News Article | November 23, 2016
We all have to wait in lines, from the bank to the grocery store to the airport. And we’ve all experienced frustration when people ahead of us aren’t paying attention. They don’t have their payment ready to cash out, or they can't find their ID and boarding pass for the security check point. So they slow things down for everyone else. But as some of these processes become more automated and streamlined, it’s beginning to save us time and energy. We can now deposit checks from our phone, or order food online for delivery to our doorstep. Nonetheless, lines remain a reality in modern life, and sometimes the best we can hope for is just knowing how long it’s going to take. In many ways, the interconnection queue is like any other line. It allows utilities to process interconnection applications in a fair and orderly manner -- first-come, first-served. And it is also susceptible to delays at many “check points” throughout the process, which can slow things down in unpredictable ways for every project. Sometimes the effects are minor and inconsequential. However, some delays, such as late interconnection study results or construction bottlenecks, can translate to big costs for project applicants and impact their ability to obtain financing. In our regulatory work in states across the country, the Interstate Renewable Energy Council (IREC) often sees timelines and “queue management” issues come up in times of crisis, when a utility’s interconnection queue has become backlogged, and applicants and customers complain. For example, after implementing ambitious shared solar programs, both Minnesota and New York saw their utilities’ interconnection processes under considerable stress, resulting in major delays. In part, this is due to the sheer number of applications coming in the door. However, it also reflects the shortfalls of both states’ now-outdated interconnection procedures, which lack, among other best-practice elements, clear timelines for each step in the process, for both applicants and utilities, and clear enforcement mechanisms for when those timelines are missed. Not only can timelines help keep the line moving forward, but they can also set expectations for utilities and applicants, and minimize disputes. In addition, when applicants have a clearer sense of timelines, they can more effectively communicate these expectations to their customers, including rooftop solar customers and shared solar subscribers. Fortunately, as discussed in the first blog post in our series, existing models make the adoption of straightforward, appropriate timelines relatively easy. Even in these model procedures, however, there are still timeline gaps that require more attention, especially after an interconnection agreement has been signed. At this point, larger facilities requiring distribution system upgrades enter a construction phase, usually managed by the utility. Construction timelines are typically developed on a project-by-project basis and included in the interconnection agreement (not the procedures); they may be vague and there aren’t necessarily penalties for missing them. Delays in the construction process can have big impacts on projects working toward a specific operational deadline, when they expect to be generating electricity and earning money. There is not an easy solution here. In reality, projects may require different construction timelines because of their particular design, location and other factors. In our proposed revisions to Minnesota’s interconnection procedures, IREC and our partners attempted to reconcile this need for individual treatment with a desire for increased clarity and transparency regarding construction timelines within the interconnection procedures. We included specific provisions regarding utility-applicant agreement on construction milestones and timelines based on industry best practices. We also added timelines for payment and final accounting of the cost associated with necessary upgrades. This remains a cutting-edge issue that will require attention in all states pursuing interconnection reform. (Paying for these upgrades gets into issues of cost certainty and allocation, which IREC will address in future blogs in this series.) Ultimately, one of the most important steps in the interconnection process for all projects is the very last one: receiving permission to operate, or PTO, after a system is installed and all other steps have been completed. Whether a project is big or small, whether or not upgrades are required, stakeholders involved in every project eagerly await the moment it can go on-line and begin generating electricity and revenue. As a recent EQ Research report shows, however, many states’ procedures do not include a PTO timeline. What’s more, the report reveals that rooftop solar customers were forced to wait an average of 45 days after construction was completed to receive utility permission to operate the system, compared to 28 days in 2014. These results follow a trend identified in the 2015 edition of the report, which found that the wait for PTO increased in 2014 as compared to 2013. It’s clear then, that as more systems are seeking to connect to the grid, processes are either stagnating or slowing down. While some of this might be due to overloaded utility staff forced to process higher volumes of requests, the trend suggests that more can and should be done to streamline and expedite the process. For example, at the end of the process, a lack of any enforceable deadlines for final testing and approval can leave customers frustrated, with a system installed but unable to be turned on, and with no recourse to push for a response at the utility. In this case, the first step toward a solution is simple: incorporate a PTO timeline into interconnection procedures. While timelines are important, applicants and utilities can have legitimate reasons for missing them, sometimes due to circumstances outside of their control. Thus it is equally important that interconnection procedures include policies for extending timelines in appropriate circumstances. Some states accomplish this by clarifying extensions for each timeline, as necessary. For the sake of consistency, however, it may make sense to have a blanket policy applicable to all timelines, and to note any exceptions to this rule on a case-by-case basis within the procedures. Either way, clear rules about when extensions are allowed are also crucial to a smooth interconnection process. Even with explicit timelines and a defined extension process, applicants and utilities will inevitably miss some deadlines. A good enforcement process can both discourage this behavior and also lay out a procedure for dealing with it when it happens. On the applicant side, enforcement ultimately means getting kicked out of the queue and, if necessary, having to reapply and start at the beginning. On the utility side, best practices are just emerging to help regulators incentivize and penalize utilities with respect to interconnection timeline compliance. How do you get people to do what they’re supposed to do? And how do you kick them out of line if they don’t? We'll explore this in a future piece as part of this interconnection series. Erica McConnell is special counsel with Shute, Mihaly and Weinberger, attorneys for the Interstate Renewable Energy Council.
