policymakers get it right, community solar could rival the rooftop solar market within a decade. But that’s a big if.”
 
And there’s the rub. The early excitement sparked by a few progressive utility programs has led to greater innovations and bigger markets in states and utility territories where policymakers, utilities and advocates have learned to work well together. Yet in many places, that spark of excitement has led to a firestorm of debate. Can anyone set up one community solar policy and development model that works for everyone? I don’t think so.
 
Utility-led community solar—especially among investor-owned utilities—has been bogged down by a perceived risk of regulation. Will the regulators approve a program plan, or will it be undermined by a broader, emerging state policy? Regulatory risk is a big drag on utility programs. We encourage utilities to take the lead, anyway. Utilities that are proactive and collaborative always come out better in the end, even if they have to modify their plans along the way.
 
Second, community solar has been bogged down by a tendency among policymakers—and in turn, utilities—to shoehorn every possible benefit in one program offer. That takes a long time, and it seldom works. By contrast, we’ve advocated for larger utilities to build multiple local community solar projects within a program portfolio, with offers for targeted groups of customers. That model is not terribly different from the state-administered programs that let customers, working with private developers, bring tailored projects to the utility. I would like to see more policies that encourage developers and utilities to aggregate projects and build greater economies of scale within program portfolios. We introduced the portfolio approach as part of the CSVP program-design process, and we also recommend Rocky Mountain Institute’s Shine Program, which has demonstrated a similar process in the field.
 
At CSVP, we consider our primary audience to be utilities, because no matter how the regulators (or COU policy boards) structure a program, the utility is going to be involved. Moreover, there is a lot of value on the utility side of the solar-value equation. But remember, that does not mean the utility must be the only driver for community solar. We’re proud to be part of building better relationships between utilities and solar service providers. The result has been better choices at every stage of program design and implementation. The impacts, in terms of speeding the process, are just beginning to be felt.
 
Will this support a sustained year-on-year doubling of the community solar market? I don’t know. But I’m guessing that from where you sit, that’s a crystal-ball question that doesn’t matter as much as the question you hear on the streets of your own community: “Do you think we could do some (or more) community solar here?”