News Article | August 22, 2016
As you read this, I am in my first month as the new president and CEO of IREC. Wow! What a privilege and honor it is to lead this great organization as we continue to work for a clean energy future.
News Article | January 27, 2016
How easy is it to go solar in your state? A new “report card” by the Interstate Renewable Energy Council (IREC) and Vote Solar grades all 50 U.S. states on two important criteria for solar development: interconnection standards and net-metering policies. Now in its 9th year, the report card shows that some states are making progress, raising their grades from, for example, a “C” to an “A” by enacting simplified interconnection rules or lifting net-metering caps. On the other hand some states are falling behind. The “Interconnection Procedure Grade” is based on the rules and processes that energy customers must follow to be able to 'plug' their renewable energy systems into the electricity grid. Five states - Hawaii, Illinois, Mississippi, New Hampshire and North Carolina - improved their interconnection grades in 2015. Only one, North Dakota, received a lower grade. Half of U.S. states have good 'A' or 'B' grades, and the remaining need improvement.
News Article | October 25, 2016
Imagine a state that has enacted all of the policies that the public and clean energy providers have asked for: an aggressive renewable portfolio standard, a robust grid modernization plan, far-reaching shared renewables. The sun is shining, the birds are chirping, people are celebrating and getting ready to build new projects -- perfect, right? Unfortunately, there could be dark clouds on the horizon without the one policy most critical to making everything else work: interconnection. The absence of this crucial policy would cause projects to because mired in a murky technical process, with no end in sight. Does this sound too pessimistic to be real? It’s not. Just ask Minnesota, New York and several other states that have learned the hard way about the importance of interconnection. The power grid is much like our network of country roads, highways and freeways, carrying energy from its origin to its final destination. Interconnection standards are, in effect, the “rules of the road,” set by policymakers, which both system owners and utilities must follow to keep traffic flowing smoothly. The quality of these rules -- like any given street sign, traffic direction or roadmap -- can facilitate an easy free-flow of traffic, or result in maddening, unnecessary gridlock. As we introduce new technologies and services, such as self-driving cars and ride-sharing apps, the rules of the road must evolve. So, too, must interconnection procedures. Drawing from our experience working on the ground with more than 20 states on interconnection reform, the Interstate Renewable Energy Council (IREC) puts forward-thinking, fact-based tools in the hands of stakeholders and decision-makers tackling the challenges of a more distributed electricity grid. In the weeks ahead, we will discuss key emerging issues and critical areas of focus for decision-makers. We will also identify a host of best practices that have not yet been captured in existing interconnection model rules. At a basic level, interconnection standards should outline with clarity all of the timelines, fees, technical requirements and steps in the review process for bringing new systems on-line. Well-designed rules are foundational to healthy renewable energy markets, as they allow utilities to maintain the safety and reliability of the grid, while providing a transparent, efficient and cost-effective experience for customers. Interconnection should not be an obstacle or a source of frustration and contention for any party involved in the process. Clear, forward-thinking rules are essential if we want to achieve our clean energy goals. In 2016, just over half of all states earned either an “A” or “B” grade in Freeing the Grid, a report that IREC and Vote Solar release annually, which tracks developments in interconnection and net metering policies across the country. Approximately 20 percent of states received a “C” or “D” grade for poorly designed rules, and 30 percent got an “F,” having failed to adopt interconnection standards of any kind. But those states that are further behind on interconnection have an advantage: They can look to the examples of pioneering states, such has California, Hawaii and Massachusetts, which have recently adopted strong procedural reforms to improve interconnection. At the national level, the Federal Energy Regulatory Commission (FERC) has also developed a set of standards for small generators and utilities under its jurisdiction. A number of states, such as North Carolina, South Carolina, Ohio, and most recently Illinois, have followed FERC’s lead, incorporating its “fast-track” review process and other best practices into their own interconnection rules. Others, including Minnesota and Iowa, are actively considering similar updates. As an active participant at FERC and in dozens of state commission rulemakings over the past decade, IREC has identified and synthesized the best practices in use across the country in a set of model interconnection procedures that states should consider as they strive to create and refine their own rules. Key practices highlighted in IREC’s model procedures include the use of pre-application reports, updated technical screens, more sophisticated sizing criteria, an improved “supplemental review” process that reduces the need for full study, and more. Even in proactive states, higher volumes of renewable energy projects seeking to connect to the grid in the years ahead could create significant logjams if we do not meaningfully prepare with proactive rules. In some places, they already have. Hawaii, California and Massachusetts were driven to reform their interconnection procedures in response to backlogged interconnection queues and frustrated customers. More recently, North Carolina experienced similar queue delays and took a hard look at its procedures. These states’ procedures and IREC’s model rules already capture some lessons learned -- but not all of them. In this article series, we will look at cutting-edge interconnection issues, and wherever possible, identify innovative solutions being implemented across the United States. In this series, IREC will answer some of the most critical questions facing our collective clean energy future: Up next in the series: how clear timelines can make or break the interconnection process, and where applicants and utilities still get stuck today. Erica McConnell is special counsel and Cathy Malina is an environmental law fellow with Shute, Mihaly and Weinberger LLP, attorneys for the Interstate Renewable Energy Council.
News Article | March 14, 2016
Nearly one-third of American adults live in a low- or lower-middle-cost housing area. And that number is growing as the middle class shrinks. Meanwhile, community solar programs are budding around the country. These programs are often promoted as a way to spread solar to those who can't host a system on their roof. But are they reaching lower-income customers who may want to participate? So far, very few programs specifically target this customer segment. And without a focused plan, lower-income customers won't get served by community solar. The Interstate Renewable Energy Council (IREC) is out with a new report that centers on spreading shared solar programs to a broader range of customers. What’s needed is a targeted approach -- borrowing successful approaches in other sectors -- that takes into account the specific challenges of serving the lower-and moderate-income (LMI) demographic. “Shared renewables are still a nascent market, and it’s now entering the next phase of growth,” said Sara Baldwin Auck, IREC’s regulatory program director. “The potential to reach a significant volume of customers is very real. That reality is spurring more people to figure out how to make programs work for LMI customers.” Financing is a central issue. Low-income residents often don’t have access to the financial resources to pay upfront costs or make monthly payments. Paying for renewable energy isn’t a priority. With a sizable risk of default or low enrollment, developers and financiers may be wary of investing in a project on their own to service these customers. One recommendation, which addresses both financing and programmatic hurdles, involves broadening the user pool. "For shared renewable energy facilities focused on serving LMI customers, developers may need to rely on another customer or group of customers to serve as 'anchor' participants in a facility, who can also serve to mitigate some of the credit and other financial issues faced by LMI customers," writes IREC. A shared solar program could include 40 percent of customers from the commercial and industrial sector, or a similar number of homeowners in the moderate- to upper-income bracket. These two groups bring better credit and payment histories, thus reducing risk. For example, the first phase of New York's community solar program requires 20 percent of customers to be low-income. That next step would be to create shared solar programs with more than half of participants in the LMI bracket. "The viability of a 60% LMI facility is inextricably tied to financing issues, however, and IREC emphasizes that these percentages will need to be adjusted on a program-by-program basis, depending on available incentives, financing tools and mechanisms, and other specific circumstances," concludes the report. Those financing tools include upfront incentives and loan programs to help customers defray costs. Developers and financiers may also require help, particularly if a majority of the subscribers are LMI earners. Incentives, tax breaks, and loan-loss reserve accounts to cover shortfalls could be used to encourage an expansion of the customer base. Another possibility is getting states to offer more attractive loans and interest rates. New York's green bank has awarded tens of millions of dollars in loans to companies offering low- to no-cost efficiency and solar options to homeowners in the state. These loans have encouraged banks to throw in many more millions for warehouse credit facilities to support projects serving this sector. "While the current project pipeline does not include any projects devoted to shared renewable energy facilities for LMI customers, the NY Green Bank could foreseeably serve as a source of capital for an LMI-serving shared renewable energy facility," writes IREC. Targeted incentives and loans are necessary to alleviate investor concerns. “If you don’t address the risk and offer creative financing mechanisms, you’re not likely to see this market segment scale,” Auck said. Outreach and marketing need to be taken into account as well. For many LMI customers, language, internet access and time are constraints. The combination of such factors can lead to a lack of awareness and understanding of programming options. They also feed into a skepticism about new offerings. "LMI customers may require specialized, culturally sensitive marketing, education, and outreach, both as far as the method used (e.g., language, medium, etc.) as well as the substance of the materials." In order to address this barrier, policymakers and regulators could design programs that leverage organizations and networks that already work with LMI residents. Partnering with an organization already working in the sector would engender trust. It would also cut down on inefficiencies in staffing and deploying marketing resources -- developers wouldn’t have to worry as much about administrative costs. Finally, partnerships would make participation less onerous. If a customer were deemed eligible through one assistance program, they could be deemed eligible for a shared solar program. The policy and financing suggestions made in the report already exist today. They just need to be applied to community solar, said Auck. “Many of the concepts and mechanisms are already in place and have been demonstrated to work,” she said. “The thing that’s needed is for policymakers and stakeholders to work together to coordinate those pieces. There isn’t the need to reinvent every wheel.”
News Article | August 22, 2016
Interconnecting to the grid is one of the key hurdles for renewable energy project development. The process can be lengthy, expensive and irksome. Some projects take three or more years to get interconnected, with a price tag of millions of dollars, and it is because of these difficulties that there has been a renewed focus around the country on reforming the interconnection process. California just enacted a new set of streamlining tools for interconnection that may well become a model for the rest of the country. As is often the case on energy policy, as goes California, so goes the country. This article will look at what reforms were enacted and how we got here. I represented the Clean Coalition in the regulatory process that led to these reforms over the last six years, working alongside the Clean Coalition’s director of policy Sahm White, so I’ve had a first-hand and direct role in this process throughout these years as we submitted round after round of comments, attended settlement talks and numerous workshops, and did our best to persuade decision-makers in various ex parte meetings I’m going to describe what was done in the recent reforms and offer some lessons learned in terms of how to be effective in promoting regulatory reform. This article can be considered a modest case study, then, in effective regulatory reform. The California Public Utilities Commission opened a proceeding in 2011 (R.11-09-011) to consider reforms to the state-jurisdictional interconnection procedure known as Rule 21. Rule 21 codifies the rules that each utility and customer seeking to interconnect must follow for interconnecting new projects to the utility-owned and -operated distribution grid. The proceeding quickly resulted in a settlement of some key issues between the parties (the big utilities and various intervenors representing consumers, project developers, and environmental interests), and the Phase 1 settlement was approved by the CPUC in 2012. A key issue, “cost certainty,” was left out of the settlement, however, and scoped for resolution in a second phase of the proceeding. Cost certainty refers to the need to know with more certainty what it will cost a project developer (solar, biomass, wind, etc.) to interconnect to the grid. Until the new reforms were enacted, a project developer could be on the hook at any point after interconnection upgrades were completed for unspecified and potentially very large additional interconnection costs. By enacting new measures to provide additional cost certainty for project developers, these developers could save on financing and insurance costs, and the savings would be passed on to ratepayers. The second phase was supposed to be expedited -- but little did we know back in 2012 that it would take four more years to resolve these issues. One lesson learned: regulatory reform usually takes a lot longer than you expect or hope that it should. In this case, there were a couple of major staff changes that slowed things down considerably. The recent CPUC decision (D.16-06-052) included an enhanced preapplication report (PAR) request process, which allows developers to request additional information, for an additional fee, over and above what was previously available. Mostly useful for large net-metered solar systems, the enhanced PAR should provide project developers a great way to identify likely costs and potential issues with their project without spending $15,000 or so on a fast-track application and having to wait six months for the results. The costs for a PAR now vary from $300 to $800 depending on the options selected. The same decision also enacted a new unit cost guide that will describe the normal component costs for the most common interconnection configurations for solar or other renewable energy projects. While not binding on the utility, the new unit cost guide should provide very useful information about possible costs for common project configurations. It will also be updated each year. The Clean Coalition proposed this new unit cost guide way back in 2011, and it is gratifying to see it finally come to fruition. Perhaps the most important reform to come out of the recent decision, however, was the new “cost envelope” option for interconnection studies. The envelope refers to the option to receive a binding cost estimate rather than a rough and potentially changing estimate of interconnection costs for a specific project. The cost envelope provides a plus or minus 25 percent binding cost estimate. That is, the developer will be on the hook only for a maximum of 125 percent of the interconnection cost estimate, and the actual costs may come in up to 25 percent lower than the estimate. Previously, interconnection cost estimates were a “non-binding order-of-magnitude cost estimate,” so this plus or minus 25 percent cost envelope option is a very significant improvement. This new cost envelope is the end result of the last five years of efforts to create more cost certainty for developers seeking to interconnect to the grid. A key force for the final decision was energy division staff, including Jamie Ormond (who moved up the food chain to become Commissioner Catherine Sandoval’s legal and water advisor halfway through the proceeding’s second phase), Gabe Petlin, and Marc Monbouquette. But perhaps the biggest credit goes to Commissioner Sandoval herself for sponsoring the alternate proposed decision and spearheading efforts with the other commissioners to gain their unanimous support for the alternate decision. (Sandoval doesn’t take ex parte meetings at all, so we didn’t meet with her or her staff in that manner). Ormond was the author of the staff report that recommended that the CPUC adopt, at least in part, the cost-envelope approach after some intervenors (the Interstate Renewable Energy Council and the Clean Coalition) had recommended this approach, which emulated in some ways the Massachusetts interconnection model. The utilities had proposed a different “fixed-price option,” which would apply to a small subset of projects seeking interconnection and in many cases would apply only to the projects that needed the increased cost certainty the least. In other words, only the most straightforward and predictable projects would qualify. The cost-envelope approach would, to the contrary, apply to a larger swath of projects and, while not as certain as the utilities’ fixed-price option in terms of knowing the exact costs, provide sufficient cost certainty to make it a much-improved option to the status quo. There were also additional unjustified costs and lengthy timelines associated with the utilities’ approach that my client and others didn’t like. When the proposed decision finally arrived in early 2016, we and many other intervenors were pleased with certain parts of the decision, which adopted the consensus recommendations worked out jointly by the parties on issues like the enhanced PAR process, the unit cost guide, and behind-the-meter energy storage interconnection, but seemed to ignore the record and the staff’s own recommendations by adopting the utilities’ fixed-price option instead of the cost-envelope approach that was supported by almost all of the other parties. We and the Interstate Renewable Energy Council (IREC) were also quite concerned that the proposed decision punted on how interconnection cost overruns would be dealt with: should utility shareholders or ratepayers be on the hook for overruns? We kicked into high gear when the proposed decision came out, as did other intervenors, and we scheduled various calls and meetings with commissioners and other decision-makers. We also learned that Energy Division staff supported modifications to the proposed decision and continued to support the cost-envelope approach. So we had support both internally and externally for an alternate decision or a substantially modified proposed decision. In our advocacy, we focused on the fact that over the four years of deliberations, no party other than the utilities had supported the fixed-price option, so it was strange that the proposed decision would adopt that position. At the same time, the proposed decision overlooked much of the record, including the CPUC’s own staff report that was the official beginning of the record on the cost-certainty issue. In response to the outcry over the proposed decision, Commissioner Sandoval convened an “all-party meeting” to consider criticisms and alternative approaches. All five commissioners attended this meeting. IREC and the Clean Coalition attended and provided strong feedback about the proposed decision, but also offered constructive alternative solutions. We were very happy to hear Commissioner Sandoval’s opinions on key issues, and it was apparent that she was our most important internal ally in enacting strong interconnection reform. While we did not know the outcome ahead of time, we were pleasantly surprised when Sandoval later released an alternate proposed decision that adopted the cost-envelope approach and even went further in some ways than we and IREC had recommended. We expressed strong support in our written comments and additional ex parte meetings for the alternate decision. We were also very pleased that the utilities came around to support the alternative, in part due to ongoing discussions between the utilities, the Clean Coalition, IREC and others, about the key issues. Kudos to the utilities for being able to support a different approach and to maintain an open dialogue with intervenors on policy issues. We were again pleasantly surprised when the commission unanimously approved (5-0) the alternate decision at its June 23 meeting. The decision, sponsored by Sandoval and her staff in the portions that weren’t taken from the previous proposed decision, contains some very far-sighted statements about the need for interconnection reform in order for California to achieve its promise on renewable energy and climate mitigation. Sandoval wrote in her concurrence to the decision (a document expressing only her views and not those of the other commissioners): “Just as interconnection created competition, choice, and innovation in the telecommunications sector, and was key to the evolution and accessibility of the Internet, so too will this new California interconnection model be pivotal to our state’s ability to turn the electric grid into the backbone of our clean energy future.” Hear, hear. With this decision California, continues its pioneering leadership on energy reform and climate mitigation. The next steps in continuing this leadership will be to introduce elements of automation in order to further streamline, reduce costs, and speed up the interconnection process, using IT tools that the utilities are already developing.
News Article | March 3, 2017
Changes to net metering are on the way. Southern California Edison is now in the process of passing out NEM 1.0, initiating NEM 2.0. NEM 2.0 will have fewer solar incentives and new rate charges. Net Metering 1.0 is expected to reach its cap by July 1st, which means that homeowners considering going solar need to get their solar installed before the cap is reached to be grandfathered in on Net Metering 1.0. Co-owner of local and veteran owned Semper Solaris, John Almond, explains Net Metering this way, “Net Metering 1.0 is a list that has a cap. Once that cap is reached, you can’t be on Net Metering 1.0. The list is full. It is important to go solar before the list fills up in order to get the best incentives.” All NEM 2.0 customers are put on a TOU (Time of Use) schedule, and charged higher rates for energy usage during peak hours. This especially affects anyone who runs their air conditioning, or families who stay home for a portion of the day. Solar customers who don’t get their solar installed in time to be grandfathered in on NEM 1.0 will be credited lower amounts if their solar panel system is producing extra. NEM 2.0 also includes a new interconnection fee. As co-owner of the fastest growing solar company in California, John Almond makes solar simple for his customers. “Solar is a math problem, with an obvious answer. With current prices as low as they are, there will likely never be a better time to go solar.” Especially as Southern California Edison is nearing the cap for Net Metering 1.0, going solar sooner, rather than later, just makes sense. Customers that go solar before NEM 1.0 changes are grandfathered in, and receive the best solar incentives for 20 years. NEM 2.0 starts July 1, 2017—or once Southern California Energy reaches a cap in energy usage for NEM this year. If anyone installs solar panels before then, they are guaranteed a spot on the original NEM program plan. That means that now is an urgent time to install solar—before these new changes go into effect. Those interested in solar panels need to install as soon as possible, because SCE could certainly reach their energy cap before July 1st—and the panels need to be installed and approved before the cap is reached. The Net Metering changes also come on the heels of a new high usage fee instituted by several California electricity companies. The 2017 high usage surcharge comes after historic rate increase in 2016. With all these factors in mind, now is a better time than ever for homeowners to go solar, reduce their electricity bills, avoid rate increases, and lock in their solar incentives. For homeowners that want to install solar and guarantee their placement on the NEM 1.0 list, there are several factors to consider when choosing a solar contractor. The California Solar Initiative (CPUC) and the California Energy Commission recommend choosing a contractor that is accredited, certified, well established, and who has a strong rating with the Better Business Bureau. About Semper Solaris: Semper Solaris is a licensed solar and roofing company based out of San Diego, California. Semper Solaris is veteran owned and operated, a SunPower Elite Dealer and an Owens Corning Preferred Contractor. Semper Solaris is recognized as the fastest growing solar company in California, and were awarded the SunPower Rising Star Award and Residential National Dealer of the Year Award. Semper Solaris prides themselves on taking the time to help their customers understand how solar works and how to choose the right system. They are A+ Rated with the BBB and have 5 stars on Yelp. Semper Solaris is NABCEP and IREC certified, with over 27 years solar industry experience. For more information, visit sempersolaris.com.
News Article | November 9, 2015
What's the true, overall value of combined “behind the meter” energy storage plus solar PV deployment to U.S. power utilities and their customers? That's the big question facing stakeholders in Hawaii and other U.S. states with a need to integrate fast-growing amounts of solar and renewable energy on to power grids. A new valuation methodology set out in a report commissioned by the Interstate Renewable Energy Council (IREC) and carried out by Clean Power Research offers utilities, grid operators and regulators the means to find out. With Hawaii's electricity market providing the basis, the IREC-CPR report, “Valuation of Solar + Storage in Hawaii: A Methodology,” fills a gap in the analytic toolkit utilities have at their disposal, IREC and CPR explained in interviews. A rough analysis using the valuation methodology indicates the incremental value of adding battery storage capacity to solar PV installations in Hawaii comes in at 10 cents per kWh. Those net capacity added benefits accrue to the utility and rate payers. Costs of 7 cents per kWh, which include the costs of solar and storage losses, are paid for by utility customers who deploy these hybrid systems, CPR's Ben Norris explained. While these figures are specific to Hawaii, IREC-CPR's valuation model can be used to determine the value of solar-plus-storage installations in any state or region, he added.
News Article | December 8, 2016
11-13 September 2017. The Government of Mexico announced today that it has teamed up with REN21 – the Renewable Energy Policy Network for the 21st Century – to organise the next International Renewable Energy Conference (IREC) in Mexico from 11-13 September 2017, within the framework of the Strategic Dialogues on the Future of Energy. Dedicated exclusively to the renewable energy sector, IREC is a high-level political conference series hosted by a national government every two years and convened by REN21. Each IREC acts as a common platform for government, private sector and civil society leaders to jointly address the goal of advancing renewable energy and has provided the impetuses for several momentous initiatives over the past decade. IREC 2017 in Mexico will continue to build upon the successes and outcomes of the previous conferences held in South Africa (2015), Abu Dhabi (2013), Delhi (2010), Washington D.C (2008), Beijing (2005) and Bonn (2004). On the announcement, the Secretary of Energy of Mexico, Mr. Pedro Joaquín Coldwell, commented: “Latin America has an opportunity to showcase its rapidly growing renewable energy industry and gain from the best practice as adopted in countries at the forefront of renewable energy deployment. Mexico, after having successfully completed its energy market reform, is well placed to host such an event and we are honored to partner with REN21 in this endeavour.” Dr. Arthouros Zervos, Chair of REN21, added: “REN21 is pleased that Mexico will be the next IREC host. We are convinced that MEXIREC will further boost Latin America’s emerging renewable energy industry and provide a global platform showcasing how renewable energy sources provide a significant opportunity to improve energy security, mitigate greenhouse gas emissions, ensure sustainable development and significantly improve socio-economic development.” Further information will be available shortly at www.ren21.net/irec
News Article | October 25, 2016
Since April, IREC and partners have been busy with a project focused on bringing high quality training to code officials and the fire service. Although historically IREC has actively led credentialing and training efforts for solar and other clean energy industries, we are increasingly focused on the workforce needs of sectors “allied” with solar.